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Date			Replies
26/04/2021	Q:	We are facing lots of solid formation in the quench tower circuit of our TGT Unit. What can be the reason and how are solids/salts formed in this circuit?
17/04/2021	Q:	Possible VGO discoloration causes in a tank with nitrogen blanketing? Oxidation leads to gum formation but is it the cause? Metal content was well within range. So what could be the reason?
17/04/2021	Q:	We are having a problem with the product fractionator bottoms pump (multistage centrifugal Pump turbine driven/standby motor driven)(inlet ~330 deg C) of a MHC unit; whenever the pump is taken in service and made ready after maintenance and primed (previously used to prime from the suction valve, now try to prime with a warm-up line) the downstream fired heater (thermal cracker) trips due to low flow as soon as the suction valve is crack opened to take it in service. Any suggestions on how to rectify this issue?
10/04/2021	Q:	Which is a better option to control firing in the furnace: connected temperature controller with fuel gas controller; or connected temperature controller with low selector?
10/04/2021	Q:	In our DHDT unit (Axens licensor) one PV is given after the feed filter package to maintain a back pressure of 5kg/cm2. What is its importance? In the other DHDT unit (Haldor Topsoe) there is no PV given.	(1)
10/04/2021	Q:	During precommissioning a diesel unit why we can not start the recycle gas compressor with 100 % hydrogen before catalyst sulfiding as per the licensor: 50% nitrogen with 50% hydrogen?	(2)
05/04/2021	Q:	How does heavy slop oil processing in a coker unit affect the recycle ratio: 1.When slop oil is processed in the main fractionator? 2. When it is processed in the blowdown tower? How is the true recycle ratio calculated when slop oil is processing?
30/03/2021	Q:	One of our fired heater gas burner's riser pipes is frequently plugged with coke-like formations on the internal periphery. Since it was identified that our fuel gas sulphur content was pretty high, my best guess for the cause of black material deposits was iron sulphide. But I read somewhere that fuel gas with high olefins can also coke up inside the riser pipes. Anyone else faced similar problems in their fired heater? If so, what was the mitigative measure taken to overcome this?	(5)
24/03/2021	Q:	We have a UOP semi reg. reforming unit, working since 1975. There are no caustic solution injection points or circulation during regeneration procedures, so we want to install a caustic injection point in the upstream air cooler (inlet temp. about 200 degC and outlet temp. about 55 degC ) . Is there any reason to install an injection point 1st in the upstream air cooler and a 2nd downstream, or do we just inject caustic solution upstream only?
23/03/2021	Q:	Are internal floating roof tanks with window openings suitable for ethanol storage?
18/03/2021	Q:	Why is the resin bed height higher in a cation exchanger than in an anion exchanger in a demineralization operation?
23/02/2021	Q:	In a sponge absorber why is absorption of LPG by lean oil (naphtha) an exothermic reaction?	(2)
20/02/2021	Q:	We have 2-stage Claus with SCOT TGTU. Whenever we have a long shutdown, we keep the Claus section & TGTU section in hot stand-by mode. The Claus Reaction furnace is fuel gas firing and diverted to an incinerator (bypassing the TGTU). The TGTU section has nitrogen circulation in hot mode. The SCOT reactor temperature is maintained at operating temperature (290C). The problem: we observe that every time the quench pH drops after a few days. What would be the reason?
18/02/2021	Q:	Can anyone suggest/advise the procedure to reduce upsets during a water shot problem in the CDU during tank changeover or slop processing? Either design changes in the desalter or any equipment internals, modification etc.	(2)
10/02/2021	Q:	I am looking for long loop and short loop circulation procedures in a hydrocraker unit after sulphiding: two stages and conversion around 97%.	(1)
09/02/2021	Q:	We have a fixed bed reformer. During the last two regenerations of the catalyst, the vibrations of our recycle compressor have increased. is it possible that it is related to the fact that the catalyst has been regenerated more times than recommended by UOP?	(1)
06/02/2021	Q:	We have recently commissioned a 0.74 MMTPA RFCCU with mainly reduced crude oil (85%) and coker gas oils (10-12 %) as feed. We are getting a very high benzene content (~ 2-3%) in our light cycle naphtha (LCN), leading to problems in the finished MS pool due to a benzene limit of 1%. The downstream naphtha hydrotreater unit is only able to desulfurize the LCN with no benzene saturation. What methods will control the formation of benzene in the reactor, by either a change in feed composition or the operating parameters?	(1)
04/02/2021	Q:	What is the mechanism for mercury desorption from crude oil pipelines during emergency shutdowns upstream? Does it effect the normal mercury concentration after resuming t operations?
04/02/2021	Q:	I work in a UOP licensed DHDS unit. It has one HP amine absorber to absorb H2S from recycle gas. At thr top of the column, a water wash facility with level tray is installed to wash lean amine from recycle gas. We are experiencing foaming. The water tray level quickly fills and goes to the next recycle gas knockout drum. Delta pressure of the column is also increasing and the level increases suddenly in the water tray even after isolating fresh water. The delta temperature between amine and process gas is 12oC. Drained liquid is milky in colour. Please suggest a remedy.	(3)
29/01/2021	Q:	This is about a LPG Merox unit in our refinery. Since the content of RSH(mercaptan) in the feedstock has more than doubled, this makes it difficult to regenerate the caustic. The content of mercaptide and disulphide in regenerated caustic has greatly increased. Frequent replacement of caustic and increased air flow and temperature in the oxidizer doesn't solve the problem. How can we solve the problem if we can not change the feedstock?	(4)
26/01/2021	Q:	Does high water and salts in crude oil feed cause high gum in kerosene oil?
23/01/2021	Q:	I work in a hydrocracker unit and the fractionator separated products into UCO, Diesel, Jet A1 and heavy naphtha. At the same time I am working on another hydrocracker but the fractionator is separating UCO, light diesel, heavy diesel and kerosene . What's the difference between them if we are using the same feed?
12/01/2021	Q:	What is the mechanism of mercury desorption from crude oil pipelines during emergency shutdowns upstream? Does it effect the normal mercury concentration after resuming the operation?
10/01/2021	Q:	For an atmospheric distillation column designed for natural gas condensate as a raw material: 1. If HCL is found in thr boot water then what type of chemical dosing can be injected? Without injecting any wash water the pH remains 5.5 but when we inject water the pH reduces a little but remains within 5-5.3. Nonetheless, the corrosion is taking place without and with injection of wash water at the overhead line. 2. If boot water contains H2S then what chemical dosing should be used and what will be the injection point? 3. If pH depression is due to CO2 or organic acids then what should be the chemical dosing and what will be the injection point? 4. If there is iron in boot water then what should be the chemical dosing and injection point?	(1)
02/01/2021	Q:	When RGC speed is increased in a DHDT unit then how does recycle gas flow increase even if the total high pressure (HP) loop is a closed loop? Does the recycle gas velocity increase, or the travelling time of recycle gas decrease, due to increased pressure difference in the RGC suction and the discharge pressure?	(1)
25/12/2020	Q:	What should be the maintenance and inspection schedule for underground storage tanks for petroleum.	(1)
25/12/2020	Q:	How to handle ethanol above ground storage tank drainage?	(1)
14/12/2020	Q:	Why is there a need to use an air cooler in the overhead circuit of a distillation column? What's so special about it that a water based condenser cannot do it standalone?	(3)
14/12/2020	Q:	Here are a few points regarding the desalter issue in our refinery: 1. There are two desalter trains installed in parallel. 2. When the desalter current fluctuates, the brine water coming out of the desalter has an opaque black colour. 3. The events occur only at one train. In this case, the rest of the trains are fine with the same crude. 4. The events tend to occur at crude switch or introduction of slop oil, but this is uncertain. What are the possible causes? Please advise what we should investigate and analyze to clarify the causes.	(4)
13/12/2020	Q:	In our DHDS plant (Axens licensor, revamped in January 2018 ) with both a hot high pressure separator and cold high pressure separator, we are facing several tube leaks(A179-CS tubes ) in our stripper feed/stripper bottom exchangers (life three years).Corrosion is mainly on the stripper feed side and corrosion is due to localised under-deposit corrosion on the OD side of tubes near the floating head tubesheet, probably due to carry over of water and salts from upstream separators. Our hot separator is operating at 40 ksc and 90 degC operating temperature against the design 100 degC. In the same plant we are facing severe choking issues in our stripper overhead fin fan coolers where a complete header box was found choked with deposits. Around 76 % of the foulant collected is iron, and ammonia is also present. Has anyone faced such issues? Is operating the hot seperator at lower temperature the cause ? Has anyone used Alloy 825 tubes for stripper feed /stripper bottom exchangers?	(7)
23/11/2020	Q:	Our company has two serial desalters. Wash water at pH 7-7.5 level is injected, and brine of pH 6 is released. Not long ago, Brazilian crude(Lula) was mixed at about 30 percent, and the pH dropped to 4.5. The TAN value of Lula is low at 0.3 level. I cut naphtha and checked for organic acids, but this isn't a particularly large amount. Our chemical vendor gave the opinion that this was because there were a lot of salts crystallized in the crude oil. However, even after analyzing metal and ash, there was not much. We need to analyze the cause; does someone have similar experience?	(4)
06/11/2020	Q:	Can we route stripped sour water to a cooling water circuit?	(5)
31/10/2020	Q:	Is there a practical solution for converting HPS to BFW? for some reason, we can only access HPS while we need BFW for temperature control in the steam reformer.	(1)
25/10/2020	Q:	In my petroleum refinery, two new diesel hydrotreating units are licensed to Haldor Topsoe. These two units are in the pre-commissioning phase of the project life cycle. My question is about hydrogen quench control valve failure status. In all of these valves, the characteristic of failure to close was considered. Based on my experience, the hydrogen quench valve failure status is failure to open. Would you please let me know the reason for this scenario for hydrogen quench valves?	(1)
24/10/2020	Q:	1.What is the expected heat loss ( drop in temperature) from the main fractionator bottom to the furnace inlet in coker unit with some recycle? 2.How does the Cp value of the bottom stream of MFC change when the recycle ratio changes?	(1)
22/10/2020	Q:	We are developing a project of a coker gas scrubbing tower with water circulation. What are the characteristics of this circulating water stream (for example, ammonia, carbon dioxide, HCN and pH)?
19/10/2020	Q:	Why aren't the draw off temperatures close to the IBP, FBP of the products? For example, the draw temperature of kerosene is 193degC where as the lab results suggest 140degC IBP and 240degC FBP.	(1)
14/10/2020	Q:	In a Hydrocracking reactor, the degree of cracking is maximum in which bed? In the first bed, the extent of reaction (exotherm) is higher but lower bed (third bed) temperature is highest. Also since the most complex molecules like disubstituted DBT will be reacted in the lowest bed, will cracking be maximum there?	(1)
13/10/2020	Q:	Which technology and equipment is used for carbon capture, utilization and storage (CCUS) from flue gases from a power plant?
13/10/2020	Q:	Which is the best technology (CPOX /SMR/PX/ATR/CR) for producing clean syngas from refinery off gas and PSA tail gas in terms of capex and opex ?
13/10/2020	Q:	We experienced an aromatics leak to the cooling water system one month ago. When we routed the contaminated water to our waste water treatment, it didn’t show any significant change. However, recently we experienced low F/M in our aeration basin. Is it normal to have this delayed response of about 30 days after introducing aromatics contaminated water to the waste water treatment plant?	(4)
12/10/2020	Q:	What are the approximate costs of utilities like HP steam, MP steam, fuel gas, DM water, plant air, and instrument air for calculating the operating cost of any plant?	(2)
12/10/2020	Q:	In two stage hydrocracker units, as the catalyst ages the HPNA at the second stage feed increases and gets heavier. Is this going to cause a catastrophic blockage on the second stage CFEs or fractionator bottom network heat exchangers?	(4)
07/10/2020	Q:	Is there any commercial plant for producing clean syngas from refinery off gases (the tail gas from CRU units having no CO content)?	(3)
04/10/2020	Q:	In an energy conservation programme I'm focusing on steam calculation starting from the reboiler and the distribution lines in the refinery. Could you please tell me the first step to do this calculation, whether anyone has a relevant book or article, and can I use Hysys software?	(1)
04/10/2020	Q:	What is the typical discount rate in an oil refinery feasibility study to get an optimum result for NPV?	(3)
29/09/2020	Q:	What are good practices to hand over sour water feed storage tanks in refineries?
28/09/2020	Q:	How do I identify if a reboiler has gassed up?	(1)
27/09/2020	Q:	How do I identify if a distillation column is gassed up - for eg a naphtha stabilizer?
20/09/2020	Q:	We use semi-catalytic reforming to produce gasoline with LPG as a byproduct. Our problem is the LPG copper strip corrosion test reads 4b as a mean high. Any recommendations to decrease this value to 1a or 1?	(3)
19/09/2020	Q:	We are operating an aromatic recovery unit producing benzene and toluene. The extraction section uses Sulfolane as solvent. The extract is stored in a charge day tank and is used for charging the benzene column. To remove olefins from the feed, there is a clay tower prior to the benzene column that operates at at inlet temp of 170 deg C and a pressure of 13 kg/cm2. There is an exchanger for heating the clay tower feed (tube side). We are observing a frequent issue of plugging in this exchanger. This leads us to shut down the fractionation section for almost a day every five months for cleaning/replacing the tube bundle. The olefin content in the light reformate feed varies between 5% and 7%. Is there any way this issue can be resolved? Is the olefinic content in the feed too high? The plugging material seems black in colour. Is there any method that can be used for identifying the fouling type? Is is it due to polymerisation of olefins? Any solution to avoid such frequent plugging in this exchanger?	(10)
09/09/2020	Q:	During precommissioning of our DHDT unit we want to pressurise the system with nitrogen by makeup gas compressor up to 50kg/cm2g. Can we increase pressure without achieving the minimum pressurisation temperature?	(3)
09/09/2020	Q:	We have a sour fuel gas amine absorber where sour fuel gas from the refinery is treated with amine from the amine unit to strip out H2S. Sweet FG from the outlet of the absorber passes through a cooler then a filter coalescer to separate carryover amine from fuel gas. We are continuously getting water from the filter coalescer instead of amine. We have checked the cooler for tube leakage but no leak is observed, also the pressure of the fuel gas side is 0.5 - 1kg/cm2 higher than the cooling water. After checking the strength of a coalescer boot sample, almost 99% water is found. Is this a normal outcome or what are the probable causes of water formation instead of carryover amine?	(5)
08/09/2020	Q:	We have a reboiler whose shell was uninsulated. After insulation, I want to calculate the energy saved (heat saved). Temperature on the reboiler shell surface is ~155oC; on the insulation it is 40oC. Glass wool insulation is installed.	(1)
03/09/2020	Q:	In our Vacuum gas oil fractionation column, we have a diesel draw chimney tray. It doesn't have any overflow lines; the pumparound and internal reflux to the bottom trays of the chimney are provided by diesel draw pumps. I just want to know, if both our pumps had issues and stopped, how does liquid from the chimney tray reach down? Even though the liquid level reaches the chimney tray vapour ports, the liquid can't reach below the chimney tray through the vapour ports as the pressure of vapour flowing through the chimney tray vapour ports is more than the liquid pressure. Am I right? If the liquid can't travel down the chimney tray, the bottom trays becomes dry as the liquid flow from the chimney tray is stopped. In such cases, what could happen to the fractionation column top and bottom sections?	(2)
01/09/2020	Q:	Could you please share your experiences and strategy regarding reprocessing light coker slop? I am interested in a dosing strategy when the tank for light coker slop should be filled by off-spec products during DCU unit start-up only or in case of upsets in the DCU unit; during normal DCU operation light slop should be sent back for reprocessing on the DCU and the tank will be empty till the next shut down. Do you perform some laboratory analyses to optimize the dosage rate of polymerization additive into the light slop?
30/08/2020	Q:	Is the UOP qualified vendor list for different process units such as NHT, DHT, ISOM, FB Platformer, CCR, FCC and Uniflex publicly available?	(1)
30/08/2020	Q:	Can we produce blown bitumen from vacuum residue of hydrotreated AR? What are the parameters to be checked?	(1)
25/08/2020	Q:	I work on a vacuum gas oil hydrotreater(Axens licensed) unit. We have a water injection system at the upstream of AK-001 to absorb the ammonium salts, along with water injection. We also add hydrocarbon drawn from a cold LP separator at the upstream of AK-001. I just want to know the purpose of hydrocarbon washing? What happens if hydrocarbon washing is not implemented? We don't have a hydrocarbon washing system in the diesel hydrotreater unit.	(3)
15/08/2020	Q:	Why is the reduction furnace in the SRU so called? Although the reaction chemistry indicates that NH3 is oxidized to N2 what is the reason behind the nomenclature "reduction furnace"?
15/08/2020	Q:	Can amines cause crude column overhead corrosion ? Also the organic acids generated during processing of crude oil, can they be trapped by amines? Kindly suggest your views.	(3)
15/08/2020	Q:	During processing of high TAN crude oils in a crude distillation unit generation of organic acids can occur. At what minimum value of TAN can these organic acids be generated during processing? Is there any rule of thumb for this ?	(3)
12/08/2020	Q:	We had serious corrosion issues in the amine regeneration column of the TGTU. We also measured significant HSS levels in the amine solution. We are about to replace the quench tower in our TGTU, upstream of the amine absorber. We are considering installing a demister in the overhead of the quench column, to increase the system’s capability to avoid SO2 entrainment in the amine system. We assume that the cons for doing this step are increased pressure drop and risk of sulphur deposits in the demister. Is it a common practice to install a demister in the TGTU quench tower overhead? Does somebody have experience of doing this? Any known issues with this demister?
10/08/2020	Q:	For a crude distillation unit, what should be the top temperature of the column, draw off temperatures for naphtha, kerosene and diesel, and the bottom temperature of the column?	(2)
07/08/2020	Q:	What are the main impacts, advantages and disadvantages of co-processing coker naphthas in diesel hydrotreating units and VGO hydrotreating units? According to operating conditions, catalyst activity, feed properties, LHSV, residence time, vaporization in the reactors, which the preferred way to co-process coker naphthas - DHT or VGOHT?	(2)
04/08/2020	Q:	What is the impact on the coking unit of an increase in quench to the drum?	(1)
30/07/2020	Q:	In our hydrogen generation unit, a waste heat boiler functions to recover reformer O/L heat to produce HP steam. Boiler is single pass shell and tube exchanger with fixed tube. Since last year the boiler is not able to recover heat upto expectation as indicated by the raised process gas O/L temperature. The process gas O/L temperature is now around 288oC instead of 265 oC earlier. In the last 2 shutdowns the tubes have been cleaned thoroughly from inside but no benefit observed. Now it is suspected that there is fouling (maybe of silica) on the shell side. There is no provision to open and clean the shell side assembly. Is there is any technology available for online removal of such fouling (maybe some kind of chemical cleaning)?	(1)
28/07/2020	Q:	What is the reason for sulphur pit overpressure? A few days ago the sulphur plant’s sulphur pit temperature suddenly reached 190°C+. Its normal temperature is around 140°C. 1)iIs this because of a small fire in the sulpgur pit, or any other reason? 2) Sweep air with moisture or sweep air without moisture - any effect on sulphur pit pressure?	(1)
25/07/2020	Q:	Why is furnace oil for burners blended with diesel?	(3)
22/07/2020	Q:	As a DCS Operator, what parametric and/or qualitative changes suggest the following problems? Flooding, dumping, jet flooding, entrainment, weeping and foaming.	(1)
21/07/2020	Q:	What thing(s) indicate the need to increase CDU stripping steam?	(2)
20/07/2020	Q:	Our desalter unit is working fine, the crude oil outlet to the CDU is "clean", there is no water and low metals content. However, there is an issue with the outlet water. When the desalter is "washing" low sulphur content crude oil the water has a huge content of oil in water, grams per liter, and what looks like asphaltenes on the interface. When running high sulphur crude this issue doesn't occur. We did some lab tests; strangely we can not get the same outcome as what happens in the desalter. The water is clean and there are no issues on the water interface. Does anyone know what might be the issue?	(1)
19/07/2020	Q:	We are facing a problem in crude/condensate decanting which is received from local fields. Settling time for the oil tankers is one hour; after this a dip is taken, water observed in the dip is nil. Then we decant the tankers into our crude oil tanks. After settling time for the tanks we are observing raised water level. What can be the potential causes?	(7)
19/07/2020	Q:	Our recycle gas compressor is giving higher flow than it is designed for at the same loading. What can be the reasons?	(3)
19/07/2020	Q:	How effective is hydrogen in stripping H2S from hydrotreated naphtha?	(6)
09/07/2020	Q:	Pumparound flows through a preheat exchanger and after that passes through a control valve and back into the column. While deciding how much pump should be used, what should we consider? Condition #1: Reduce the control valve opening, provide the pumparound more residence time inside the exchanger which will cool it down more and then it will return at a lower temperature but with a lower flow rate. Condition #2: Increase the control valve opening which will allow more flow to be fed back into the column but with a relatively higher temperature. Which one should we choose?	(3)
06/07/2020	Q:	Our catalytic reforming unit is running at 500°C . A short length flame and smoke was seen at the heater outlet flange; we have a steam ring which we have used to extinguish the fire. Now my query about hot bolting: is it safe to tighten the bolt at 500°C to stop the leak? If not then what should be the maximum temperature and safe procedure for hot bolting?	(3)
05/07/2020	Q:	Our crude fired heater is having trouble with positive draft. The heater is the balanced type. Our initial suspicion was fouling/leaks inside the air preheater. But when the ID fan was stopped, the draft inside the furnace increased even further. Chemical cleaning of the heater radiation zone was performed. The convection bank manway was opened and inspected. No significant clogging was observed during the inspection. Any clues as to what could be the possible reason for this?	(4)
02/07/2020	Q:	In our catalytic reforming unit, DM water and CCl4 are used as dosing to keep the water and chloride balance within the prescribed limit. Material of both injection lines is stainless steel 304 whereas the main line of the feed (DSN) is carbon steel as per design. Line pressure and temperature of feed line are 24 kg/cm2 and 151deg C and both injection points are connected to the feed line. From a corrosion point of view, if i replace the injection line of DM water & CCl4 with carbon steel pipe will there be any problem ? If no then please give me the reason for using SS 304, or what type corrosion can take place in the injection line for DM water and CCl4?. Currently we are facing some leakage at the elbow weld joint. In addition, when we tried to repair by welding, again a leak/fissure was found just ahead of the welded point.	(2)
28/06/2020	Q:	The refinery I work in has a 40 year old hydrotreating reactor with a very high design minimum pressurization temperature (MPT) of 120degC. it always takes ages to clear the MPT before we can proceed to the next step in the unit startup. We run our 2x recycle gas compressors which are fixed volume reciprocating compressors, loaded to 200%. The question I would like to ask is: is it better to have higher purity H2 for heating up? Higher H2 purity would mean less mass flow at constant volume. However, H2 thermal conductivity is way higher than other gases such as N2 or CH4, C2H6. The other school of thought is to bring in less pure H2 source to boost the mass circulation. This is probably a heat transfer question also. Would like to hear if anyone has done any research on this.	(3)
27/06/2020	Q:	We have been facing issues in one of our sour water stripping units wherein we observe continuous plugging of the feed control valve to the stripper column with greenish black hard deposits. The temperature of sour water passing through this control valve is in the range 146-152 deg C. Could anyone suggest the testing we should carry out to understand this heavy deposit? Does anyone have experience with hard greenish black deposits in their sour water stripping units?	(5)
26/06/2020	Q:	In a multi-bed filter why is the larger particle size bed placed over the smaller particle size bed?	(1)
26/06/2020	Q:	During jet fuel manufacturing, conductivity improver and stability improver additives are added . During critical periods, the fuel requires prolonged storage times, around six to nine months. After this prolonged storage , does the fuel lose its stability? If so. why? Can the additives doped during manufacturing contribute to the instability of the fuel ?	(1)
25/06/2020	Q:	I am currently working on designing a flue gas system for a Fluid Catalytic Cracking unit on the regenerator side. The typical set-up is regen effluent flue gas comes out of the regenerator at 1300F. It passes through the Waste Heat Boiler, generating 600 psig (high pressure steam) by recovering heat from the effluent flue gas. The flue gas then passes through a series of pressure let down devices (double disc slide valve, followed by an orifice chamber (bunch of orifice plates lined in a duct)), before going through the wet gas scrubber (caustic wash for any catalyst carryover) into the stack and vent to the atmosphere. Normally the slide valve (one of the pressure let down devices) is used to control regenerator pressure. This valve is also designed with a minimum cut out and/or a mechanical stop, that prevents the slide valve from going completely closed, the reason being this serves as a path of relief in case the slide valve goes slam shut, causing a source of overpressure on the regenerator. In this case the regenerator is designed for 38 psig. One of the scenarios to be considered, credible under the current setup, is if the tube in the WHB ruptures, high pressure BFW on the shell side of the WHB can pass through the tube (process gas side), which is open to the regenerator and creates an overpressure. As mentioned above the minimum opening in the slide valve, through the orifice chamber, through the wet gas scrubber, will be a relieving path for this fluid. Question: I am trying to calculate the amount of relief that will be generated through the tube. Since BFW on the shell side is at saturated conditions, there will be flashing (two-phase flow) passing through the tube. As the relieving flow exits the tube, it should be under sonic conditions (choked flow). I need to determine how much flashing will occur across the tube as it exits the tube, and secondly the amount of flow that will exit the end of the tube (probably a two-phase restriction orifice calculation needs to be performed) to determine the flow. I would greatly appreciate if someone can guide me as to how to perform this calculation as I have not done much two-phase through tube (at sonic conditions) and two-phase RO calculation.	(2)
25/06/2020	Q:	What is the basis for choosing a pressure controller instead of a temperature controller for steam heating?	(1)
25/06/2020	Q:	What is the difference between unimodal and bimodal polymer?
21/06/2020	Q:	What are the effects of excess recycle gas flow with high purity at 95+ vol% on a hydrotreater unit? It's good for the catalyst but what are its effects on the process, especially on the furnace?	(1)
21/06/2020	Q:	In a hydroprocessing Unit, what factors determine location for adding washwater? I have seen two locations in my unit - one upstream of the air fin fan and one at the inlet of the last CFE. Where should I inject wash water?	(5)
16/06/2020	Q:	1) What are the standard procedures to dispose of the catalyst dust (from regenerated and spent catalyst) from a CCR Platforming unit ? 2)Are there any adverse effects on the environment due to random disposal of the catalyst dust? 3) Is there any process to extract precious metal from the catalyst waste?	(3)
10/06/2020	Q:	i'm working in a LAB plant. For dehydrogenation of paraffins there are 2 standby reactors. After deactivation of the catalyst (about 45 days) we changed to another one. Now we want to use both reactors at the same time in parallel. We increased the paraffin flow rate from 50 t/hr to 60 t/h. The hydrogen flow rate also increased from 10 t/h to 11.5 t/h according to our equipments capacity. I think it'll raise our conversion and increase the catalyst lifetime. Is this possible?	(2)
10/06/2020	Q:	I found that makeup gas fed to NHT from CCR contains 200 ppm of propylene and ethylene. Would this contaminant cause coke and gum formation at the NHT reactor?
07/06/2020	Q:	in a SRU final condenser demister pad, dislocations occurred two times recently. Due to this the tail gas line to the TGTU filled with sulphur. What may be the reasons and remedies? Also, in case of carryover of sulphur what ways are there for early removal of sulphur.	(3)
05/06/2020	Q:	Will the pH of phenol in an aqueous phase (no hydrocarbon) affect how well phenol is decomposed through mixing with air? If it does, is the decomposition more advantageous at a lower or higher pH?
27/05/2020	Q:	Hi, I am working in optimizing the fuel gas for our fired heater, so can anyone help me in providing the fired heater efficiency calculation in Excel format. Your support will be much appreciated. Also, any calculation available to help us to assess the heater performance will be very helpful. Your prompt response will be highly appreciated!	(4)
26/05/2020	Q:	In our regenerative caustic treatment system a disulfide stream is generated. Which is the best destination for this stream in the refinery (FCC, coke drum, hydrotreater, naphtha feed, others)?	(4)
25/05/2020	Q:	In HPCL Vizag Refinery the SRU plant was commissioned in 2009 with the plant designed by M/s KTI italy. The Thermal Reactor Burner Design was provided by AirOil. It is a Lance in Lance type with manual insertion and retraction . The problem we are facing is with the short life of the AAG Diffuser, frequent plugging of the FG tip, and frequent damage to the FG tip resulting in difficult insertion and retraction. The FG gun is provided with a N2 cooling system to keep the tip clear and for cooling when the train is in AAG mode; it is ensured all the time that N2 is continuously fed to the FG gun. Even after this we are facing the above problems. Can anyone can throw some light on the following: 1) Why is the AAG diffuser life short even though we are operating the train well within design feeds. 2) Why is the FG gun tip i plugged even though N2 flow is continuous and the FG to gun is provided with a strainer to provide good quality FG. 3)Why is the FG gun tip getting damaged resulting in difficult insertion and retraction 4)Are any new advanced burner designs available which can overcome these problems 5)Are there have any best operating procedures / troubleshooting reports to avoid these problem	(1)
22/05/2020	Q:	How much do liquid product yields decrease and how much is the hardness of the coal affected by lowering the temperature leaving the furnace?	(5)
19/05/2020	Q:	I would like to know the configuration of an amine system for refineries having multiple hydroprocessing units with multiple ARU / SRU. Are common lean amine and common rich amine pipelines connecting all units, or is each hydroprocessing unit independently assigned to an exclusive ARU / SRU unit (with rich amine and lean amine pipelines running between these two units, oor is one hydroprocessing unit i connected to two ARU / SRU units for flexibility in operation? Kindly share your views stating the pros and cons of each configuration. You may share specific experience from your own refinery on the reliability of units having any one of the above.	(4)
16/05/2020	Q:	What are the causes behind the reformer outlet temperature dropping without any changes on the DCS? A few causes may be: 1.Burner fuel firing CV malfunction 2. Steam flow increased 3.Combustion air flow increased. Any other causes of a drop in the reformer outlet temperature?	(1)
15/05/2020	Q:	We are experiencing seal failures in a heavy naphtha pump (topmost side draw product of the atmospheric crude column) due to blackish muck-like material. the pump suction strainer has been found to be damaged as well. Heavy naphtha draw-off is from the 9th tray from the top. Could it be due to formation of iron sulphides and corrosion of the top tray elements? Anyone else faced similar issues?	(4)
11/05/2020	Q:	In a CCR Platforming Unit, why is the PERC injected in the regenerator but not directly in the PF Feed? While regeneration is off, is PERC directly injected into the PF feed?	(2)
11/05/2020	Q:	What is the accelerated deactivation procedure for a gas oil hydrotreating catalyst in a pilot plant?
08/05/2020	Q:	How can I detect my reboiler leak from Column parameters? I have observed no pressure fluctuations during the leak. Why did the column pressure not increase to steam pressure?	(1)
07/05/2020	Q:	How can we separate xylene (O, P and M) at 99% purity from reformate which is intended for making MS product. Can it be done through distillation or does it require an extraction process in the aromatic solvent unit? What is the process called? Is there anywhere in India it is being done?	(4)
06/05/2020	Q:	We have an operating issue in our LPG sweetening process; the level between LPG and amine interface is highly unstable (big fluctuation). We've checked the functionality of the meter (flow; level; pressure; temperature..etc) which is fine, but observed an abnormal phenomenon - rich amine is "boiling", a certain amount of LPG is dissolved in the rich amine solvent, the pressure and flash gas rate from the RA flash drum is relative high. Question: a couple days ago we treated with a high dose of antifoam additive to cure the foaming problem in another unit, and the LPG sweetening unit is using the same source of amine solvent (containing excess antifoam additive). Is it possible that excess antifoam led to enhanced LPG solubility?	(2)
06/05/2020	Q:	We are facing an issue of LPG product off spec due to total sulfur being high. We have an amine treating unit followed by caustic treatment with CFC technology (EIL). Since the caustic regeneration system is not working frequently, caustic dumping and fresh caustic (25 Be) charging is being done. While the CFC unit is designed for RSH 4500 ppm and 100 ppm H2S, actual numbers are H2S NIL and RSH 1350 ppm in LPG. The following activities have been done so far: a) Line up checked for mixing feed and product to rule out short circuiting b) Caustic strength reconfirmed and dumping / charging increased c) Circulating caustic flow has been maximized and presently it is ~19.5 m3/hr. d) Caustic levels in contactors have been increased to 70% to increase residence time. e) Feed to CFC was reduced from 58 to 50 m3/hr. Questions: 1. Is there anything which we are missing? 2. Is there any impact of Erha crude which we are processing in the CDUs? 3. What is the experience of troubleshooting in other Refineries?	(5)
01/05/2020	Q:	I have a problem with my sour stripper column Feed : NH3 = 796 ppm H2S = 324 ppm pH = 8,7 Product (Sour Water Stripped) NH3 = 136 ppm vs max 50 ppm H2S = 5 ppm vs max 10 ppm pH = 5,8 Why does the pH of sour water stripped (product) decrease significantly with the NH3 content still high? What happens with this process? I have added to the ratio of the reboiler but NH3 still is high. And now, my temperature reboiler sour water stripper cannot increase (indicating fouling). Anyone help me?	(1)
29/04/2020	Q:	In our company we plan to create a large-scale hydrotreating pilot plant for catalyst testing. Our purpose in creating the pilot plant is treating various hydrocarbon feeds including naphtha, kerosene and diesel with 500 - 2500 ppm of sulfur. This setup will be used for catalyst testing and process design at higher capacity. Our intended set-up should have a reactor with 15-20 liters for the catalytic bed and could operate at pressures above 250 bar and temperatures above 650 C. For catalytic reactor design, L/D ratio is an important parameter and various considerations and limitations for the industrial scale found in texts can be used for estimation of this parameter. For the pilot scale many of these conditions can't be used. Are there any documents or references at pilot scale?	(2)
27/04/2020	Q:	What is the impact of chlorides on hydrotreating catalyst and unit?	(5)
17/04/2020	Q:	Is there any way of online cleaning a CCR regenerator without opening it?	(1)
14/04/2020	Q:	We have been using R-85.6 reformer catalyst. Recently we received a suggestion to use new catalyst R-88. What is the difference in efficiency and resistance to the sulphur content of heavy naphtha? We don't use a naphtha HD unit.	(1)
12/04/2020	Q:	What is cold, warm and hot circulation in a refinery and why are each of them important?
09/04/2020	Q:	In our diesel hydrotreating unit, we treat a mix of LVGO, LCGO, and CDU Gasoil. what is the optimum cut off temperature for this feed and why? Normally we cut off the feed at 260C. Right or not? Also we have a NHT unit; we cut off the feed also at 240-260C. Why?	(2)
05/04/2020	Q:	After a UOP hydrotreating catalyst changeover an issue was observed in the product colour which became 15 instead of 30 while no particulates were present. I am seeking any explanation and solution.	(5)
31/03/2020	Q:	We plan to dismantle a tetraethyl lead additive station and removal of tetraethyl lead is necessary prior to dismantling. Could you advise how this should be undertaken?	(2)
29/03/2020	Q:	We know kero is blended as a pour point depressant in diesel in tanks, however will more kero in diesel by reduced stripping itself also affect the pour point in product diesel, considering flash point is not lowered too much?	(4)
22/03/2020	Q:	What are the reasons for a drop in DP of a spent catalyst slide valve in a FCCU?	(5)
21/03/2020	Q:	Our secondary water consumption in our petrochemical plant is higher than design so is there any technology that can help us to reduce secondary water consumption for the centrifugal pump without revamping our secondary water system?
19/03/2020	Q:	What are the best practices to check leaks from flanges? As soap solution is commonly used, what are the specifications of the soap? Any specific brand?	(1)
15/03/2020	Q:	Why is the flash point of fuels lower than Initial Boiling points?	(2)
15/03/2020	Q:	We are operating a Naphtha Hydrotreater with two reactors. The first reactor is for diolefin saturation. We are facing high DP issues in the 2nd reactor. What could be the cause?	(2)
09/03/2020	Q:	In our CDU we have been observing very high SOx values. This is coupled with high chlorides and low pH. What are the possible sources of SOx (SO4) and causes?	(1)
05/03/2020	Q:	I am working on a process for aviation fuel and gasoline production from biomass gasification via Fischer-Tropsch synthesis using cobalt based catalyst. I would like some insights on how to convert the Fischer-Tropsch wax (C5-C40 both paraffins and olefins) to Aviation fuel and Gasoline. Do we need to use both hydrotreating and hydrocracking? Will it be different compared to gas-oil hydrotreating?	(3)
04/03/2020	Q:	Could any one tell me what is the cost of refining a barrel of crude oil or how can i predict it for typical refineries ,as well as the forecast ,thank you in advance	(4)
03/03/2020	Q:	We have two boilers working in paralel. However, due to high steam generation from the waste heat boiler in CCR unit (about 25%) being higher than design, both boilers are maintained operating at about 50% capacity of design. Still steam generation is higher than our requirements. We are maintaining both boilers running due to reliability concerns as stopping one boiler will lead to a delay in startup in case of emergency? So could you please share if you have similar experiences and is there any hot stand-by procedure for boilers or any procedure that can help us to immediately startup a boiler in case of a running boiler trip as now there are huge losses of energy due to unused steam venting and condensing.	(3)
26/02/2020	Q:	Start up procedure of a topping oil refinery?	(1)
26/02/2020	Q:	CDU overhead :Stability of filming amine at high pH? What is the pH range at which the film formed by filming amine remains stable? The naturally occurring Fes loses its stability at pH above ~ 7.5. Is there a similar range for stability of film formed by filming amine as well. Thanks	(4)
22/02/2020	Q:	In the isomerisation of light naphtha, how often dp you regenerate or replace the catalysts (Pt/chlorinated alumina, Pt/zeolite and Pt/sulfated-zirconia) in the reactor and the adsorbent (Zeolite Beta) in pressure swing adsorption?	(1)
19/02/2020	Q:	In our refinery we have 2 atmospheric crude distillation units: Unit 1 Fired heater stack reads 550C Unit 2 Fired heater stack reads 440C Can I know what is the accepted range ?	(4)
19/02/2020	Q:	In our refinery CDU we injected corrosion inhibitor (filming) mixed with Heavy Naphtha in one tank then we injected air (for mixing). My boss suggests injecting superheated steam instead of air because air contains oxygen that causes corrosion. Is this right or no?	(5)
19/02/2020	Q:	Hi, We are going to install a Kerosene Hydrotreater Unit. Is it required to fit connection strips in the Aviation Turbine Fuel lines flanges starting from downstream of reactor?	(2)
18/02/2020	Q:	A boiler to produce low pressure steam • Boiler has a rudimentary design. • Total volume is 1 m3 . • Check valve, pressure and level indicators are present. The check valve opens when the required pressure is achieved. It can also be manually operated. • Mode of operation of boiler is unchanged- Half of the boiler volume filled with water, then fired. Steam builds up to the required pressure. When the required pressure is achieved, check valve opens letting out steam. Once steam generation begins, level of the water in boiler is maintained and continuous operation is achieved. • A flow measuring device is installed upstream to measure steam flow rate. • The start-up requires 352 seconds. • Due to severe clogging, boiler is swapped with a temporary one. The new boiler is double the size of the previous one. The heat input rate and the check valve characteristics remain unchanged. • 400 seconds after firing the new boiler, it is observed that the pressure indicator is faulty. The level in the tank has shown little deviation and the check valve has not opened. • What would be the most safe and efficient course of action? The boiler has emergency PRV, and is functioning at one fourth of the pressure it is built to handle, and the maintenance of the clogged boiler will take 6 hours. If the issue with the pressure indicator was diagnosed 1200 seconds after firing, with the check valve still being closed, would your course of action have deviated from the previous one? If so, how?	(1)
18/02/2020	Q:	A refinery column that operates at 1.5kg/cm2g pressure. • The management decided to reduce the column pressure to 0.5kg/cm2g slowly within 15 days – this saves a lot of money and improves distillation efficiency. • Financial statement shows there will be substantial increment in profit due to this. • At first, 1 air fin exchanger leaked, the operators isolated it. • Within one day, one more leaked, again it was isolated. • All exchangers leaked within 2 days explain what went wrong here, and to suggest a way to tackle this issue.	(8)
15/02/2020	Q:	Why are most coker furnaces box type with horizontal tubes? Coker furnace heat duty is comparatively lower than a crude heater's, still they are horizontal ones. We have 9 heaters in our refinery for a coker with all of them as horizontal types. Any ideas on selection criteria ?	(3)
14/02/2020	Q:	Are there any correlations available to estimate the incipient cracking temperature for Vacuum Gas Oil? This is for designing a VGO Processing Plant.
05/02/2020	Q:	Hello, In a CDU/VDU unit a Desalter is provided downstream of the crude charge pump. What should be the design pressure of this vessel? Should it be crude charge pump-shutoff pressure or should it have a maximum operating pressure of vessel + 2 kg/cm2g, similar to the design pressure of the other pressure vessel? It may be noted that this vessel is protected with a PSV. The conservative approach is to design this vessel for pump shut-off however this will lead downstream piping and equipment to be higher class which has cost impact. Please suggest what is the practical approach and why?	(2)
30/01/2020	Q:	Our topping refinery's fuel gas line to vertical demister knockout drum system got choked and corroded. Our feed doesn't contain any sulfur. What might be the problem?	(2)
30/01/2020	Q:	What is Process Safety Time? At what stage is it is decided?
20/01/2020	Q:	Hi We have a design of a Vacuum unit where a slop wax line is going to slop wax pump. This line has a vertical leg of 35 ft the line is 6 inch but this vertical leg is 8 inch; the vertical leg has a level control which controls the recyle of slop wax is someone familiar with this scheme; what is the logic/theory behind this?	(4)
18/01/2020	Q:	I work in a Diesel Hydrotreater Unit. Currently the Naphtha Stabilizer of our unit has a suspected choking problem in the overhead line. The stabilizer top pressure (design value- 7.5 kg/cm2) suddenly increases, top temperature drops and reboiler outlet temperature starts dropping to low value. This happens especially at night or in very cold conditions. To re-establish reboiling the stabilizer column is drained (both rundown and reboiler side) then after raising level in column reboiling is established again as usual. The column overhead line has no tracing steam, so we have kept an external steam lancer to keep naphtha in vapor phase.	(4)
17/01/2020	Q:	How can the effect of temperature increase in steam methane reforming over the catalyst lifetime be calculated?
16/01/2020	Q:	Can 10% Ethanol blended Gasoline be stored in Floating roof tanks.	(3)
05/01/2020	Q:	The last time we opened the fired heaters of the Platformer units, we noticed lots of dust accumulating on the tubes. We are looking for ways to externally clean the coils online. Is there a way to do it with our internal resources? If not, what are the companies that offer this service?	(3)
04/01/2020	Q:	Why is the diameter of top and/or bottom of a VDU smaller than rest of the column?	(7)
01/01/2020	Q:	My question is related to an amine absorber used to strip out H2S from fuel gas or recycle gas. We know thatthe optimum temperature difference between gas and amine is to be maintained at 8 to 11 degrees Celsius. 1) Why does absorption decrease when delta T is below 8 & above 11? Please answer for individual case. 2) Moreover, does only delta T matter or do individual temperatures of gas and lean amine also matter for determining absorption efficiency ? 3) If individual temperatures do matter then what should be the optimum range of both?	(4)
01/01/2020	Q:	It is planned to replace the inlet system of the Reformer in a Hydrogen Generation unit with upgraded metallurgy from SS 304 to SS 347. This upgradation is warranted due to an increase in inlet temperature of the Reformer feed (Prereformer is being introduced as a part of a revamp). We would like to know if anyone has carried out such modification in your hydrogen generation unit. Please share the details including precautions to be taken.
18/12/2019	Q:	In our Hydrotreating & Hydrocracking Units, we do Catalyst Sulfiding in 2 stages: Low Temperature Sulfiding and High Temperature Sulfiding. What are the advantages of doing Sulfiding in 2 stages? If we are treating heavier Feeds is 3 Stage Sulfiding used?	(5)
17/12/2019	Q:	In Hydroprocessing units, in case of a Leak in the Breech Lock Exchangers, can maintenance be done without reducing System Pressure and without stopping Feed to the Unit?	(3)
12/12/2019	Q:	For a Cracked Gas Compressor in an Ethylene Plant, I am doing a simulation for determining optimum wash oil rate for the CGC. As a rule of thumb, 0.01 to 0.25 percent of cracked gas rate is taken as wash oil rate in plant. But I want to know how to calculate it using simulation now. I do not have compressor curves, so to start with I am doing it like this : three phase separator I have taken . I am flashing cracked gas outlet from compressor and wash oil and wash water in this three phase separator here. Now I want to know what is the point where I can say that it is an optimum flow of wash oil ? Do I need to run more wash oil to get dienes from the cracked gas outlet into the wash oil ?	(1)
07/12/2019	Q:	For part of a project, I am dealing with SR naphtha reforming reactors. The process is four reactors in series that use Pt-Alumina catalysts. Due to the high-temperature generation in the regeneration step, one of the reactors can not be in the service anymore. I want to know does anyone have the same experience? Is it possible to work with three reactors? Could you please inform me to find some useful resources to find a similar study and situation?	(3)
07/12/2019	Q:	In a case study for safety improvement and process analysis for SR naphtha reforming, I want to know If one of four reactors can not be in service is it possible to work with three? Is it safe to work with three reactors? Does anyone have such experience? Could anyone please inform me to find some useful resources to find a similar study and situation?	(2)
30/11/2019	Q:	What are the reasons for a Naphtha hydrotreater Reactor Delta Pressure increase?	(7)
23/11/2019	Q:	I am asking about the idea of mixing paraxylene with gasoline to increase its RON . From an economic perspective, is mixing Px with gasoline considered beneficial?	(3)
12/11/2019	Q:	Hello, In our hydrogen production plant we have our own steam generation system that produces 36 bar of steam at 390 degree C temperature. Steam produced in the steam drum has a continuous blow down vessel. We noticed that the conductivity analyzer goes so high that it reaches to NAN sometimes as it automatically reaches to its normal values without any external steps taken by us. We are curious about this automatic adjustment of conductivity in blow down. We have checked the instrument as well, but there is no issue with the analyzer. It is to be noted that the BFW is mixed with condensate separator before pressure swing adsoprtion. The condesate water first goes to degasifier and then mixed with demin water and then pumped to steam drum where steam is made. From couple of days pH of condensate is very low due to low inlet temperature due to dissociation of carbon dioxide, which made pH low. Kindly tell us if there is any reason for high conductivity as per our case.	(1)
08/11/2019	Q:	We are operating cooling tower with circulation rate of about 10,000 m3/hr. Recently a case of oil ingress occurred through one of the coolers in a process unit. This oil ingress resulted in increasing the cooling water supply temperature from 29 degC to about 36 degC. Although oil content in the cooling tower has been reduced to below 10 ppm by appropriate chemical dosing the problem of high CWS temperature still persists. Cooling tower fans and CW distribution through fills have been checked and found to be working fine. Can anyone suggest some measures for reducing this CW supply temperature back to normal?	(2)
08/11/2019	Q:	We are operating cooling tower with circulation rate of about 10,000 m3/hr. Recently a case of oil ingress occurred through one of the coolers in a process unit. This oil ingress resulted in increasing the cooling water supply temperature from 29 degC to about 36 degC. Although oil content in the cooling tower has been reduced to below 10 ppm by appropriate chemical dosing the problem of high CWS temperature still persists. Cooling tower fans and CW distribution through fills have been checked and found to be working fine. Any measures for reducing this CW supply temperature back to normal?
03/11/2019	Q:	What are the adverse conditions which may lead to formation of clinker and syntering during FCCU catalyst regeneration?
19/10/2019	Q:	This is with reference to High pressure exchanger overhauling job being carried out at DHT unit during ongoing Turnaround Shutdown. During Shell side combined hydro testing of Effluent-Feed Hot Exchangers bank (90E03A,B,C,D) to attend suspected leaks, cracks found in one of the exchanger (90E03D) tube sheet near Pass partition plate weld joint. Please refer attached photographs for location of cracks observed and also attached exchanger drawings. Thickness of Tube sheet is 372 mm and metallurgy is SS 321. Presently, grinding of T/s Crack location was done up to 15 mm and still crack exists. Prior to finding cracks, profuse leaks from some tubes (67 nos in 90E03C, 6 no in 90E03D where T/S cracks found) were observed during hydro testing @ 127 Kg/cm2 (HT Pressures: Shell-127 Kg/cm2. Tube-227 Kg/cm2). These leaky tubes were plugged with SS 321 plugs using TIG filler wise ER347 and subsequently hydro test was done during which one crack in T/S observed. In this regard, we require urgent guidance to understand repair methodology/testing etc. (Photos & video i want to share but unable to do)	(1)
08/10/2019	Q:	Can someone explain what does the pressure ratio and the critical pressure ratio mean in the following link? Also, does anyone have an Excel related to steam silencer design? https://www.geothermal-energy.org/pdf/IGAstandard/WGC/2005/1345.pdf
07/10/2019	Q:	What are the alternatives to hydrojetting to clean heat exchangers in a refinery? Are there any chemical cleaning solutions available to clean after bypassing the exchanger? Thank you	(4)
07/10/2019	Q:	I am currently working in Exxon Flexicracking FCC model. During start-up of the unit, when we establish catalyst circulation, sour water received in the MF O/H drum is acidic. When we introduce feed to the reactor, it becomes neutral. Why is it so? I am interested in the chemistry of the process leading to acidic boot water. Can we reduce the acidity by changing operating conditions of the MF or R-R section?	(1)
07/10/2019	Q:	I am currently working in Exxon Flexicracking FCC model. During start-up of the unit, when we establish catalyst circulation, sour water received in the MF O/H drum is acidic. When we introduce feed to the reactor, it becomes neutral. Why is it so? I am interested in the chemistry of the process leading to acidic boot water. Can we reduce the acidity by changing operating conditions of the MF or R-R section?
05/10/2019	Q:	Why is sour water from the main fractionator O/H drum acidic in the FCC during initial catalyst circulation without feed but becomes neutral after introducing feed to the reactor? I am interested in the chemistry of the process leading to acidic sour water? Are there any ways to reduce the acidity of sour water by changing the operating conditions of the reactor or fractionator?	(1)
04/10/2019	Q:	In our CO2 degassifier, the inlet concentration is 100 ppm when the outlet iş 50 ppm. The system has impregnated wood to seperate CO2(g) from the cationic water. What kind of effect has a high concentration of CO2 on anionic column and boiler feed water?
02/10/2019	Q:	Regarding centrifugal compressors in hydroprocessing units, if the suction strainer goes high we need to shut down the compressor manually to avoid vibrations, surging. There are no automatic trips provided on high Delta P. Is there any reason for not providing an automatic trip on suction strainer Delta P?	(1)
01/10/2019	Q:	Hello, In our refinery we have an alkylation unit with HF and in recent dates we have had many problems with the acid vaporizer of the HF regeneration column (acid leaks from the tubes). The tube bundle is monel 400 and the heating medium is tempered medium pressure steam. Do any of you have similar experiences and could you help us find the failure mechanism? Thank you.	(2)
26/09/2019	Q:	Is there any alternative to caustic ( NaOH) addition after the desalter in the crude unit to control chloride carryover? As we know, sodium is the cause of fouling in the downstream unit with the addition of higher dosages of NaOH. Thank	(6)
25/09/2019	Q:	Sour water from the SRU quench column is routed to the sour water stripper normally.My doubt is whether this will go to the Phenolic Sour water Stripper or Non-phenolic sour water stripper? Request the professionals of SRU to clarify. Please also explain the reason if it is routed to the Phenolic Sour water stripper unit.	(2)
20/09/2019	Q:	Can anyone explain about C3 and C4 refrigeration systems or send any documents or file links.
18/09/2019	Q:	What is the reason for coke formation in the wet gas compressor and what is the solution?	(1)
13/09/2019	Q:	What will I get if I apply a heating process to gas which contains hydrogen sulfide?	(1)
11/09/2019	Q:	One of our centrifugal compressors in recycle gas service (93% H2; 6% CH4) was designed to perform for 4 cases, SOR; EOR conditions, H2 service and only N2 service. However, during the design phase the differential pressure data given the vendor was uniform and corresponded to that envisaged for N2 service. During commissioning, the actual DP obtained across the system is way less and the compressor is operating on a very low RPM and more towards the stonewall, even though gas molecular weight and the operating parameters have reached their near design values. What are the probable solutions to this problem, so that we can push the machine towards its normal operating envelope and increase the flexibility of plant operation? Will trimming of impellers help?	(1)
10/09/2019	Q:	When a furnace is intended to operate at more than design capacity, tube skin temperatures are expected to reach beyond tube design temperatures. It is because the increase in heat flux is higher than design value. Let us say that tube skin temperatures are 50 deg.c above the tube design temperatures. How can we make a decision whether the heater can be run at more capacity or not based on tube skin temperatures ?	(1)
10/09/2019	Q:	What is the best way to theoretically blend isomerate and reformate for octane number from gc data linear blending vs index blending using blending octane number Further what is the source of obtaining blending octane number of individual hydrocarbon	(3)
04/09/2019	Q:	Does any one has info on blending RON for gasoline linear vs indexed OR blending RON number of component hydrocarbon determined from GC analysis and where to get blending RON numbers
03/09/2019	Q:	Why does the FCCU main fractionator column bottom level need feed make up during low throughput? Why is the level not maintained properly during low throughput?	(4)
30/08/2019	Q:	I am working in hydrotreater and i want to know, can we inject wash water to REAC during the catalyst sulfiding stage ? What are the advantages and disadvantages of injecting during the catalyst sulfiding stage ?	(2)
30/08/2019	Q:	Hello everyone!! It is possible that the hydrodesulphurization catalyst (NiMo, CoMo) of a gasoline unit is reduced from its sulphidated state to its inactive (metallic) state, by supplying make-up hydrogen (without sulfur) and performing continuous gas purging of the gas system reaction (without supplying the unit with feed) and with a temperature of 30 ° C in the reactor? Thank you	(5)
25/08/2019	Q:	Hi All I'm trying to simulate naphtha hydrotreater in Hysys v 8.8 and facing following problem. I tried to change pressure and temperature as well but not getting converged. 1-OOMF Line search failure. 2-Calibration page sulphur and Nitrogen is not in feed message is coming. Can anyone explain what is OOMF and how to solve it. Best Regards
23/08/2019	Q:	What is permissible limit for bending of arbor/wicket coil in CCR box type fire heaters.
20/08/2019	Q:	In coker with more than one module, according to the experience in their units, how much does the performance of liquid products decrease when a module goes out of service?	(2)
14/08/2019	Q:	In our delayed coker unit, we have observed severe corrosion in Stripper Reboiler (Tubes were found heavily corroded) which is leaving heating media as Debutanizer bottom. During its 20 Years of life we have never observed corrosion in these reboilers. What are the possible causes for this? For preventing cyanide corrosion in Gas Concentration unit we are adding Ammonium Sulphate however we have never observed cyanide level greater than 0.1 ppm in sour water anywhere in plant. Is there any chances that this Ammonium Sulphate is causing this corrosion as there is no cyanide present in the system.	(1)
13/08/2019	Q:	Is it possible for Arbor / wicket coils of CCR box heater to get tilted over a service of 5-6 years.
08/08/2019	Q:	Drag Reducing Agent is being added in crude oil during cross country pipeline transfers .Crude oil will be processed in the refinery Crude column along with Drag reducing agent. In crude column the crude oil is subjected to very high temperature . The remains of drag reducing agent after thermal stressing will land in which stream ?	(1)
07/08/2019	Q:	Why are some reciprocating compressors using glycol for their cooling system in the recycle gas compressor while other don't have such as net gas booster compressor?	(3)
06/08/2019	Q:	Monitor antifoams concentration in amine slovent We have treated silicon base antifoams in amine solvent to cure absorber foaming issue, and regularly monitor conc by analyze silicon content in slovent, due to silicon base antifoams have negative effect when overdose, we change to non-silicon base additive (polyglycol based chemicals); could anyone suggest how to measure conc. of non-silicon base additive?
06/08/2019	Q:	Monitoring antifoam concentration in amine solvent We have treated silicon base antifoams in amine solvent to cure absorber foaming issue, and we monitor addtive concentration regularly by analyze silicon content in slovent, due to silicon base additive has negative effect if overdose, we use non-silicon base additive (polyglycol based chemicals), how to measure non-silicon base additive conc. in amine solvent?
01/08/2019	Q:	We have a reciprocating compressor (motor driven) at UOP CCR-Platforming unit. Service of this compressor is Hydrogen. Recently we have noticed that its lube oil temperatures are rising. We have checked the cooling water flow of the lube oil cooler and found it adequate. Please provide expert opinion regarding causes and remedies of rise in lube oil temperatures.We are using Shell Rimula R2 Multi 10W-30 (CF4) for lubrication.	(2)
31/07/2019	Q:	How is the process heater low pass flow trip decided?
17/07/2019	Q:	Why does cavitation not occur in a reciprocating pump?	(1)
15/07/2019	Q:	Thanks a lot Mr. Sam Lordo for your Answer on below question , Please also enlighten me whether the water injection rate should be 1-2% of the total overhead flow based on the query below? "In our distillation column we are treating Natural Gas Condensate with 76 ppm sulphur, Acidity < 0.05 mg KOH and organic chloride <0.3 ppm and water content < 0.05%. but designer did not keep any caustic, corrosion inhibitor and Ammonia dosing provision due to combat corrosion at overhead line. Also they did not keep any DM water flushing provision (for fouling control within the tubes of aero condenser). Is it ok not to keep above provision as per above spec of NGC or NGL? But we are draining the overhead drum water separating boot approximately 10-15 litres per day where PH remains 5 to 5.5. So, do we need to use NH3, Caustic and corrosion inhibitor in order to keep PH more than 6?"	(1)
14/07/2019	Q:	Which metal is used for sulphur guard for naphtha services? What are the available options?	(2)
13/07/2019	Q:	At our Stripper Column Overhead of Naphtha Hydro-treating Unit , we are injecting pure Chimec 1044 (from CHIMEC S.p.A)which is a blend of polymeric compound in heavy aromatic solvent @ Injection rate kg/hr : 0.02 kg/h of pure Chimec 1044 based on 10 wt. ppm chemical injection rate over the process rate. Besides, Natural Gas Condensate (NGC) is used as a feed for Natural Gas Condensate Fractionation Distillation Coulmn (CFU) which is a by product from Natural Gas Plant having very low sulfur as well as salt. In fact, we are planning to blend 5% TG with high sulfur (from other crude oil refinery) together with the NGC for processing in CFU . Can i use the same Corrosion Inhibitor (Chimec 1044) at the overhead of our (CFU)?
28/06/2019	Q:	I hv naphtha cracker wherein there is an issue of fouling in cracked gas compressor and it's intercoolers also. What is exactly the fouling material . Is it styrene and butadiene most of the time ? Customer is doing wash oil at 2 percent rate continuously and wash water with batch mode only . What is the role of wash oil? Wash oil can not act as antifoulant right ? Can you please explain. What are treatment options for fouling in such equipment ? Also let me know red oil formation in caustic tower ? What is composition of red oil ??	(1)
28/06/2019	Q:	For our Delayed Coker Unit after quenching drum some portion of hydrocarbon is coming from the vent lines while opening of the vents to continue draining. We checked the quench oil lines to be sure the valves are leaking but quench oil valves are not leaking. We tried to put steam by opening the steam connection just upstream of the vent valves during quenching. It helped but for this time, we have some problem with quenching of the drum. The drum overhead line is not cool down enough during quenching. Can anyone help to identify reasons why hydrocarbon is coming from vent?
27/06/2019	Q:	How do you estimate the decrease in yields resulting from an increase in pressure in the fractionator due to fouling in the head coolers?	(2)
24/06/2019	Q:	How do you minimize slurry concentration in the MF bottom/slurry circuit system? What operational parameters can be checked/adjusted?	(2)
24/06/2019	Q:	For the FCC slurry circuit, can you recommend ways to address/mitigate control valve erosion? What adjustments in FCC operation can aid in minimizing the erosion in control valves?
23/06/2019	Q:	We are facing problem of shorter run length of our Delayed Coker Unit(DCU). The furnace coil inlet pressure increases to design limit within a very short interval i.e. 30-35 days after the SAD, however the tube skin temp remains well below the design limit. The feed to the DCU unit is VR from VDU, having asphaltene about 5% & CCR about 17%. The COT, BFW flow and other operating parameters are maintained as per the design operating guidelines. Can anyone help to identify reasons for the drop in the run length of our DCU?	(7)
23/06/2019	Q:	Two streams mix together: 1. A liquid or oil stream @ 160 degC and 110 kg/cm2(g). 2. A gas stream (mainly H2 gas) @ 160 degC and nearly 85 kg/cm2(g). The "mixer" consists of a pipe, in which oil is flowing from right to left. The gas entering at right angle from above. The gas is introduced in the oil by means of a nozzle in form of a smaller dia pipe with an elbow, directing ALONG the flow of liquid. (if direction of flow of oil is --> , then the elbow also directs the smaller pipe towards ---> direction). There is no pressure indicator just before or after the "mixer". The questions are: 1. What will be the resulting pressure, downstream of the mixer? (after the nozzle or smaller dia pipe). 2. Why does liquid oil not enter the smaller pipe which introduces the H2 gas into the oil? 3. Does the nozzle in the pipe act as an "ejector"? and the gas being pulled along the oil? 4. What will happen if the nozzle is removed along with its elbow, and the gas introduced in to the liquid just using the pipe attached at right angle? Will the gas flow in to the oil or the oil will flow in to the gas? The approximate flow rates are: Liquid: 112 STD m3/hr (94,000 kg/hr). Gas: 74,000 Nm3/hr (12,000 kg/hr).
17/06/2019	Q:	The wash water quality standard from NACE and most articles I have read recommend using phenolic water in either desalters or crude overheads only. I have not found an example of any reuse of stripped sour water from a SWS with phenolic water (FCC or coker sour water) feeds for wash water on a hydrotreater effluent train wash water injections. I have read through articles on polymer fouling in the sour water stripper itself due to phenols and one corrosion book cited kerosene color issues with phenols. Other than that most articles just say phenolic water is recommended for desalter usage mainly but don't call out the specific issues of phenolic stripped sour water for hydrotreater wash water. Are the accompanying cyanides and HSS the main concern, concentrating up at the injection site, or are there concerns with the phenols themselves being injected downstream of the hydrotreater? Are there any examples of diluting phenolic stripped sour water with other streams and reusing it in hydrotreaters if you don't have enough sources of non-phenolic stripped sour water?	(2)
15/06/2019	Q:	What is the suitable configuration of Deisohexanizer column to produce Pharma Grade hexane? We have existing DIH column which was designed to separate C5 & C6 isomers from overhead, unconverted n-hexane from side cut as recycle and Cyclohexane, methyl cyclohexane, c7+ components from bottom of the column. Now, we are planning to reconfigure DIH column to separate Pharma Grade hexane. New column should be able to separate PGH during PGH production and should separate isomerates properly during normal gasoline mode. In this context, how should column look like in terms of draw locations e.t.c
12/06/2019	Q:	What are the particular properties of Kissanje blend crude oil and the problems that might be encountered during its processing?
11/06/2019	Q:	Iam working in Indian Refining company.Our company is in the process of putting up two SRU (one working and one standby).Two trains of SRU with common TGTU has been planned. Whether common Incinerator+ WHB or dedicated Incinerator+WHB should be preferred is the question.	(2)
31/05/2019	Q:	What are the treatment methods for removal of butyl mercaptan from LPG stream?	(2)
31/05/2019	Q:	We are designing an LPG sweetening unit. The sour LPG consists of H2S, methyl mercaptans, ethyl mercaptans, propyl and butyl mercaptans , COS as the sulphur impurities. To remove H2S we are using amine absorption tower using MDEA solvent. Then it is followed by caustic wash for mercaptan removal. We observe that butyl mercaptan is not removed effectively from caustic wash. The caustic wash circulation has to be increased to a very high unreleastic values to achieve 10ppmw sulfur at the downstream of caustic wash. Can you please inform on the various options for butyl mercaptan / H2s levels of sour LPG after amine absorption : (in ppmw) Sour LPG Methyl Mercaptan : 0.966 Ethyl Mercaptan : 6.877 Propyl Mercaptan: 12.529 Butyl Mercaptan: 108.822 Hydrogen Sulfide: 15.000 Carbonyl Sulfide :36.316	(3)
30/05/2019	Q:	We have a semi regen platforming uint and catalyst type UOP-R56. During the regeneration after completion the nitrogen purge step, we not complete next step. Now the reactors under positive nitrogen pressure for 30 days. 1-Is this situation adversely affects the catalyst after the oxidation and nitrogen purge steps? 2-what needs to done in this case?	(1)
27/05/2019	Q:	How do you calculate actual flow rate of Fuel Gas from the flow meter reading? In our process plant we have Fuel Gas FTs which gives us reading in Nm3/hr and we want to calculate from this reading actual fuel gas flow taking into account temperature, pressure and density corrections. Which is the most accurate formula for calculating flow rate? What are the best practices followed by other refineries in order to calculate the fuel gas flow, do they apply temperature and pressure correlations? Pressure or density which is better to take in account?	(3)
26/05/2019	Q:	My question is related to indications of channeling or bypassing in a catalyst bed. An indication of bypassing or channeling is the Radial Spread (T.peak - T.min) of the multi-point thermocouples provided at the outlet of the bed i.e. difference between peak temp and min temp. However, it is measured as Radial Spread divided by the Temperature difference across the catalyst bed: RS/dT = (Tpeak-Tmin) / (Tpeak-Tinlet) Where Tinlet is the average inlet temperature to the catalyst bed and the value of the ratio RS/dT should be below 0.5. Any value greater than this indicates channeling in the catalyst bed. How is RS/dT an indication of Channeling? Why is its limit 0.5?	(3)
24/05/2019	Q:	We have a problem at our CDU. It is observed that when we examine salt content at the start of crude charging tank after giving it 24 hour settling time, salts are in yhe range of 2 to 5 PTB. But when same tank is charged and sample is taken at CDU upstream, salt content is higher... Up to 50bPTB... What could be possible reasons?	(7)
20/05/2019	Q:	Why we are using high pressure steam in heaters?	(2)
16/05/2019	Q:	This question is in regards to filter clay lumping in Kero Merox treatment. What factors could lead to filter clay lumping in Kero Merox Treatment? How to counter this issue from not occurring whereby unloading is not a painful experience. Any advice/suggestions would be greatly appreciated	(3)
10/05/2019	Q:	What is the temperature at which coking starts in Delayed Coker?	(3)
07/05/2019	Q:	Carburization is affecting heater tube in Coker unit. Kindly share your experience of any failure encountered and what corrective actions can be beneficial for preventing or increasing material resistance to carburization.
01/05/2019	Q:	In our Delayed Coker Unit, we have a Balanced Draft Feed Preheater in which draft is continuously hunting whenever the Stack Damper is kept closed. What are the causes and possible solutions for the same?
01/05/2019	Q:	What is the cracking temperature of Vacuum Residue?	(2)
01/05/2019	Q:	In our Delayed Coker Unit (DCU), we have a Feed Preheater which is a Balanced Draft Fired Heater. The Draft of heater is continuously hunting whenever the stack damper is fully closed so we are operating the same with stack damper 15% open. Also the Excess Oxygen & Draft are on the higher side in this condition. What can be possible cause for the same & possible solutions?	(5)
30/04/2019	Q:	What is the best check valve type at reciprocating compressor discharge line on Hydrogen service? Also references of manufacturers for this type of check valve.	(1)
29/04/2019	Q:	Is there any way of knowing by Amine regenerator inlet or outlet temperatures whether there is a hydrocarbon carryover to system ? Is there any way to just predict foaming tendencies in Regenerator with just temperature profiles across it ?	(1)
23/04/2019	Q:	I am doing hydro test in normal galvanized pipe. During hydro test the ambient temperature is 43 degree Celsius. Test pressure is 24 bar and holding time is 1 hour. The problem is when I set pressure in 24 bar after 1 hour of holding time it became 26.5 bar. Pressure increased 2.5 bar. Is there any scientific reason behind increasing 2.5 bar?	(1)
22/04/2019	Q:	On what terms HT/ MT/LT shift converters are decided for Hydrogen unit?	(2)
18/04/2019	Q:	We use DMDS for catalyse activation of hydrocraking, hydrotreatment unit and sometime for plaforming unit. DMDS is procured packed in metal drums. Our main issue is the treatment of waste dmds and also their containers. We have a quite subsequent amount of waste drums and chemicals. What are typical process or best practices about waste dmds management?	(3)
12/04/2019	Q:	In the our HDS unit it treat light distillate cut (Ibp 40 C Ebp 230 C) come to unit from CDU unit and after treated go again to CDU unit to separate the light distillate to products LSR , NAPHTHA and KEROSENE . In the last 3 weeks till now we had tested Naphtha in the lab. for sulphur content and the result is > 1 ppm the normal result is < 0.5 ppm which is suitable for SR reforming unit as feed ...we do many changes in the operations setting in the stripper column but that change nothing. The stripper column bottom temperature maintained by circulating to furnace and we noted that the level in reflux drum increased abnormally in the last month so we increased the reflux flow rate to the overhead. Are there any recommendations for this situation?	(5)
27/03/2019	Q:	For a given gasoline car or bike (engine), does the efficiency increase by increasing the fuel RON? i.e., without changing the engine does the efficiency increase by just increasing the RON of fuel.	(2)
19/03/2019	Q:	Please share the detailed procedure of KMnO4 washing of Vacuum Column. Can KMnO4 washing be done before steaming and hot water wash of column ? Also, if KMnO4 washing is to be done after steaming and hot water wash then whether column is to be cooled to ambient condition. Any requirement of cold / hot water wash of column after KMnO4 washing is completed ?	(2)
14/03/2019	Q:	what is the role of DMDS in adding to the platformer unit feed?	(4)
14/03/2019	Q:	In the our hydrotreating naphtha plant total sulfur is increased more than .5 ppm (this is my specification) and this hydrotreated naphtha (HTN) used to Aromizing unit to produce Aromatics. As you know, in the furnace of CCR platformer DMDS is used to passivate furnace tubes ,but when total sulfur increase more than .5 ppm in the feed of CCR platformer we stop injection of DMDS in the feed of CCR platformer and the question is : can we stop the injection of DMDS in the feed of CCR platformer in case of total sulfur increase more than 0.5 ppm in HTN? does the increase of TS in HTN can do the role of DMDS in furnace tube ?	(2)
14/03/2019	Q:	Our refinery has installed corrosion control system (filming and neutralizing amine injection) in our overhead distillation column system. However, since the water content isn't too high, we cannot have enough sample from water bootleg. Our Fe content in water bootleg sample is quite high (>100 ppm) with previous injection of filming amine is considerably high (up to 18 ppm). The chemical vendor suggested us to install wash water system. However, install wash water system may take longer period and we wonder if continue injecting amine is still effective without wash water system. Have anyone had this kind of experience and is there any suggestion to keep the corosion controlled without wash water system?	(3)
06/03/2019	Q:	How to remove pyrophoric material from FCC Reactor, if any, Does any refinery face such kind of issue during turnaround?	(1)
01/03/2019	Q:	In a naphtha stabilizer, top tray (tray 46) temperature is controlled by the reflux and the bottom tray (tray 3)temperature is cascaded with the hot light gas oil flow (reboiler's hot medium). Top pressure (overhead vapor pressure not the OVHD drum pressure) is controlled by the removal of non-condensed vapors from OVHD accumulator. Here, when I increase the bottom tray temperature, top pressure is getting increased slightly (very minimum) and then OVHD vapor pressure is getting decreased faster. Can anyone explain this phenomenon? Note: Distillation tower - 48 trays column; OVHD product - LPG; Bottom product - Stabilized naphtha.	(4)
22/02/2019	Q:	Do you have any ideas about the industry average of attained steam purity for steam turbines? Currently, we cannot meet the OEM requirement of steam purity, thus we are concerned that fouling might occur on our steam turbines.
16/02/2019	Q:	When our VDU column products, vacuum slop and vacuum residue were tested for H2S it showed H2S presence >10 ppm.What could be the possible reasons for high H2S? We are maintaining VDU bottom level and temperature low to avoid cracking still H2S reported is high.Coil steam and Velocity steam were increased and kept 120% of the PFD values. Chances of exchanger leak was also checked and observed no leak.	(4)
16/02/2019	Q:	In our refinery Crude heater when open it we see moisture on whole pipe. Can you explain the possible cause for that?	(1)
15/02/2019	Q:	I understand that increase in wheel chamber pressure is associated to fouling. But does increase in wheel chamber pressure always equate to axial displacement of rotor and increase in thrust bearing temperature? Reduction of process demand feed will result to reduction of wheel chamber pressure, however, we observed that once we return the feed rate to values prior reduction, (ex. 35mbsd to 25mbsd then return to 35mbsd) there will be an increase of WCP? what are your thoughts on this observed trend?
15/02/2019	Q:	I would like to hear your views on the factors that are the major causes of the increase in Wheel Chamber Pressure. To give you a background, we are currently experiencing an uptrend of wheel chamber pressure on our MANTURBO turbine almost reaching alarm values. Turbine steam flow has slightly increased also. Adjustment of exhaust pressure has yield into a slight decrease of WCP. Base on our findings, we are leaning into fouling as one of probable causes of the increase of wheel chamber pressure. However, there was no axial movement of rotor or increase of bearing temp on the active side of the thrust bearing. Does increase of wheel chamber pressure always equates to movement of rotor and increase of bearing temp? Furthermore, we cannot explain the observed trend of the WCP. Every time we reduce the feed rate, WCP also decreases. However we cannot explain why when we increase feed rate to its value prior reduction, (Ex. from 35 mbsd, to 25mbsd then return to 35 mbsd again) Wheel chamber pressure will be higher and have an uptrend increase! What do you think is the explanation with this observe trend? As of the moment, we cannot afford to down the equipment and we do not have the necessary materials for overhauling. Can you guys share your thoughts on how can we lower the WCP? Or even just maintain pressure and prevent any further increase?	(1)
12/02/2019	Q:	What is the deltaP value changing limit(+/-) into the fuel line during the leak test for crude oil furnace burn with natural gas. Is there any calculation method, standarts extc? NFPA 86 says in a table A.7.4.9, can we use these values?
30/01/2019	Q:	what is the maximum sulphur level in feed (Naphtha) that a platformer catalyst can handle without a hydrotreater?	(2)
26/01/2019	Q:	Linden based Hydrogen unit, NG is using as feed for hydrogen generation. There is a hydrogenation reactor with COMOX catalyst where hydrogenation reaction takes place after that desulfurization reaction in next reactor with ZNO catalyst. NG feed having no sulfur and we operate the hydrogenation reactor in line for many hours. Since there is no S in NG feed no H2S formation will occur in that reactor. Catalytic reaction will not occur. As per requirement, we take sometime RFG (refinery fuel gas) , which having sulfur content for Hydrogenation reaction in COMox based reactor. My question is this type of feed variation, deactivated catalyst may work after taking RFG feed or how we can make activate COMoX catalyst when NG feed in line alone.	(1)
19/01/2019	Q:	In our TGTU section of SRU, We have Stripper column which strips out H2S from the amine. The H2S will routed to SRU as feed from the Reflux drum O/H of Stripper Column. In recent days, it has been found that, all of Sudden Stripper Column level is decreasing and the same time The reflux drum get full and get overflow in the Overhead line(O/H). During this time there is a sharp increase in column PDI. After a while, everything gets Normal after taking some actions (Reboiling steam cutting, reducing amine circulation rate,increasing reflux flow etc..,). This case happens rarely but we couldn't stop it. What could be the reason for the above case. How to avoid it?	(5)
19/01/2019	Q:	Emergency Depressurization (EDP) System design Our Hydrocraker unit has two emergency depressurization systems : 7 bar/min (100 psi/min) and 21 bar/min (300psi/min). Unit design pressure is 160 barg and feedrate is 86 m3/h Licensor assumes that EDP system (RO + Valve) is designed to decraease pressure unit by 7 bar or alternatively 21 bar in first minute . Today unit is operated at higher flowrate (128 m3/h) and lower pressure (145 barg) A depressuring test done in the new conditions showed that the depressuring rate decreased at 18 bar/min instead of 21 b/min in first minute. Is this new depressusing rate still acceptable or should EDP valves and Restriction Orifice be resized to target 21 bar/min? Additional info: Refinery situated in the Ivory Coast	(2)
18/01/2019	Q:	I have a problem with time consumed in purification through distillation. My distillation column consists of 27 feet 12" column with paul rings as packing components. I have a reflux at 17 feet in column, that comes from the two condensers of 17 meter square and 10 meter square. I do distillation by two stage water ring vacuum pump with booster attached. I get the vacuum of 735mm/Hg. What should be the reflux temperature that goes back in column? Or in reverse, what should be the temperature difference that goes back in column and at the bottom?
11/01/2019	Q:	While buying and processing Eagle Ford crude oil from Texas, a large amount of methanol was discovered in Light Naphtha (About 700 ~ 800 ppm). Methanol was expected to be mostly removed from the Desalter, but after checking the samples at the front and rear of Desalter, the reduction rate was around 10%. The Desalter temperature and pressure conditions have been checked, but the phase may not be changed. Can you explain why methanol is not removed?	(1)
10/01/2019	Q:	Methanol content of Light Naphtha (<75) increased rapidly during processing. When I looked up the cause, I found that the oil produced in Eagle Ford of TX was high in methanol content. Methanol was expected to be removed in desalter, because it is polar solvent. However, the rate of elimination was 20 percent and very low than expected(in 2 stage Desalter).Why isn't methanol removed from Desalter? I would appreciate it if you could tell me the similar experience or literature.	(1)
09/01/2019	Q:	In our VDU column we are planning to route slop recycle directly from Chimney tray (Above flash-zone) to stripping section using gravity flow. Is it feasible to route slop recycle without slop quench pot & pump? Situated in India	(2)
02/01/2019	Q:	On our dehydrator vessel we have 2 x 2 phase transformers but the current is unstable. Why would the current be fluctuating so much?	(1)
28/12/2018	Q:	We are operating a small refinery processing sweet crude (less than 0.4 wt % sulphur). The crude is heated in a heat exchanger network and sent to a preflash column. The overhead from preflash column are condensed as naphtha and sent for stabilization after removing free water in overhead reflux receiver boot followed by coalescer. The naphtha is reboiled in the column and refluxed by a overhead stab in condenser. Vapour from the column are sent as fuel. Recently when the column was opened up after one year of service the overhead condenser was badly corroded. In fact all the tubes had holes (condenser uses cooling water in the tubes). The strange thing which was noted that elemental sulphur embedded in the corrosion product covering the outside of tubes. We are wondering where this elemental sulphur was formed? The overhead operating temperature is 100°F. We are using antifouling agent in our crude but the vendor says that there is no possibility of elemental sulphur from their product. Additional: 1. Preflash overhead goes through a prefilter followed by a sand bed coalescer. We have observed no emulsion and water haze after these filters and coalescers. However, we are recycling boot water to overhead condenser in the preflash. There is no water wash in the stabilizer as it is a simpler stripper with no overhead condenser and drum. 2. No outside naphtha is being processed; however, demin water solution is prepared with neutralizer which is injected in preflash overhead. We are wondering about this Claus type reaction that take place under these mild conditions without catalyst.	(2)
25/12/2018	Q:	In the fractionator column JET A1 side stripper some time I faced level fluctuating before the hot vapor from the side stripper to to fractionator column temperature normally more than 205 deg C the side stripper level is normal if the temperature of the hot vapor retune less than 200 deg c level will start fluctuating.What's the reason and how to solve it? I have to increase side stripper reboiler or draw rate?	(1)
19/12/2018	Q:	The color of Gas oil produced from Mild hydrocracker is off spec. After changing the catalyst and the feed blend. The new feed blend includes 20% of Aromatic extract and VGO in feed blend was reduced by the same %. What are the reasons of gas oil color changing? is feed tank required to be blanket with Nitrogen?	(2)
18/12/2018	Q:	I saw an answer in Q&A, that portable electric desalters will screen the demulsifiers. I would like to screen some of my demulsifiers using portable electric desalter (PED). Can anyone suggest the suppliers of PED? it would be a great help.	(3)
13/12/2018	Q:	Reprocessing slop oil is always a headache issue for refiners, in our refinery, we blend recovery oil (one of slop oil from crude tank cleaning) into heavy crude slates (API<28), but suffering problem on desalter operation, higher emulsion layer led to electric field trip and desalter brines contain oil which can result wastewater treatment plant in upset, we would like you could share the operating experience on reprocessing slop oil with minimal impact on these facilities, thank you~ Questions (1). What kind of pre-treating methodology did you apply on slop oil before reprocessing? Water separation or any filtration steps? (2). Did you use chemicals for slop oil pretreatment? (3). How did you reprocess slop oil? In-line injection into CDU uint or blend slop oil into crude tank?	(6)
12/12/2018	Q:	What is best practice for design of dewatering systems on pressurised LPG storage spheres and how is this affected (if at all) if the installation is located in an extreme cold climate? Is manual or automatic draining recommended? Automatic drain systems are likely to be a more complex design. For example, a new-build design might be fully automated and comprise a 2" nozzle with a remote-operated, accessible fire safe primary isolation valve at minimum distance followed by a dewatering pot with an interface level sensor. The interface level sensor would throttle a control valve with bypass on the dewatering pot drain line and an independent lo lo interface level sensor would trip closed the primary isolation valve and de-energise the solenoid on the downstream interface level control valve to force it closed. The trip system would also impose an output high limit of 0% on the interface level controller forcing its output to zero to avoid the valve bumping open when the trip is reset. The dewatering pot would have a hard-piped connection to flare and a hard-piped connection to a closed drain. The interface level sensor would have a local repeater indicator visible from the bypass valve. The drain line would reduce to 3/4" diameter downstream of the control valve (this serves as a restriction orifice on the drain system). It would be designed to be self-draining with no pockets and would be well-braced to minimise vibration while in operation. The number of flanges in the system would be minimised and the majority of joints would be socket-welded (screwed fittings not allowed except perhaps for instruments). Cold climate considerations (also mitigating Joule-Thomson expansion effects) might include electrical tracing on the dewatering pot drain line with a common alarm to DCS on tracing circuit failure and provision for methanol (anti-freeze) injection into the dewatering pot flare connection.	(1)
11/12/2018	Q:	In our distillation column we are treating Natural Gas Condensate with 76 ppm sulphur, Acidity < 0.05 mg KOH and organic chloride <0.3 ppm and water content < 0.05%. but designer did not keep any caustic, corrosion inhibitor and Ammonia dosing provision due to combat corrosion at overhead line. Also they did not keep any DM water flushing provision (for fouling control within the tubes of aero condenser). Is it ok not to keep above provision as per above spec of NGC or NGL? But we are draining the overhead drum water separating boot approximately 10-15 litres per day where PH remains 5 to 5.5. So, do we need to use NH3, Caustic and corrosion inhibitor in order to keep PH more than 6? Moreover, do we need to inject DM water at the up stream of Air cooler to eliminate fouling problem as well as increasing PH by the dilution of DM water?	(3)
08/12/2018	Q:	Prior to the use of simulators or for preliminary calculations, how the draw off temperature for a specific cut like gasoil or kerosene is determined using TBP data.	(1)
08/12/2018	Q:	I need to compare the current residue cut of my atmospheric distillation unit to the TBP/ complete Assay of earlier used crude feed. My question is how can i correlate both of them, how does the operating conditions /temperature and yields be compared with the TBP Analysis? If a process simulator like HYSYS can be of help.
06/12/2018	Q:	Crude oil desalter problem: It is observed that during normal running of Crude oil desalter(2 stage in series), the Amperage increased from 45 to 90Amp. It was also checked that there is no water shot with crude(i.e. < 500PPM H2O). Immediately wash water stopped, still current doesen't comes down. Hence, wash water resumed and observed current at higher side. Evev, the crude oil type processed is also the same as earlier. What could be the reason for high current and suggest solution to bring down current?	(4)
04/12/2018	Q:	what is relation between temperature and throughput in the reaction of hydro treating unit?	(2)
03/12/2018	Q:	what is the cause of co (monoxide carbon) formation in the catalytic reforming unit?	(2)
02/12/2018	Q:	Why anion resin exhausted before cation resin in ion exchange water treatment?	(1)
23/11/2018	Q:	Why anion resin is exhausted before anion resin in ion exchange process in water treatment?	(1)
22/11/2018	Q:	Can anyone explain me what are all the parameters that affect H2 purity in Recycle gas in case of a Hydrotreater/Hydrocracker ?	(4)
09/11/2018	Q:	How to monitor performance of CO promoter additive? What is CO index and its significance?
05/11/2018	Q:	What would be the effect of fluctuation in regeneration gas flow in UOP Cyclemax Regenerator if my flow is having variation by 5-8%?? Will there be any effect on catalyst coke burning? What could be the reason for flow variation?	(4)
31/10/2018	Q:	In VDU we are facing problem in HVGO SECTION, that HVGO pump suction strainer periodically choking? What’s the causes?	(6)
27/10/2018	Q:	VDU OVHD off gas after treatment in amine (MDEA) absorber routed to VDU furnace to serve as secondly source of firing along with Refinery FG (low in Sulfur).. H2S in treated offgas is 100ppm (design 0.1%). However, Sox (SO2) in final four gas is high?? Reason? We checked other Sulfur species's presence which are contributing high SOx. Any way to treat other Sulfur compound and bring Final emission under control??	(6)
27/10/2018	Q:	In Our Sour Water Stripper Unit, The quality of Stripped Water is as follows: H2S :0.4 PPM(Max.10 PPM) NH3: 2.4 PPM (Max 50 PPM) Ph: 8.9(6-8) The H2S and NH3 are in desirable range but still we couldn't get lower Ph in stripped water? Is any other factor causing low Ph?	(2)
26/10/2018	Q:	Kindly advise that if a leakage arises from LPG tank lorry during filling operation, how should the leakage be handled? Are there any code and standards that outline what exact steps we need to take in case of a leakage?
25/10/2018	Q:	At a compressor's steam turbine, frequent vibrations are faced at Journal bearings. The vibrations go from normal 13microns to about 45 microns. Steam temp and pressure are normal We previously faced oil charring issue at the bearings and the problem was rectified by applying nitrogen in the seal. We suspect that the same problem has reappeared. Can anyone suggest how can we confirm if this is oil charring and how the issue can be resolved?	(3)
11/10/2018	Q:	How the Load on Furnace in Crude distillation unit on CIT of Furnace? In our Furnace the design conditions of CIT/COT are 260/360 C and actual conditions are 250/350. Is Furnace fired duty depends on Delta T only or is it depends on CIT of Crude?	(3)
07/10/2018	Q:	What is minimum H2S level maintain in UOP naphtha hydrotreating reactor recycle gas? why naphtha hydrotreating reactor can not purge at what temp?	(5)
03/10/2018	Q:	Is there any limitation for taking Hydrogen rich off gases as feed to reformer? My doubt is whether excess hydrogen in the feed to reformer can it cause reversible reactions as steam methane reforming is reversible in reaction?	(4)
27/09/2018	Q:	Is there any limitation for taking Hydrogen rich off gases as a feed to Reformer , If yes what is the limitation ? Is it because of Le Chatlier's principle if Hydrogen is more will it cause backward reaction? Or else is there any other limitation ?
25/09/2018	Q:	Our naphtha sample from crude distillation unit went off on chloride content with result showing 1.3 ppm.So we checked organic chloride in our crude tank. The result showed presence of organic chloride in that particular crude tank. So that tank is kept blocked and we resumed to our normal operation. We did many brain-stroming and looked for solution. Can the experts in this forum please suggest how to process this crude having high organic chloride. Is there any chemical treatment available. How can this problem be solved?	(6)
23/09/2018	Q:	In our refinery RFCC unit MAB was running with suction IGV mode since 2009 to 2017 AT 4350 RPM. During TA 2017, We changed the mode from IGV to speed control as suggested by OEM and the speed reduced from 4350 to 4000 and 6 to 8 tons/hr HP steam consumption reduced. Last month we try to increase the flow by 10,000 Nm3/hr we found the compressor suction side journal bearing temperature on increasing trend. After overhaul the machine in 2017 all the bearing temperatures in turbine and compressor found around 65 degC and the compressor suction journal temperature was 87degC.and maintained the same till last month. The oil analysis shows no any abnormality ( Low MPC, ISO oil cleanliness meets OEM's spec, oil colour is clear and no tracing of varnishing. RULER test given positive results) In the last one month only in compressor suction journal bearing temperature raising gradually up to 106degC ( High alarm 106, HH alarm 115)and then coming back to 96 and then raising again. This fluctuation raising and reducing is continuing. Mean time, as per OEM's recommendation we increase the oil flow to this particular bearing, reduce the oil supply temperature from 45 to 42 degC and compressor primary filters 50% replaced but no significant effects noticed, Our doubts are if the oil quality is bad then all the bearing temperature should fluctuate but we have increase the bearing temperature only in compressor suction bearing. Any one had similar experiences or can you share your thoughts for trouble shooting.
23/09/2018	Q:	In our sea water intake unit, the high flow sump pumps are designed and installed 10,000 m3/hr capacity each of pumps 6 numbers ( 5 running +1 standby) at 4.60 Kg/cm2g pressure. But after commissioning in 2009 we found the real demand is only 37,000m3/hr instead of 50,000 m3/hr of design. So we proposed to run only 4 pumps for the actual demand. We run only 4 pumps with throttle the discharge MOV to maintain the header pressure of 3.50 kg/cm2g and that situation, the pump discharge pressure is around 4.0 to 4.2 kg/cm2g. These pumps are not having any online monitoring instruments. The motor vibration taken for analysis with portable hand held vibration meters. Pump bearing temperature being measured through RTD and monitored in DCS. but for the suction bell area suction conditions, recirculation or cavitation are unable to monitor because of lack of technology ( as per vendor) After 8 years of operation, we start do major overhauling the pump one by one. During first pump overhauling, we noticed severe erosion in suction bell and diffuser area and not much pettings or erosion in the impeller except discharge erosion marks ( Impeller made out of Duplex stainless steel). After overhaul of first two pumps we noticed huge variation in power consumption between overhauled pumps and other pumps. We recently had two major breakdown with thrust bearing failure during pump scheduled change over period with different manner. During pump switching over 4 pumps are running and operator starts fifth pump and try to stop one pump. During this period, one of the pump which is running normal power and bearing temperature suddenly bearing temperature increased and touches the thrust pad and pump stopped. In the last two months there are two consequent failure of same nature and the operator unable to take any action to avoid this problem because no any instruments installed in the system. We get confused that during switching over, respective two switching over pumps conditions are normal but the same time an another pump thrust bearing failed within no time before take any decision by operator. During the failure, we observed the power consumption and flow rates of all the pumps were fluctuating of and suddenly the third pump thrust bearing temperature increased from 60 to 125 within few seconds. The bearings are tilting pad babitted lined. The oil condition found normal ( through oil analysis). If any one have similar problem on high flow open sump sea water intake system, please share your experiences and is there any instruments developed for the suction bell and suction well with detailed information of such instruments.
21/09/2018	Q:	In naptha hytotreater operating temp and pressure are 285 degc & 45 kg/cm2.in case feed loss emergency when again feed introduce & wht temp & pressure ?	(2)
19/09/2018	Q:	Can hot naphtha at 120 deg C be transported through ICPR pipeline?
09/09/2018	Q:	What are the benefits of saturating your raw natural gas feed with water?
08/09/2018	Q:	Naphtha vapours are observed at manway lid of roof top when its opened . Mild naphtha vapours are also observed at roof drain of the storage tank when its opened. Generally roof drain of the storage tank is kept in open condition only . The storage tank is of Internal Floating Roof type . Tank safe height is 10.75m . Generally tank height is maintained at 9 m or lower. Tank outlet Temperature is between 36 to 42deg. Let me know why naphtha vapours are emanating from roof tanks and roof drains. I dont think there is swivel joint leak .	(3)
03/09/2018	Q:	Coking Drum Switch Handling: Delayed coking unit, in a strict sense, is not a continuous process. Coke drums are operated in batches and downs stream fractionators and strippers are operated continuously. Each of the events during coking cycle , such as preheating, drum switch over , drum filling cause big disturbance to the downstream process. Advance Process Control may not be applicable for this operation. Can automating the SOP of Drum Switching improve the coking cycle?	(2)
31/08/2018	Q:	At present we face sudden increase in bromine index for benzen product in our aromatic plant. This cause our benzene product to goes to off spec as the BI exceeded the spec limit. We did several actions in order to improve the Bi level, hot clay treater for BT cut , one was isolated for replacement and only one remaining now in service and operated at higher temperatures, so is there any one has such experience. Please advise Also the Bz losses in raffinate product from extractive column was increased to allow more lifting of heavy olefin, but still the observed effect is very minor ,so please share with us your experience if any for such case.	(2)
30/08/2018	Q:	After cracking at VDU Heater, part of the Sufur on the AR(ATM Residue) is changed to H2S or Mercaptans and the stream flow to VDU Column. Part of the H2S and Mercaptan go to the VDU overhead. To catch the Sulfur (Specifically, H2S or Mercaptan) at Off gas Stream, Amine adsorber is installed at that line. However, when I review the Heat and Material balance (HMB), only H2S is considered at the stream and Amine cannot catch the mercaptan well. It is useful to catch the H2S only. Why the designer normally do not consider mercaptan catcher on the off gas stream? Is there any specific reason? For example, mercaptan cannot go to the VDU column overhead.	(2)
29/08/2018	Q:	Our FCC plant Downstream debutanizer tower having pressure increase issue due to exchanger perforamance and cooling water temperature issue, If only reboiler steam is reduced, Debutanizer OVHD C3’s composition is started increasing,Though Debutanizer’s purpose is to separate C3&C4 LPG (to Top) and Naphtha (To bottom),in case of sudden reducing reboiler steam, C4 component starts accumulation in Debutanizer column and C3 concentration at OVHD starts increasing,In fact, after only reducing reboiler steam, Debutanizer OVHD temp temperature started decreasing and Debutanizer OVHD pressure started increasing simultaneously.OVHD pressure may increase tentatively due to composition profile change in the column, then it was come down. Above Phenomena little tough to understand. Anyone kindly explain?	(6)
23/08/2018	Q:	I am working in VGOHDT. We are facing flaring issue intermittently in Fractionator overhead drum. We are using split range controller for maintaining pressure using fuel gas and excess pressure will release in LP flare. But we found that the overhead gas composition consist about 51% hydrogen ,23% methane and 14% nitrogen respectively which are non condensable gases. We increased HP steam in stripper column and reduce the pressure in Cold LP separator for removing it but problem persist. Kindly give suggestion to reduce H2 and methane to reduce flaring in Fractionator? We are operating fractionator pressure at 1kg/cm2 and top temperature at 106 deg c.Overhead Finfan outlet temperature at 45 deg.	(7)
19/08/2018	Q:	Did anybody model DHDT reactor in Hysys Refsys? In Hysys, hydrocracker template is used to model hydrotreater. How to adjust the fractions of kinetic lumps in feed fingerprint to match our original feedstock of the plant. Hysys estimates lumps fractions based on distillation data and other bulk properties of feedstock. Moreover, accurate calibration of the reaction rate parameters also depends on product composition especially in terms of C:H:N:S fractions. How to specify the fractions of C:H:N:S in the abscence of the data. Otherwise matching of hydrogen consumption with plant data is quite difficult.
19/08/2018	Q:	Usually, Steam is used for CDU's stripping. I wonder that can I use fuel gas that comes out of the top of the column for stripping? (& Recirculating fuel gas). I think that by using fuel gas as stripping medium, we can save money & there will be less corrosion at the top of the column. Can you tell me the advantages & disadvantages about this idea?	(3)
17/08/2018	Q:	In most cases, steam for stripping at the Crude distillation units. IF I use FUEL GAS for stripping at a Crude distillation unit ,what are the disadvantages? I think it would be nice to reduce the amount of steam used and to gain the economic benefits of it, since it is to recirculate the Fuel gas that comes out from CDU.
15/08/2018	Q:	We are facing problem while collecting Regen cat sample and spent cat sample. The sample point is located upstream of Regenerated Catalyst Slide Valve (RCSV). RCSV dp take-off points are also located near to the sample point take-off points. While trying to collect the regen cat sample, only hot dry gas is coming out from the sample point drain. No catalyst power is observed. At the same time, slide valve Dp is fluctuating badly and reaching trip value. We did reaming of the sample collecting line. Line is observed to be clear. Due to above problem, we could not collect regen catalyst samples for last few weeks. Kindly provide inputs on this, if any other refineries have similar experience. Similar problem is experienced with spent catalyst sampling also. The sample point is located upstream of Spent Catalyst Slide Valve (SCSV). While collecting the sample. Only dry gas is coming out and no catalyst powder is observed from the sample point. Kindly provide inputs on this, if any other refineries have similar experience.
07/08/2018	Q:	What are the safety precautions that must always be taken before entering the Confined Space Work in order to install the floating suction inside the tank?	(1)
07/08/2018	Q:	I would like to ask you about the problem that we are currently experiencing now is a sudden increase in differential pressure reading unusually for FILTER WATER Separate , And MICROFILTER . Which led to the change filter elements in each shipment quantity of up to 225000 litres only, although pursuing fuel shipments during the receipt, and the control checks of the fuel samples from the batch In terms of (water,sediments, appearance, electrical Conductivity and Density), All the results Within specification. What are the expected reasons that may lead to this sudden rise and exit of the differential pressure reading for the allowable limit?	(2)
06/08/2018	Q:	What can possibly cause an implosion inside FCC Reactor Riser. We presently have an implosion inside our Reactor Riser. The section /area assumed triangular in shape rather than the original circumferential shape. The incident has drastically reduced the I.D of the riser in that location, restricting normal flow through it.
03/08/2018	Q:	Anyone suggest me about increasing Propylene production in FCC without affecting stripper dp. In our refinery 2 Reactors or working in poly Propylene unit (PPU) for poly Propylene production and feed sent from FCC to PPU. Now 3 rd Reactor is commissioned in PPU but not any changes in FCC for increase Propylene production. So kindly suggest me which type of changes is required in FCC technology or process data's to increase Propylene production.	(4)
02/08/2018	Q:	What is the meaning "octane barrel"?	(2)
02/08/2018	Q:	Once we've removed acid gas, how do we regenerate lean amine in amine treating?	(2)
01/08/2018	Q:	We have a DIesel Hydrotreating Unit. In feed furnace we have Austinitic steel coils. During short shut down, UOP manual says to maintain the bridge wall temperature as 205 C, to prevent the polythionic acid corrosion. Can anyone tell the basis of temps as 205 C?	(2)
30/07/2018	Q:	Can anyone tell me about how Heat Stable Salt works?	(6)
28/07/2018	Q:	We are using a fuel gas fired heater with 8 burners and an fd fan. How do we increase the heat transfer of radiant zone? it is currently 60% and we wish to take it to 75%.	(4)
25/07/2018	Q:	What can be the reason of higher CCR catalyst dusting rate (elutriation and dust removal is working properly)? Which part of the reactor can be failed if only catalyst dust was found in reformate?	(2)
23/07/2018	Q:	What are the ways of cleaning fired fuel gas burners online? The heater is fd fan type and fuel gas is used. Also, what are the factors that could reduce its efficiency?	(4)
23/07/2018	Q:	Our refinery is planning to have a spare LPG loading pump with API seal plan 53B. With this seal plan, the barrier fluid will leak to LPG as part of the seal plan design. The concern is, the LPG will be loaded to tank trucks and no testing will be done once LPG was transferred so monitoring of the LPG quality after loading will not be done. With this, what barrier fluid will be compatible with LPG that will have no effect on its purity and might not cause any problems like clogging of pipelines due to propane vaporization?	(1)
23/07/2018	Q:	We are currently considering a spare LPG pump which has a seal plan of API 53D. The concern is that the LPG pump will load LPG to barges and with this seal plan, LPG contamination will occur since leak of barrier fluid to LPG is part of the seal plan. What barrier fluid should be used that is compatible with LPG that will not affect its purity?	(1)
22/07/2018	Q:	How does an FCC engineers control the riser residence time? What are the factors that affecting cracking residence time in riser? How do I calculate the residence time	(1)
21/07/2018	Q:	What back flush procedures are available for cleaning a heat exchanger? Feed is Meta and ortho xylene on cold side and eulibrium conc of xylene on others. What are the suggested ways for packinox online cleaning procedures?
19/07/2018	Q:	Can there be internal mechanical damage in pakcinox heat exchanger? if so under what conditions and how to check it? the temp range is 380 to 120 and 105 to 335.	(1)
19/07/2018	Q:	We are having some fouling in our packinox plate welded heat exchanger. Are there ways to do the cleaning without taking any shutdown? Also what could be the fouling materials ? The Heat exchanger plates are stainless steel s321 adn the feed is mainly c8 aromatics with some c7 and c9 gas is also used in the exchanger mainly containing hydrogen and ethane The temps are 105 and 334 for cold fluid and 120 and 384 for hot side	(6)
17/07/2018	Q:	Is their any long term health hazard of nucleonic gauges having Cobalt 66 as an radioactive element, used for level measurement in granular solid catalyst?	(2)
17/07/2018	Q:	In our Refinery, we are facing continuous emulsion and water carry over from wash water tower. What all can be the reasons?	(6)
16/07/2018	Q:	What are the materials that can corrode 321s stainless steel in an aromatics plant producing paraxylene?	(2)
16/07/2018	Q:	How do we improve the efficiency of a fired heater running on fuel gas and an fd fan?	(8)
16/07/2018	Q:	We have two Similar alfalevel packinox plate welded heat exchangers in our unit. One has a hot end approach of 38 while the other has 52 degrees what could possibly be the reasons of this difference? The process are similar in both with same streams and similar feed rate	(5)
16/07/2018	Q:	What are the factors affecting the efficiency of an Alfalaval Packinox plate welded heat exchanger? How can the efficiency be improved	(2)
09/07/2018	Q:	This is question is related to high potential gum in gasoline ex FCC. We have 2 gasoline merox reactors (A&B) and recently we have bypassed 1 reactor(A). Thereafter we observed some abnormal results of high potential gum (as high as 1300 ppm). On further analysis, we have checked merox inlet (B) and outlet(B) as well as combined outlet(A&B) i.e., Rundown. we have found high gum at inlet (1200 ppm) and immediate out let (500 ppm) and combined outlet (900). As per literature and my experience gasoline merox reactor doesn't contribute or treat potential gum but couldn't able to find the source. Also inlet is higher side, we have checked olefins at inlet (28% reported). what could be possible reasons for high gum at inlet and why are we observing gum abnormalities across reactor?	(3)
28/06/2018	Q:	Currently, I am trying to reduce the sulfur concentration from the hydro-treated naphtha. After reading up a few articles I came to the conclusion that the sulfur concentration is due to improper stripping of H2S from the stripper column. I have to improve the performance of the stripper column to reduce the sulfur concentration by adjusting pressure and R/F. How do I proceed? Is there any other sources of sulfur that I have to pay attention to?	(6)
27/06/2018	Q:	Feed incompatibility is normally a cause for fouling increase in the upper radiant section, due to asphaltene precipitation. P-value is normally used to measure asphaltene precipitation tendency in other processes (like visbreaking, fueloil, etc). Has anybody experience of the successful application of P-value (or any other similar) to predict compatibility issues in Delayed coker feed? If so, what is the minimum p-value recommended?	(1)
27/06/2018	Q:	High content of solid particles in crude oil or Delayed Coker feed can cause accelerated fouling in the furnace. Has anyone experience on how to measure solid particles concentration and particle size distribution in crude and/or vacuum residue? I have seen the use of laser difraction or particle counter for other products (kerosene, lubricants, etc) to measure both total content and particle size, but I am not sure if this could be succesfully applied to vacuum residue. What is the maximum solid concentration recommended to avoid fouling issues? What is the maximum solid particle size recommended?	(4)
27/06/2018	Q:	In one of our Delayed Coker units we suffer frequent re-foam events: sudden foaming during the steam stripping stage. These events sometimes happen when we turn to stripping to blowdown, so probably the main reason for these events is depressurizing of the coker drum. However, other foaming events happen in the first stage of stripping, when we have stopped feeding VR and we are stripping to main fractionator. We always carry out the stripping following the same procedure (steam feedrate, time, etc). However, with some vacuum residues we suffer these re-foaming events, while other don’t foam over. My questions are: – What are the best practices to avoid re-foam during steam stripping? – What are the main variables that cause re-foam? – Is the re-foaming dependent of the VCM of the coke? (this unit has a very short cycle and have a higher VCM in coke) – Is the re-foaming dependent of the coke morphology?	(1)
27/06/2018	Q:	Silicon-based antifoams (PDMS) is routinely injected in the top of coker drums to reduce foam height. However, it has been claimed by some refiners that injecting the antifoam directly with the vacuum residue in the feed line, before entering in the drum, is more effective, with a fast response and a lower dosage required. Has anybody experience with this kind of injection? If so, which is the optimum injection point and which are the issues that must be taken into account?
27/06/2018	Q:	How do we calculate the pressure drop of the inlet and outlet line of the reboiler?	(2)
20/06/2018	Q:	At a Visbreakeing unit(coil type visbreaker) I worked on, the gas oil was drawn from the main fractionator to a gas oil stripper and then transferred via a pump to visbroken bottoms stream. We faced frequent high ampere problem at this pump. The pump returned to its normal amperes after its impeller was cleaned. Coke deposition was found on the impeller, suction strainer and discharge NRV. We had cut stripping steam to the gas oil stripper previously to decrease the overhead naphtha, however it was taken back in service to get the system back to 'design' conditions and doing so, reduced the frequency of high amperage problem. (The pump delivers 2~3 m3/hr gas oil flow. At higher flows it reaches/exceeds FLC(full load current). The pump's design minimum flow is 12 m3/hr.) Can anyone please suggest possible remedies to this problem, specially the coke deposition at pump's impeller? Is it fairly common to have coke deposits in visbreaker gas oil lines if so what are some practices to reduce/remove the coke?	(3)
14/06/2018	Q:	What is WSIM for ATF ? How will it affect the product performance/ quality?? What are the measures to be taken to control WSIM ?	(2)
11/06/2018	Q:	In our NHT unit of isomerization plant we are frequently facing issues of reactor effluent air fin coolers tube leak. It has happened twice in 6 months and this time around afc inlet line developed leak as well. Feed composition total Sulphur is 140ppm and chloride is 2ppm. Our wash water injection is continuous and injection rate has been increased to twice the design flow as recommended by licensor. In recent shutdown salt deposit was also observed before water injection point in last 2 effluent exchangers. Boot sample result is having pH :5.7, cl : 70ppm & iron content : 50 ppm. Our unit is designed for handling 17ppm chloride impurities in feed but still the corrosion rate is higher. Please suggest any solutions.	(4)
09/06/2018	Q:	Currently it has been observed in CRU unit that DP across the 3rd reactor is increasing from 0.3 to 0.56 during raining time and again coming down to 0.3 after the rain stop. So, what could be the reason behind it? Is it happening due to temperature reduction of the circuit or DP meter malfunctioning during rain?	(1)
06/06/2018	Q:	I am a process engineer and recently joining CCRU with Axens technology, I want to understand how can we know if cl/water injection in the regenerator is at the optimum What can give us an indication based on your experience?
31/05/2018	Q:	In distillation columns, why are trays more widely used than packings for vapour-liquid contact? What are the advantages of using trays over packings?	(5)
31/05/2018	Q:	On the top of a flare tower, there are certain "star" shaped objects surrounding the top. What are the uses of those?	(1)
31/05/2018	Q:	What is the approx. percent efficiciency/effectiveness of a shell and tube heat exchanger, double pipe heat exchanger, plate heat exchanger, cooling tower and regenerative heat exchanger?
29/05/2018	Q:	I am into esterification of benzyl group. We manufacture Benzyl Acetate. The problem we face is chocking of column. The salty material gets trapped into paul rings (packing for column), resulting into colouration of end product. Is there any chemical way out of it?	(1)
22/05/2018	Q:	We're experiencing an increasing loss of heat transfer efficiency in our shell and tube heat exchangers. Has anyone found any technologies for cleaning exchangers online that does not require a shutdown of the distillation unit at all? Something for both sticky/polymeric as well as water scaling would be most desirable.	(8)
22/05/2018	Q:	we have a reciprocating compressor, consisting of 2 stages (1st stage 4 cylinders & 2nd stage 2 cylinders), our problem is recently we are facing high temperatures in cylinder 1, but all other cylinders are having normal temperatures. So what could be the problem of this high temp in cylinder 1 although all valves and rings were replaced with new. Do note that cylinder 1 & 3 are connected to 1 snubber , and 2 & 4 are connected to another snubber.	(1)
20/05/2018	Q:	We are using born heaters for CRU unit where all heaters inlet lines are covered with ceramic fiber Jacket as air seal purpose but few outlets pipeline from radiation section are not covered. Currently bluish flame is observed coming out from gap/clearance between the outlet pipe and and heater shell casing pipe during night time. What could be the reason for that (from 3rd Heater which has no convection section but has common stack with 1st & 2nd heaters) ? Another day in the same heater, red hot spot at the inlet of pilot line (pressurized ) was observed and became normal just after the pilot air line had been isolated/closed. But at the pilot inlet found little flame coming out from pilot fuel gas line and disappeared when pilot fuel was isolated. Although pilot should remain close just after the main burner lighted but in our case we keep the pilot in on position all the time. What could be the reason of this red hot spot? We have VFD operated blower , some time blower noise becomes very high and try to reduce the noise by adjusting the VFD speed . So, what could be the reason for high sound ?	(3)
16/05/2018	Q:	What will be the approach or methodology to work when serving a rotary atomising burner burner of a steam boiler?
13/05/2018	Q:	What are the differences between hydrogenation and hydrodesulphurization?	(2)
12/05/2018	Q:	In case of fluidized naptha cracking heat balance is an isssue, where not enough coke is generate to provide the endothermic heat. In such cases can pet coke be used in the regenerator to produce the reequired heat? If Possible what adverse effects can it have?
11/05/2018	Q:	What is the temperature and pressure maintained in the fractionator of a delayed coker unit? Does it not cause premature thermal cracking of the reduced crude oil even before it enters the coke drums?	(3)
10/05/2018	Q:	I have read somewhere that; "Steam is injected in the furnace to prevent premature coking". How is that possible?	(2)
05/05/2018	Q:	In our Propylene Recovery Unit (PRU) why is reflux drum mounted above the condenser? It means condenser on ground floor and reflux drum above the condenser, but other distillation column generally condenser on top and reflux drum below the condenser.	(4)
02/05/2018	Q:	We have three smr plant having 750nm3 capacity.one of the smr syngas header external paint was faded and peeled out from its position. Checked skin temperature on the surface, found higher than normal. What is the cause of burnt paint? Is there any special procedure for measuring skin temperature on syngas header like reformer tube temp measurement?	(1)
26/04/2018	Q:	What are generally the end of run characteristics of a catalyst? What are the signs indicating the need for catalyst regeneration?	(5)
26/04/2018	Q:	Why is water injected into catalyst used in CRU operations?	(3)
18/04/2018	Q:	What is the typical distribution of catalyst carbon content (coke in wt%) in 4 reactors of CCR (continuous catalyst reformer unit)?
11/04/2018	Q:	Which companies have particular and extensive expertise in executing turnaround of stacked type FCC Orthoflow Units?
08/04/2018	Q:	I have difficulty in drawing product from my side stripper of the atmospheric distillation tower. Whenever I raise the Stripping steam rate, this problem will occur. My initial suspect is due to the hydraulic limitation when the stripping steam is above a certain value. The technical reasoning would be when there is high vapor rate rising up the stripper tower, the vapor load creates high pressure drop across the stripping trays. Liquid flowing from the top will ultimate be restricted from flowing down the stripper tower and creates hydraulic limitation. Do you all agree on this observation?	(3)
07/04/2018	Q:	High AT in transfer line beetween heater and drum. After a maintenance shut down of the unit where we have some modifications in this pipe, the AT between heater and drum has increased from 18ºC until 27ºC (average values). We process heavy crudes with a 25%w concarbon and 20% C7 asphaltene. For this crude, which is the minimum inlet drum T in order to avoid problems with coke formation? (Our current minimal T is around 468ºC) Which is the maximum coil outlet T to avoid aceletated fouling in the heater? (now we would need to increase up to 500ºC) We use fierglass insulation in this pipe. Have you tested any better insulation (e.g. aerogel)? We are thinking to try an electric heat tracing, do you have any reference of this option being used in delayed cokers? Would it cause fouling in the pipe?	(3)
25/03/2018	Q:	In our FCC, we process two feeds namely, Coker Gasoline and Mixed feed (Mixture of Residual crude Oil & Coker Fuel Oil). In one of our unit shutdowns, we found very hard coke formed in the Riser at the area of feed nozzles. We did not observe this type of phenomenon in past. What would be the probable causes for formation coke in the Riser?	(4)
18/03/2018	Q:	In our HMU plant, we are going to do Pre-reformer reduction but we don't have any water collection system. Can anybody explain how to do the reduction and how to ensure that reduction of Pre-reformer is complete?
17/03/2018	Q:	I have a question on determining if the atmospheric residue is lighter from the atmospheric distillation unit. I know I can compare the T5 distillation of my residue to see this has been lower than historical values... I think if I were to check the delta across my stripping section has increased with a constant stripping stream ratio, that'll probably give some indication too. Does anyone know what other methods can be used to check if I am actually dropping any HGO or light molecules down to the atmospheric resid layer? Conclusion: Yes, I have compared the T5 of my residue and also the T5 of the vacuum tower feed and they are lighter. My stripping steam, FZT were lower than usual during those period while my FZP was higher. I think in conclusion, those should have actually caused the drop of lighter molecules to bottoms due to insufficient uplift of molecules.	(2)
16/03/2018	Q:	For a reboiler furnace in NHDT, is better: to have reboiling liquid 34 m3/hr and furnace COT at 208 C or to have reboiling liquid flow at 40 m3/hr and furnace COT at 203 C? Note: Reboiler furnace is the limitation for maintaining max throughput.	(7)
14/03/2018	Q:	In our FCC unit regenerator outlet flue gas goes to flue gas boiler and generate 95 TPH high pressure steam. We are doing 3 times soot blowing in a day (24 hrs) for remove catalyst from water tubes. Can water tubes damage or effected due to many times of soot blowing?	(1)
14/03/2018	Q:	For hydrotreater units, does the Iron content in stripper overhead receiver boot water has the same limit for steam stripping and heater reboiled stripping? What is the allowable limit of Iron content in boot water for both the cases?
13/03/2018	Q:	We have kerosene hydro bone unit (desulphurization unit) , we faced technical problem which is non-improving (WSIM) water separometer index modified specification . what is the mean thing that effect in (WSIM), and how can we improve it? By the way, the reactor system of kerosene hydro bone unit is isolated.	(3)
12/03/2018	Q:	What does it mean by metallic and acidic side of a catalyst( e.g. Platinum)?	(1)
10/03/2018	Q:	In Hydrogen Generation Unit, Total Organic Carbon (TOC) is observed high in process condensate water collected from process condensate separators. What could be the reasons n how to rectify it.
10/03/2018	Q:	Why hysys process simulator don't have actual volume flow among inputs, when you have only the volume flow, although the stream is gas you must put the liquid volume flow, so i make manually calculation before i put the value to prevent errors?	(1)
10/03/2018	Q:	At Temperature above 370'C in a CDU? What cracks? - Diesel? (Asked b/c FBP of Diesel is 370'c) - Ends heavier than Diesel?
09/03/2018	Q:	In Hydrogen generation unit, it is observed higher total organic content (TOC) in process condensate water collected from condensate separators. What could be the probable reason and how to mitigate/ rectify?	(1)
05/03/2018	Q:	What's a wash tray/section in a CDU? And how it is vulnerable to coking?	(3)
03/03/2018	Q:	Temperature of the CDU feed is always less than 370'C because temperature further than that will cause cracking. Cracking of what? Cracking of Diesel? Or cracking of heavier ends? I'm asking because FBP of Diesel is 370'C.	(4)
01/03/2018	Q:	Are there any differences between a naphtha hydrotreater and a diesel hydrotreater?	(5)
01/03/2018	Q:	Is there any other chemical we can use than of PERC in UOP Platforming process?	(2)
26/02/2018	Q:	I have been entrusted with the task of assigning line numbers to refinery circuits, not something of which I have any experience or training. Are there any industry standard numbering conventions?
25/02/2018	Q:	In FCC unit, Does PSD of the catalyst effect the catalyst loss through stack?	(3)
25/02/2018	Q:	In our FCC unit, We have two temperature indications in the stripper bed. During start-up of the unit, we observe the two temp. indications show almost same temperature, but during normal operation of the unit, the temp. difference of nearly 100 deg. C between the two temp. indications is being observed. What would be the reason?	(1)
25/02/2018	Q:	In Hydrocracker unit, after revamp, quench pipe is routed below the catalyst support grid. The gap between support grid and quench pipe is filled with ceramic rope. The quench pipe is supported with C type support. With this arrangement unit has run two cycles without any problem. But at present cycle, one of the bed DP started rising. After shutdown and reactor opening, it was observed that catalyst migrated through the gap as ceramic rope damaged. Also the quench pipe rested below the support grid was observed to be lifted up from C support. During one month of unit run after catalyst loading, there were no emergency or sudden shock to the system so that quench pipe should lift. How has this Ceramic rope become damaged and Quench pipe lifted up?	(2)
15/02/2018	Q:	Why is Platinum used as a catalyst in Reformer? Why not any other element/compound? What is its interaction with hydrogen and hydrocarbon?	(4)
15/02/2018	Q:	Why is the top of a CDU normally wider than its lower body?	(6)
14/02/2018	Q:	Can anyone please tell me how to identify whether the liquid is forming a channel in the reactor packed bed? Also please confirm the effect of pressure drop across the bed if channelling occur? will it increase or decrease? In my understanding, the pressure drop will increase. But I need documents to support my argument. Please help!	(3)
14/02/2018	Q:	Is there anyway to reduce hydro-test pressure of equipment which having very high hydro-test pressure?	(1)
13/02/2018	Q:	In our FCC, catalyst has been observed to get carried over to the fractionators during start up activity. This upsets the fractionators bottom pumps. What can be probable reasons for such carry over and how this can be mitigated?	(4)
12/02/2018	Q:	In our kero minus hydrotreater unit, employing Albemarle catalyst, I witnessed an abnormal behaviour in preheat exchanger and HP separator. A pressure gauge is installed at downstream of tube side of last preheat exchanger that essentially indicates pressure drop in tube side (Reactor downstream) of exchangers. The said gauge has hunting of approximately about 1 bar. I first wonder why is this happening as there is no chance for continuous pressure fluctuations in the circuit. I also presumed gauge to be faulty and asked maintenance section to replace it, but the problem still prevails. Then I found the level fluctuations of the approximately same kind in HP separator. The level transmitter in our DCS didn't indicate this rise and fall, but the level glass proves this abnormality. I am unable to understand this behaviour and seek experts advice.	(2)
10/02/2018	Q:	What is the need of using three reactors in Platforming instead of a single one? Plus, do different reactions take place in each reactor? If so, what's the feed of the second and subsequently the third reactor?	(3)
07/02/2018	Q:	Kindly if any one can tell me about preactivation step "precoking" is it necessary and which type of catalyst is used for and what is precoking function?	(2)
07/02/2018	Q:	I am doing some research for a paper on gas treatment and would like to know an estimate of the cost of a planned shutdown in a gas treatment plants. I don't need precise number but some "rule of thumb" estimates would be very helpful. Taking an average size plant of around 150 MMSCF/Day that has de-sulpherization, de-humidification, mercury removal and condensate removal. 1/How often does a planned shutdown occur? 2/On average how long is the plant out of action including shutdown down and start-up? 3/What are the normal activities performed at a shutdown? 4/How many man days are involved including: a/ planning, b/ hazops, c/ scope of work, d/ method statements, e/ risk assessments, f/ permits g/ anything i forgot? h/ performance of tasks for shutdown maintenance and startup
06/02/2018	Q:	I am looking after Atmospheric Distillation unit. Lab results states that RCO flash is always less than HGO (Heavy gas oil/ JBO) flash. As RCO is heavier than HGO what is the reason behind it? HGO product passes through a stripper; can this be the reason?	(4)
06/02/2018	Q:	I am working in NHDT-CRU. In our unit NHDT HP separator is in horizontal position whereas CRU HP separator is in vertical position. And KHDS unit HP separator is in vertical position. NHDT system pressure : 20 Kg/cm2-g CRU system pressure : 20 Kg/cm2-g KHDS system pressure : 25 Kg/cm2-g What can be the possible reason ?	(3)
26/01/2018	Q:	In our refinery, C5/C6 isomerization process uses zeolite based catalyst and reaction loop pressure is maintained at 18 kg/cm2g. The ISOM unit uses H2 makeup from CRU and there is continuous purging of recycle gas from ISOM separator. the design basis is 1635 kg/hr of purge gas (contains 187 kg/hr of H2) with 63 vol% H2 purity. No HCL. 5-12 ppm of H2S. Please advise how economical will it be to recover the H2 from purge gas using membrane separation process? is there any refinery currently using membrane separation process for recovering H2 from purge gases at 18 kg/cm2g?	(5)
22/01/2018	Q:	How does the introduction of Superheated Steam into a CDU disturb the partial pressures thus lowering boiling point?	(4)
16/01/2018	Q:	How to calculate vacuum heater residence time? What is the limit to avoid coking?	(3)
14/01/2018	Q:	How can we calculate the draw off temperatures of Kerosene and diesel to be with drawn from CDU? Similarly what would be the procedure in case of LVGO and HVGO in case of Vacuum Distillation?	(1)
14/01/2018	Q:	In our FCC 4 PDT A,B,C,D are provide to show RCSV Differential pressure , all PDTs are N2 purged with flow orifice and flow orifice bypass. from some days we are facing dp problems in C and D. If we are open flow orifice bypass of C and D than DP maintain and when we are close flow orifice bypass DP disturb of C and D. What may be reason?	(1)
09/01/2018	Q:	Recently we have done the skimming of NHT reactor and now want to reuse all the actispheres that has been removed from the top layer of catalyst bed . So, is there any problem to clean it by dissolving into the Heavy Naphtha and inert it with the N2 before reusing in the reactor again?
04/01/2018	Q:	Is there any quick method for theoretical estimation of hydrogen production from UOP R-56 platforming unit? We are facing the problem of high LPG production (Higher cracking rate & lower delta T in the last reactor) after the second cycle. We tried to adjust Chloride and condensate injection rate but couldn't get the desired output. Does the regeneration effectiveness cause these changes? One more thing, during the reduction in the regeneration, water produces through hydrogen reaction with the oxidized catalyst. My question is how do we know when to stop reduction? @Ralph Ragsdale We regenerate our unit 10 months back. and from the beginning, we are facing high LPG production problem. I believe our system is wet but don't know why. might be the improper regeneration. water production during regeneration is what I worried about. I think we didn't drain water up to the required limit. Only because we couldn't find any limits in the first place in Manuals.	(4)
03/01/2018	Q:	I am currently working in a project which includes a decrease in the operating pressure of the stripper in the hydrobon unit (hydrotreatment of naphthas). Due to this decrease the temperature on top of the column will decrease too and the area of the aereocondenser at the top of the column won't be enough to achieve the desired temperature. For this reason I am designing a new trim cooler that will use cooling water to achieve the current temperature before the liquid/gas separator. To avoid revaporization downstream the trim cooler will have to cool down both the vapour and the liquid stream. The inlet current is 7.300 kg/h with liquid phase stream being 6.000 kg/h. I have simulated it with Aspen EDR and the resultant heat exchanger will have to operate 40% flooded in order to cool the liquid phase stream. To achieve and control the level of flooding in the trim-cooler two ideas come to my mind: Level control and dam baffles. This is the first time that I design a trim-cooler but I have checked out the designs of other trimcooler and I have NOT seen any level control instrumentation or dam baffles. Can anyone familiar with the design of trim coolers comment please?	(1)
28/12/2017	Q:	We want to increase the capacity of the stripper in our hydrocarbon unit. There is an aerocondeser for the stream leaving the top of the column. We want to increase condensing capacity by means of a trim cooler that would be placed next to the condensers. It will receive a total of 7,3 tones/h, 1,3 t/h vapour and 6 ton/h liquid. I have simulated with ASPEN EDR the new trim-cooler that will operate with cooling water (tubeside). To avoid revaporization downstream of the trim-cooler the liquid needs to be cooled down as well as the condensing vapour. The software indicates that the required area for cooling the liquid is 45% of the total number of tubes. I am specifying 30% cut baffles but doing a quick number tells me that liquid will just pass and there won't be any flooding. Has anyone ever designed a trim-cooler? How do you accomplish the flooding of the heat exchanger? There are several options, I find that the most suitables ones are: 1)A dam baffle that will flood the shell until the desired level. 2) A level control loop (level transmitter control valve) We have other trim-cooler installed in other units, hydrocracker for example, but I have reviewed the trim-coolers drawings but there is not dam baffle or any level controlling loop.	(4)
28/12/2017	Q:	i have corrosion problem in overhead system reflux pump and accumulator this system consist of atmospheric tower and overhead condenser (4 bundles with crude in tube side) then accumulator with water boot the and reflux pump to atmospheric again. we just add corrosion inhibitor in overhead line without neutralizing amine due to old recommendation based on high accumulator temperature. temp in accumulator 115-130 c and pressure 1.1-1.4 barg .note that no water accumulated in vessel boot .	(6)
27/12/2017	Q:	At the beginning of our NHT project ( catalyst HR 506), sulfiding was done by pre-wetting condition and still now same oil in procedure has been followed that means Oil in start with DSN at 140 degC through reactor and DMDS injection start at 180 degC to maintain the H2S at 180 to 200 ppm. Finally at 280 deg C, DSN is replaced by Heavy Naphtha (HN). Mentionable that our HN is sweet so we have to inject DMDS all the time to maintain H2S limit within 180-200 ppm in the recycle gas to keep the catalyst in active phase. Now my question is that what is the demerit now to do the normal start-up by starting oil-in directly with HN at 280 degC without pre-wetting ? Is there any chance of losing Sulfur from catalyst during H2 rich gas circulation within 6 hrs to raise the temperature to 280? Is there any impact on catalyst to increase the differential Pressure (dp)of catalyst bed for pre-wetting or direct oil-in procedure? Currently dp across the reactor bed observed increasing little bit after each normal start-up by pre-wetting oil-in procedure -what could be the root cause of it?	(1)
26/12/2017	Q:	We have SS321 tubes for one of the furnaces. After welding of the SS321 tubes, what is the recommended PWHT cycle? I understand that to avoid Knife line attack in SS 321 and so to dissolve Chromium carbide and precipitate Titanium carbide, PWHT is done within 850 DegC to 1250 DegC. Some procedures recommend for 2 heat treatment cycles (1050 DegC 1 hr soaking with water quenching and then 900 DegC 4 hrs soaking with water quenching) whereas some procedures ask to do one heat treatment (1050 Degc 1 hr soaking with water quenching). I also saw a procedure asking for 900 DegC with slow cooling (air cooling) and not fast cooling (water quenching). So, I request you to provide clarity in number of heat treatment cycles, soaking temperature, soaking time and quenching medium (air/water) and its metallurgical consequences ?
22/12/2017	Q:	Have anyone use platforming continuous catalyst circulation technology experience catalyst plugged in the bottom of Reforming reactor after turnaround? What may inhibit the catalyst flow to the regeneration section from bottom of reactor (catalyst collector)?	(3)
22/12/2017	Q:	We have synthesis gas centrifugal compressor of 4 stage. Recently a problem regarding the level of seal oil overhead tank of 3rd stage is found. As level goes down whereas both the seal oil pump running. Can u suggest the action to be taken?
13/12/2017	Q:	Why does PH increase in effluent water from electrical desalters? And what is the reason for monitoring such PH levels?	(2)
12/12/2017	Q:	In the regeneration of catalyst, the SR of catalytic reforming unit fixed bed reactor. Could any one tell me why we keep the O2 between 0.3-0.8mol % in the carbon burn step. Also, in the oxidation step should the O2 be kept at10mol%? Another thing, what will happen to the catalyst if the sulfur in the feed is more than 0.5ppm?	(1)
09/12/2017	Q:	I am interested in the forum's experience on (full) reusing of processing condensates from conventional Natural Gas / LPG steam reforming Units (from all major licensors). I have experience with an ex-KTI (Technip) based NG SMR whereby process condensates are fully a) fully reused in the BFW system post a simple air stripping for removal of dissolved CO2 and b) steam produced (at 40 barg) is used for both internal needs and export to other process user and a steam turbine / generator. The system operates as such successfully for many years. I understand that recent designs (and at higher steam pressures) call for either a) the steam not to be exported or b) a dual steam raising system one for internal consumption (where the process condensates can be recycled) and another for export steam on clean BFW. This, due to issues with organics difficult to be removed from the BFW and generated in the shift reactors. Any experiences / views on this ?	(1)
09/12/2017	Q:	Can anyone please tell me about the basis of feed cut in and cut out temperatures? How are these selected? Why is feed cut out temperature always higher than feed cut in? And how do you calculate hydrogen partial pressure in kero minus hydrotreater, bearing in mind the unavailability of GC?	(1)
06/12/2017	Q:	I wanted to understand the constituents that cause the coloring in say natural gasoline. I'm working on an NGL fractionation unit & the Debutanizer bottoms is routed to a Decolorizer column. Now, I'm not sure what is removed to actually meet the D-156 saybolt color 20 specification. its gas condensate...C5-C20, mercaptans inc heavy mercaptans i.e c5,c6 mercaptab, BTEX. No MEROX unit on the feed stream..so no DSO. Also no N2/ nitrogenous compounds. I would be very grateful if somebody could share the HC compounds contributing to color other than the obvious DSO/ N2 compounds.	(1)
01/12/2017	Q:	In hydrotreator, why do we consider hot separator top pressure as a system pressure? Why do we not consider reactor top pressure or reactor bottom pressure or inlet hydrogen pressure?	(1)
30/11/2017	Q:	How would you design a reformer used in production of hydrogen from used oil?	(1)
22/11/2017	Q:	I have a question about light alkanes isomerization catalysts. UOP experts suggested that the silicon can poison hydrotreating and hydrocracking catalysts due to damaging the Al2O3 structure. I wonder if silicon can also poison the light alkane isomerization catalyst, such as chlorited Pt/Al2O3 catalyst, Pt/SO4 catalyst which contains Al2O3 as coagulant, and Pt/zeolite catalyst? Our partial feed for light naphtha isomerization unit is the raffinate from Benzene extraction unit, the raffinate is possible to have silicon due to using defoaming agent at top of benzene distillation extractor.	(3)
17/11/2017	Q:	I'm working in ExxonMobil licensed FlexiCracking unit. After emergency shutdown in unit, Slurry PA, HCO PA, LCO PA flows are disturbing. Slurry PA flow is establishing after 2 - 3 trials. Whereas LCO PA & HCO PA were unable to maintain even after opening cutter to both the circuits. Immediately after unit trip, we are closing stripping steam to LCO, HCO strippers, LCO PA, HCO PA pumps are drained thoroughly before placing it in service. LCO PA, HCO PA are slowly dropping to zero. that time main fractionator top temp increasing too high to >170 C. How can I maintain steady LCO PA, HCO PA flows during unit startup, while maintaining main column top temp at 140 C. Please help me how can i maintain steady PA flows during startup so that MF temp profile is steady.	(2)
13/11/2017	Q:	I have question regarding the Reverse Osmosis membranes (RO) and we use anti scale chemical for the RO unit , please could you tell me what will be the effect if we inject the anti scale over rate injection and under rate as well? Is there a specific test to do for this chemical (anti scale ) to find out the optimal performance?
13/11/2017	Q:	The chloriding agent used in fixed bed semiregenerative platforming unit is TCE mixed with platformate to be injected in the system. Is there any issue with mixing it with the run down platformate to the catalyst. Another question, what are the factors to be considered when changing the chloriding agent for example PERC ? Is there any impact?	(3)
05/11/2017	Q:	Why do we need to keep antisurge valve open 20%to30% open in RGC and why have they given margin for antisurge controller PID?	(1)
04/11/2017	Q:	How do you calculate overflash in a crude distillation column?	(2)
30/10/2017	Q:	We are interested in reducing treatment load on spent caustic treatment unit. Then we are going to idle visbreacker gasoline treatment process by feeding it to other units. At present we use sweetening process (washing with caustic and converting with Merox) for visbreacker gasoline product. The problem regarding to produced spent caustic as byproduct is unreliable spent caustic treatment process to meet the environmental specs. The alternatives are suggested as follows: 1- introducing to heavy naphtha hydrotreater unit (unifiner) 2- introducing to Kerosene/diesel hydrotreater unit 3- introducing to hydrocracker unit 4- sending to crude storage and refine it again Would you please explain pros and cons about the abovementioned alternatives? What is the best alternative?	(3)
25/10/2017	Q:	What is the effect of free water in Naphtha feed on catalyst in Hydrogen generation unit? What % of water can be allowed in feed?
25/10/2017	Q:	What are the probable causes of Aviation turbine Fuels failing in Jet Fuel Thermal Oxidation Test? Is there any specific content in jet fuel feed like contaminants/residue/emulsion/caustic or hydrocarbon species which leads to JFTOT failure?	(2)
24/10/2017	Q:	Is stripped water useful for amine dilution and caustic dilution?	(1)
23/10/2017	Q:	In our plant, we have 7 heaters for Distillation unit, NHT and CRU unit. Fuel Gas that is generating from CRU Unit (80% H2) is being used for all those heaters. But, gum or glue is observed at the pressure regulating system which is situated on fuel gas line which mean it is depositing at the reduced area due to restricted flow path. My question is that if the olefin/unsaturated compound present in the desulfurized naphtha ( CRU Feed), is it getting Oxygen from Oxygenated compound like MTBE, TAME or Methanol and so on to form gum or is it getting O2 from the existing system? If this is not the case then what could be the reason of forming gum in the fuel gas?	(3)
22/10/2017	Q:	In my unit, Main fractionator is running steady all parameters are normal, suddenly one day, CLO Flash point came very low compared to earlier it was high(75-89 C) and used to fluctuate by 10 C. Now flash is always coming below 60 C. We have increased HCO Stripper stripping steam and Main Column bottom stripping(Agitation) steam to maximum but still CLO flash is not improving. Checked for FLO to bottom circuit, all locations blinded. Main Column Flash zone temp & bottom temperature are 356 C and 349 C respectively. Kindly suggest best ways to improve CLO flash and how to find out the problem?	(3)
21/10/2017	Q:	When do we use Merox process instead of hydrotreating? Is sulfur the only parameter to choose the process?	(4)
18/10/2017	Q:	Standard Operating Practices/Procedures for Hydrocarbon Draining is Draining the Hydrocarbon in Close Drains. Is there any Mobile/Portable Facilities/Skids available for doing the Hydrocarbon Draining and Collecting?	(2)
12/10/2017	Q:	How do we calculate the bblpd to mmtpa if we have one month shutdown once in a year?	(2)
10/10/2017	Q:	How to control same bed outlet temperature in hydrotreater reactor?	(3)
09/10/2017	Q:	If exothermic reaction temperature exceed beyond 30 degree C at the outlet of hydro-treating reactor bed then what will be the consequence? Whether the result of that coking or sintering of catalyst might take place for Co-Mo Catalyst? If feed cut and temperature rise above 300 degree C then what will happen to catalyst? Additional: If exothermic reaction temperature exceed beyond 30 degree C at the outlet of hydro-treating reactor bed (Normally maintain at 280 C) then what will be the consequence? Whether the result of that coking or sintering of catalyst might take place for Co-Mo Catalyst? If feed cut and temperature rise above 300 degree C then what will happen to catalyst? FYI, when NHT was restarted with HN feed, pressure drop was increased from 0.67 to 0.79. So what could be the cause of this pressure drop? Ravinder Chib said nothing will happen to catalyst but is there any chance of coking as feed suddenly cut for 30 minutes long and temperature of reactor bed was increased for 30 minutes?	(2)
06/10/2017	Q:	How to control IBP, FP and Ep for diesel, kerosene and light naphtha products?	(4)
02/10/2017	Q:	What is the animation video link of FCC reactor and regenerator working, cracking and catalyst circulation?	(1)
28/09/2017	Q:	What are the criteria for sizing a restriction orifice?
27/09/2017	Q:	In our hydrocracker unit the system pressure 140 bar. In case of recycle gas compressor get trip and we able to start within 5 minutes at that time system pressure reach 110 bar. In the recycle gas vendor provided booster pump for primary seals in case of DP less than 10 bar booster pump will start automatically.My question why we need this booster pump if we start the recycle compressor without this pump at system pressure 110 bar what the causes and effects?	(1)
24/09/2017	Q:	I'm working in fixed bed catalytic reforming plant and would like to ask you about measuring the R-86 catalyst lifetime to help me out to initiate the catalyst utilization plan during the existing cycle. Also, has anyone have a catalyst performance report who is willing to share it with me to use it as a guidance when writing mine, it would be highly appreciated.	(2)
20/09/2017	Q:	Is there any way to clean 80 inch submerged intake seawater in water-free situation? In other words, is it possible to plug both side of 2 km pipe and discharge the encapsulated water?	(1)
11/09/2017	Q:	In Hydrocracker fractionator, ATF draw temperature is 220 Deg C which is going to side stripper. Side stripper is having reboiler which is taking heat from diesel pump around. The reboiler outlet temperature is about 250 Deg C.It is observed that when the ATF draw increases beyond 50 M3/hr. it is failing in Flash while maintaining the temperature condition same. Column is operating at 2.1 Kg/cm2g pressure. Where is the problem?	(5)
10/09/2017	Q:	One of the PSU owners is asking for guarantees at the outlet of Propylene Recovery Unit (PRU). The basic design of this unit is in Consultant's scope. At present the poisons in feed such as Methyl Acetylene, Propadiene, Arsine, Phosphine and many others are not known. In fact feed composition is not known at all. However the poison levels in the product are fixed and are to be guaranteed. The propylene from PRU is routed to Polypropylene Unit. The feed to PRU comes from LPG treatment unit which in turn receives it from RFCC unit. Please advise whether it is wise to give guarantee of product at the outlet of PRU.	(3)
08/09/2017	Q:	I am working in UOP hydrocracker unit. In our feed filter backwash frequency is very high since one month. We have cleaned the filter elements one by one. After cleaning of filter some improvement seen for some days but then filter starts backwashing again. we have also checked CCR and asphaltene and all are within range. we process VGO and HCGO in our hydrocracker unit . It is recycle type with 97% conversion. please suggest remedy.	(8)
05/09/2017	Q:	How to control fractionator profiles in hydrocraker unit?	(3)
05/09/2017	Q:	What's cross limiting control in heater forced draft type. Why stoichiometric air and Wobbe index given in the calculations?
31/08/2017	Q:	What are the normal metal contents in vacuum residue and coke? How does it affect the final price of the coke?	(4)
31/08/2017	Q:	Radiant tube skin temperatures of CCRU preheter and interheaters has increased and nearing the design tube metal temperature of 625 Deg.C. Whether anyone has faced such issues in CCRU? What is the solution to bring back the skin temperature to normal? It is to be noted that no decoking facility has been provided since the service is clean.	(3)
31/08/2017	Q:	How do you estimate the approx. quantity of sludge in a crude tank before handing over for Tank Cleaning?	(1)
29/08/2017	Q:	What is the best way to re-process Fuel Oil Blend Stock (FOBS) or waste that contains 20-30% water and sediments? Any recommended third party company doing this job? Any way to sell such material?	(3)
29/08/2017	Q:	In our plant we have three floating roof tanks, it's receiving crude oil from the field and the same pump out the oil to the terminal for export. The production still the same no change, but when we stopped the shipping pumps to the terminal next day the production decrease. What accounts for this?
29/08/2017	Q:	Hypothetical: A hydrocarbon contamination is observed in the cooling water system for almost a month. Exchangers and pumps utilizing cooling water (CW) were inspected in the process area however, the cooling water supply is already hazy thus the CW return is also hazy already. The use of biodispersant is being considered to clean up the system. Laboratory testing of the hydrocarbon collected is also being done to determine the contaminant's quality. What more should be done to solve this contamination issue? Will the laboratory result be accurate? The cooling towers are open loop and evaporation of hydrocarbon may take place.	(3)
25/08/2017	Q:	Is there any correlation between increased heater outlet pressure and increase in recycle ratio, if COT is maintained constant.?	(1)
24/08/2017	Q:	In our Diesel hydrotreater unit we faced an issue in heater steam coils.The steam outlet temperature was 230 before desuperheating and after desupheater more than 380 deg C . We injected boiler feed water to desuperheater to reduce the temperature but we absorbed temperature goes up even we closed boiler feed water.we checked all instruments it's good. What is the problem behind that and how to solve it?	(2)
22/08/2017	Q:	I would like experts' comments on ATF processing. We don't hydroprocess LK to produce ATF. We only change the form of sulphur compounds in an alkaline solution in presence of air. The reactions proceeds as below 2R'SH + 2RSH +O2-> 2R'SSR +2H2O. We have a constraint that while processing light slop in crude unit we cant ATF as it results in colour deterioration of the product. Can i get some expert comments as why this happens. and whether this method of producing ATF is followed elsewhere?	(4)
14/08/2017	Q:	What is the uses of Decant Oil or clarified oil or slurry oil which is generated from the Catalytic Converter? What are the valuable chemicals recoverable for it? What is the different technology behind this to convert it to a useful fractions? Which company provides the technology?	(7)
12/08/2017	Q:	Decoking of the fired heater of VDU During recent years , the skin temperature of one of the 4 coils developed a slightly higher skin temperature than the other 3 coils , the skin temperature is nearly 500 C , it is still in the safe range but we are now considering decoking to to remove any present coke during shutdown . Anyways , I am comparing SAD ( Steam Air Decoking ) to Pigging , There seem to be many hazards and incidents during SAD , i wonder if any of you witnessed any incidents with SAD ? ... Can anyone clarify the potential hazards and their severity ? do you recommend it or you recommend pigging ? ...... Thanks for your comments and replies in advance ....	(5)
07/08/2017	Q:	42 Inch Vac transfer line developed leak at 6 clock position at the 20 inch branch connecting location which was connected at 12 clock position of the pipeline. Total 2 no of branch in which one no of branch location leak observed in 42 in header due to internal erosion. In other branch location at 42 inch header the thickness was found to be 4mm over a length of 500mm at 6 clock position straight bottom to the 20 inch branch. The line is of P5 metallurgy with SS 316 clad. original thickness 12.7mm. The line was in service for 19 years. Remaining locations thickness was found to be above MAT. Only in 2 branch locations at localized location severe erosion observed. In this instance, the leak was found to be due to turbulence and velocity which caused erosion but are there any other factors which cause this kind of failure?	(2)
04/08/2017	Q:	What is the process for detecting leak in feed/effluent heat exchanger of C5/C6 isonerization process which uses zeolite catalyst, without shutdown or using radio active tracers? Is there any component which when injected along with feed will completely react in isomerization reactor?	(3)
31/07/2017	Q:	What is meant by "False Air Damper" in reformer? How does it work?
25/07/2017	Q:	"Sand-type" coke morphology Typically, we process high asphaltene, high-MCR vacuum residues in our Delayed Coker, that produce a shot-coke morphology. But in one of our Delayed Coker Units we have recently changed feedstock quality, to light (low-MCR, low ashaltenes). This light VR is producing a transition coke (asphaltene / MCR ratio about 0,6) with low particle size (less than 1 mm), quite loose, that looks like "sand". This coke give us a lot of problems during coking cycle: high level alert that is not consistent with coke yield and drum filling (it seems as coke "floats" or is withdrawn with coking vapours) and more severe problems during decoking cycle: problems during cooling (high level measurement, it seems as coke "floats" in water), difficulties in cooling (more time required, it seems as coke release more heat that usually), plugging problems in drainage line and bed collapse during coke cutting. Definitively, the coke bed formed is very loose, not compact and "mobile". We suspect that it is due to: 1) Excessive velocity in the coke drum (due to higher gas production); 2) Light feedstock require more time in order to obtain a compact coke. How could we improve the coke morphology to avoid this problem? Which should be the changes in operating conditions to avoid these problems?	(2)
24/07/2017	Q:	We recently received a batch of jet fuel, which test within the refinery indicated was within specification (40 ° Celsius). However,when sent through a pipeline of 45 kilometres to the company's warehouse, and after being allowed an appropriate period of stability, we took homogeneous samples of the tank and found the flash point was was 37.8 Celsius. How has this change occurred?	(7)
24/07/2017	Q:	Is a microbiological assay for storage tanks necessary?	(3)
17/07/2017	Q:	What is the effect of reducing the system pressure in a gas oil/naphtha hydrotreater? Will this be able to reduce the hydrogen consumption given that there is still allowance on catalyst deactivation? What parameters do we need to consider before reducing the system pressure?	(2)
14/07/2017	Q:	How to find out the right/optimum flow of hydrogen in reductor in continuous catalytic reforming unit? What if I operate reductor at maximum capacity in my plant?
03/07/2017	Q:	Can there be RSH recombination in Kerosene Hydrotreaters operating at 360 deg C temperature at EOR and targeting 8 wppm Sulfur in final product? The feed is SR kerosene.	(4)
14/06/2017	Q:	In a SCOT unit, what can produce black solids accumulation in the quench water column?	(1)
14/06/2017	Q:	Are there ways to monitor pressure drop on-stream across reheat exchangers, condensers and catalytic reactors in a sulfur recovery unit? Manual pressure survey is being done using pressure gauges attached to Strahman piston valves are the only current way to do this in our plant. What is an effective way in forecasting high pressure being experienced in the system?
14/06/2017	Q:	What is the latest UOP method of analyzing C5+ content for the Platforming product (Reformate)?	(2)
08/06/2017	Q:	In case of PSA expansion with one pair, is it a must to have the same PSA skid between the new vessels in size (length)?
30/05/2017	Q:	I have a general query related to hydrotreaters. I want to know what are the factors considered in designing push/pull system for feed surge drums. I saw some units operating with Fuel gas while some operate with Nitrogen as supply for blanketing.	(3)
29/05/2017	Q:	How LHSV in a pilot plant reactor can be calculated with the following data: feed flow rate=30grams/hour,hydrogen to hydrocarbon ratio=400 Nm^3/m^3 and temperature and pressure conditions are 270 degree celsius and 20 bar respectively?	(1)
27/05/2017	Q:	In our refinery,straight run LPG is used as Automotive fuel LPG to meet the minimum MON spec of 88. Why is cracked LPG not used for Auto-LPG ? Will it not meet the MON spec ? What is the composition wise difference in Straight run and Auto LPG ?	(2)
21/05/2017	Q:	Why do we need to do catalyst wetting and exothermic during catalyst loading?	(1)
19/05/2017	Q:	In VGO hydrotreater unit, cracked feed processed from coker unit which is mainly HCGO and HHCGO (Heavy Heavy coker gas oil). If HHCGO end point increased from 570 deg C to 600 degC, then how severe its impact on VGOHT operation and its catalyst performance?	(7)
16/05/2017	Q:	During the drying of fusel oil, what are the correct proportions and quantities of fusel oil and sodium chloride solution used for mixing? What amount of the filtered solution is distilled?
16/05/2017	Q:	in our C5/C6 Isomerization unit, the reactor effluent after feed/effluent heat exchanger has 43% liquid at 1040C. this effluent is being cooled to 400C using air finfan cooler and water trim cooler. Hydrogen rich gas is separated from liquid hydrocarbon in a separator at 18 kg/cm2 and used as recycle gas. We normally maintain H2/HC = 1.5 mole ratio. We want to install a hot separator at the outlet of feed effluent exchanger to separate the condensed hydrocarbon and the remaining gases and uncondensed vapour will be further cooled in air fin fan cooler and water trim cooler. Liquid hydrocarbon from hot separator and cold separator will be mixed and sent to stabilizer to remove C1-C4 components. 1) I want to know whether this type of hot separator is feasible and did any refinery has this type of system. 2) How much will it affect recycle gas purity.	(2)
15/05/2017	Q:	Our CDU overhead air cooled heeat exchanger is designed with 156 tubes and 3 passes. we have recently shutdown the unit to plug 32 leaked tubes: - 20/52 tubes plugged in pass 1 - 12/52 tubes plugged in pass 2 . We would like to estimate the effect of tubes plugging on the overhead ACHE performance by simulation (example wtih PRO II ). How could we do that ?	(2)
14/05/2017	Q:	We are using AXENS Catalyst RG-682 (Naphtha Reforming) and HR-538 (Naphtha Hydrotreating). Now, my question is what is the actual life time of these two Catalyst? How many times it can possible to regenerate RG-682 & HR-538?	(6)
12/05/2017	Q:	I am process engineer of Naphta Hydrotreating units in a Refinery with capacity of 350000 bbls/day. In this moment the refinery it has in storage tanks gasoline with higher weight percent in MTBE above 2 % weight. However this gasoline will be send to co-processing in VGO Hydrotreating unit (FCC Pretreatment) where according with our evaluation it is possible co-processing this naphta by dilution in the reactors taking in account because HDO reactions, will have more heat release, hydrogen consumption and water generating. So we could hydrotreated this naphta in VGO hydrotreating unit, however the quantity of oxygen compounds like MTBE was about 20-40 ppm. This naphta is send to the naphta fractionator and will be separate in Light naphta (LVN) and heavy naphta (HVN), and the HVN stream is send to NHT unit. But the problem is, according with opinion of process engineer of NHT unit, the feedstock to NHT should not have oxygen compounds (0 ppm) in order to avoid fouling in the preheat train by gum formation, but the catalytic scheme installed in the reactor of NHT there are CoMo and according with my evaluation, after dilution of this naphta previous introduce to the NHT, the concentration of ppm in MTBE will be lower and i have read and studied, that in NHT units, the most of oxygen compounds are converted around 90 %, so in my oppinion would have not problems in send this feedstock to NHT unit. My question is, does it exist a maximum concentration in ppm of oxygen compounds like MTBE in feedstock to naphta hydrotreating units? and which will be the main impacts in point of view catalytic and heat transer in the preheat train?	(2)
10/05/2017	Q:	We have platforming heaters tubes of alloy 2.25 Cr-1Mo (vertical tubes) . The maximum design skin point temperature 595c while the limiting design metal temperature 650c as per API 530. What is the maximum temperature we can reach it above the maximum design and below the limiting design to avoid the oxidized of the metal?	(5)
08/05/2017	Q:	Fusel oil removed during distillation. It contains various higher alcohols. What is the standard procedure for separating isoamyl alcohol?	(1)
02/05/2017	Q:	How can I calculate Reforming Heat of reaction and reactor Delta T. From the catalytic reaction guideline I know that the Napthene dehydrogenetion heat of reaction -50 Kcal/mole. Now I want to calculate reactor delta T. Additionally I know the reformer feed flow rate, feed detail hydrocarbon analysis, feed density, feed molecular weight In practical operation, we have three reactor in series, 1st reactor delta T 117F, 2nd reactor delta T 48F and 3rd reactor delta T 16 F; Now I want to calculate this delta T in theoretically. How can I prove/calculate that this practical delta T as like theoretical?	(2)
01/05/2017	Q:	What are the effects of continuous usage of FCCU direct fires air heater during normal operation to support Regenerator base temperature especially at a condition of limited fresh catalyst availability?	(1)
29/04/2017	Q:	In most of the flare KOD's within a process unit, there is one inlet line at the middle of the horizontal KOD vessel and two outlets (from the two ends of the horizontal KOD) which joins and then goes as a single line. Why is this so ?	(1)
26/04/2017	Q:	I have been requested to benchmark our estimate of process chemical costs in current refinery project. Refinery configuration with middle-east crudes processing, and bottom upgrading with ARDS and RFCC. Crude capacity about 250 kbd. Process chemicals cost include CDU demulsifiers, neutralizing amine, corrosion inhibitors, antifoaming etc, i.e. those used in overall refinery complex. Can anyone share any similar costs, at least per barrel of crudes processed?	(2)
21/04/2017	Q:	How can I find the amount of flow passing through a control valve at a given output?	(3)
21/04/2017	Q:	What is the relationship between the top temperature of a vacuum tower in a vacuum distillation unit and the rate of corrosion in the overhead condensers?	(4)
21/04/2017	Q:	In an atmospheric CCR reforming unit how can measure the chloride content (HCl) of the regeneration vent gas? If you have a Chlorsorb system how can you measure its efficiency?	(3)
20/04/2017	Q:	In centrifugal compressor driven by steam turbine why do we have three solenoid valves: one for starting oil and another for trip oil all of them for trip valve actuator and how does it work ?
20/04/2017	Q:	What is the relation between the amount of overflash used in a vacuum distillation tower and the stripping steam injected at the bottom of this tower?	(3)
20/04/2017	Q:	For a cooling top pumparound for a vacuum tower, which is more useful: to use a larger flow rate (140 m3/h) at higher temperature (78C) or use smaller flow rate (100 m3/h) at lower temperature (70C)	(2)
19/04/2017	Q:	I currently working with naphtha hydrotreater plant we have splitter column which split only light and heavy naphtha.in our reboiler (fired heater) of that column convection inlet temperature is 155C and convection outlet is 181C further it goes in radiation inlet where temperature same as a connection outlet but outlet of radiation is 161C. I don't understand that why temperature in radiation zone decrease compare to convection outlet.	(3)
18/04/2017	Q:	Are there analytical techniques to quantify hydrocarbon content in amine solutions ? These cause serious foaming problems.	(1)
12/04/2017	Q:	In my CDU unit, there are two type of feedstocks -- sour crude and sour condensate. I noticed both Units have same configurations -- except CDU have desalters and charge heater while Condensate Fractionation Unit does not have them. While crude feed is vaporized up to 60% before charged into CDU column (360degC), condensate feed is heat up only up to 140degC where it is still 100% liquid phase. My question is, 1) Why in CFU configuration, it does not requires Charge Heater at upstream of Condensate Fractionation column? 2) What is the factor determining the vaporization rate of condensate/ crude feed into the fractionation column?	(1)
07/04/2017	Q:	In our unit DHDS we have steam turbine pump. I am unable to understand why both mechanical and electronic governors are needed. Also turbine is provided with tripping device.The maximum over speed trip value around 1600RPM. Could anyone explain why both mechanical and electronic are needed?
06/04/2017	Q:	How to avoid transmitters chock during plant commissioning?
04/04/2017	Q:	In a vacuum distillation unit working with a multi-stage steam - ejectors system, and it's around 10000 BPD capacity. The flowing of the suction fluid (hydrocarbon mixture) is 24975 M3/hr and 79 C˚. Can we switch to vacuum pumps instead of the steam - ejector, from an economical point of view?	(3)
01/04/2017	Q:	In my plant, Vaccum Column LT LP tapping body nozzle is badly choked, all the dechoking options tried but no success found. We have only one LT tappings. As of now we have installed a PI at bottom in place of LT HP tapping, on the basis of this PI value level column is being operated. However this is not the permanent solution unless until we shutdown the column. Is there any other option available to monitor level of column??	(2)
30/03/2017	Q:	How can I determine the amount of stripping steam for a side stripper?	(3)
30/03/2017	Q:	What are the sources of phenol in overhead condensate (sour water) in a vacuum distillation unit?	(2)
30/03/2017	Q:	What is the typical composition of VGO (Vacuum gasoil) and what is its cracking temperature?	(3)
30/03/2017	Q:	What is Wild Naphtha and why is it so called?	(7)
26/03/2017	Q:	I am working in Crude distillation unit. Heavy Naptha yield is coming very low. Around 4-5 M3/Hr against 26 M3/Hr. It is observed, whenever HN stripping steam reducing stripper level is increasing. Stripping steam reduced from 400 Kg/Hr to 200 Kg/Hr. Even then we are able to get 4 M3/Hr. Could any one advise to overcome this problem?	(6)
25/03/2017	Q:	In our hydrocracker unit we have recycle gas compressor and they are provided five ejectors to create vacuum in service condenser. Two ejectors for first stage and another two for second stage.And last ejector for start up. Why we need to use initially start up ejector and we can use first stage and second stage initially instead of start up ejector if we can there is any effect?	(1)
24/03/2017	Q:	I am facing an unusual problem of a localized fouling in vacuum column top section and i am trying to develop a solution for the ongoing problem , i am looking for any advice or insights or even prior experience with similar problems , any contributions are highly welcomed . My problem is periodic formation of semi-solid fouling in the top section of the tower despite of operating at relatively low temperatures (Tray temperature 185 C ) and low Pressures (-0.955 kgf/cm2) , i assumed that cracking or coking at this conditions is highly unlikely at this conditions (correct me if i am wrong) and i assume that the problem might be caused by phase separation of asphaltenes entrapped in light hydrocarbons .... is there any way to exactly determine the problem , what kind of lab tests can be done? any one faced similar problems in vacuum columns? Additional: Thanks all for your valuable answers , I want to add some missing information to the original posts , first of all the fouling color is blackish and the top tower temperature is nearly 85 C ....the fouling seems to be of a hydrocarbons origin.......... it was noted that the fouling increase with the increase of overhead temperature what steps and lab tests can i do to exactly characterize the fouling? Further: We Analyzed the solid fouling using x-ray analysis , it was 98.9 % Hydrocarbon, 0.7 % Sulfur , the rest are trace metals with various low percentages (0.01 ~0.02 % ) ... the lab analysis didn't indicate any chlorides , i am not sure if the x-ray analysis can or can't detect chlorides but will discuss it with the lab chemist , most of the replies suggested ammonium chlorides , but apparently it isn't the case....	(7)
23/03/2017	Q:	In our hydrocraker unit in first stage we have VGO and HCGO. We maintain ratio 70:30. If we increase the percentage of HCGO there is any effect in reaction and hydrogen consumption? And how to maintained?	(6)
21/03/2017	Q:	ASTM D2887 method claims to be applicable for petroleum fractions having FBP up to 538 C. But, as per method, GC is typically operated within range of 360-390 C. So, is it possible to vaporize HCGO (370-530 C) sample (0.5-1 micro liter) at this operating temperature and hence, evaluate the TBP profile of HCGO?	(2)
20/03/2017	Q:	We are using Compressor Type WS2/180-A1 for our Naphtha HydroTreating recycle gas compressor. During Wash water injection at the up stream of NHT reactor effluent separator, water is carrying over to the suction of Compressor. As a result of that compressor discharge, flow becomes low and load current also becomes low which suggests one of the load valve is not functioning due to dirt in water may have choked the load valve. After cleaning the load valve, flow and current becomes normal again. This problem is being faced recently when some salt has formed at the downstream of NHT reactor effluent which is dissolving with the wash water and carrying over to the suction of compressor. In addition, we are facing this problem after 3.5 years of plant life cycle. My question is whether it is happening only for dirt in water or load valve's diaphragm and O ring get old or spring has lost its tensile strength. Whether the Compressor type WS2/180-A1 is designed to handle some liquid or water as it is designed for recycle gas of NHT unit? FYI- 1. Wash water injection has been continuing in a regular interval of 15 days since the inception of plant start-up 2. Salt formation at the suction strainer is experiencing currently.	(3)
20/03/2017	Q:	Currently Chloride content in our straight run Heavy Naphtha (HN) feed is 800 PPM. So, please tell me the maximum limit of Chloride content in HN is acceptable for NHT unit to minimize the chloride corrosion and salt formation in the system (for Naphtha Hydrotreating Unit).	(5)
20/03/2017	Q:	We maintain 180-200 ppm H2S gas (measured by Drager Tube CH29101) at the outlet of NHT recycle gas compressor discharge to keep the HR 506 (Co Mo) catalyst in its active form or sulphided form.FYI, our HN feed contain very low sulfur which is Doctor test negative. For this purpose,we are adding 2.8-3 kg pure DMDS with the feed which can be able to produce more or less 0.095 kg H2S in the recycle Gas but from the design data book calculated value is 21.99 Kg H2S (provided recycle gas flow 467 kg/hr) which is 47,087 ppm.So, how the calculation has done and how it becomes 180-200 ppm H2S in the recycle gas. Please show me the basis of calculation.	(4)
20/03/2017	Q:	I am in charge of DHDT (produce 10ppm ULSD) catalyst performance monitoring, recently WABT was increased fast out of my expectation, meanwhile ULSD color was getting worse (DHDT has decolor reactor), observed cut point (T95) of feedstock SRLGO had a fluctuation in last few weeks, what is the possible cause of this abnormal WABT jump?	(5)
15/03/2017	Q:	What is LSHV. What is effect if decrease or increase in the reaction .And how to maintain it?	(3)
15/03/2017	Q:	In our NHT unit, tube material of stripper Column Overhead air cooler is SA-179 which is low carbon steel. So, if we use type SS 321 instead of SA-179 then will it be more sustainable in the wet H2S and wet HCl environment?	(3)
14/03/2017	Q:	Is there any nitrogen species that may be present in LVN but is not present in HVN? We are detecting high nitrogen content in LVN but not in HVN. Also, our sulfur content is low. Even though we may see nitrogen in HVN (poison to reactor), the endotherm of the reforming reactor is not affected. Are there nitrogen species that can be detected by NSX but is not readily available for breaking down/reaction?	(3)
11/03/2017	Q:	Why truf type distributor are used over light LVGO tray?
11/03/2017	Q:	Please tell me the normal PH limit supposed to have at the NHT Stripper Column Overhead drum water boot sample. Currently, we are getting ±1 which is very low. Please enlighten me whether it could be the effect of wet H2S alone or it could be the cause of combined effect of wet HCl and H2S which might carry over during the wash water injection from reactor effluent Separator drum to the Stripping Column Overhead Drum. FYI- 10 wt ppm CHIMEC 1044 is being injected at the inlet of stripper overhead air cooler continuously.	(3)
08/03/2017	Q:	There are 6 identical trains processing natural gas bringing H2S < 4PPM and CO2 From 5% to 2%. All parameters are same. MDEA is the solvent used. But interestingly out of the 6 absorbers one is not properly functioning in terms of capacity and quality.The lean amine in all other absorbers is pale yellow and the one having problems is brownish. The solvent tested for all parameters, found ok except colour. Could any one come out with a solution?	(3)
01/03/2017	Q:	We have tried several times to continue inject wash water @ 80-100l/h at the upstream of air cooler of NHT separator drum but every time recycle gas flow becomes low remarkably due to suction valve get choked which seemed some entrained water and salt carried over and blocked the suction load valve of Compressor. Therefore, please advise us what could go wrong and how to solve the problem? Moreover, we have increased the temperature after Separator aircooler (A-201) to avoid the tube corrosion which reduced the DP fluctuation across the reactor R-201 but frequency of salt formation at the suction strainer was increased and it seemed de-sublimation point of salt attained at the downstream of A-201 which is close to the suction of recycle gas compressor. However, last couple of days we did not inject the wash water and monitored the rate of salt formation at suction strainer and found very insignificant amount of salt that could be the reason the de-sublimation point shift and not coming close to the suction of compressor for the time being. But, Today again get problem just after injecting only 50 litre wash water but no salt is found at strainer which seemed water carry over and choke suction valve again. For your info, we have drained water from the separator boot continuously- is there any problem with the water injection point? So, should we shut down the plant and need to do steam cleaning whole NHT Circuit to eliminate all the salt from the system?	(4)
27/02/2017	Q:	We have a peculiar case where the Coke Drum has twisted. Any suggestions on the repair procedure?	(1)
22/02/2017	Q:	Does anyone know about the economic feasibility of Organic Rankine Cycle in Crude Distillation Unit? We are having sub-cooled condenser duty of 20-24 GKcal/hr with overhead temperature in range of 120-130°C.	(1)
21/02/2017	Q:	I want to load about 14 ton of CMS (Carbon Molecular Sieve) into a PSA Nitrogen Producer tank. The tank is 5 meter tall with 2 m in diameter. What is the best, simplest and fastest method to load the pellet of CMS into that big tank? I consider this mortar screw pump and connect it to a long / extended hose to reach the top of the tank. http://www.penobet.ru/images/prod/sosna7pro.jpg Within removing the agitator inside the hopper and used VFD/VSD to slow down the motor speed of Screw or Pump mechanism, will the screw still crunch or crush the CMS pellet? Sorry for my English.	(2)
16/02/2017	Q:	We observed that our crude unit naphtha stabilizer column overhead water has become decolourized since few days. The colour is yellowish to brown. However, the main column overhead water is clear in colour as previously. Can anyone help me in identifying the possible causes for this? Some forming also has been observed while draining this water. Can overdosing of corrosion inhibitor (filming amine type) cause this issue? Further info: Thanks for valuable answers. The colour was observed while draining of the vessel boot. So, there is no much time to react with atmospheric oxygen. Is it any dissolved oxygen that react to give the colour? Also, I found some evidence of overdosing (almost double ) of the corrosion inhibitor for a short period of time. Once it was corrected the colour was improved. But, not sure whether it is due to that or due to anything else.	(3)
15/02/2017	Q:	What is the range of UOP R56 catalyst density? Is it ok to assume that the density of Fresh catalyst (R56) is the same with the Spent Catalyst when calculating the weight of the catalyst? Is it possible to overload reactors (3) in a (vertical) stack with catalyst in CRU?
15/02/2017	Q:	In a CDU overhead drum reflux, which are the advantages of a three phase separator versus a flooded one with a naphtha + gas outlet, a naphtha to reflux outlet and a water separation? And how can you estimate them? In both cases the reflux temperature is the same.	(1)
14/02/2017	Q:	What is industrial practice of caustic dosing in desalted crude? And what should be optimum dosing in ppm?	(4)
11/02/2017	Q:	How many Vacuum Residue Hydrocrackings are in operation worldwide? What is the maximum conversion achievable (ie minimum bottom product after the atmospheric and vacuum distillation of the reactor effluents) in these plants?	(3)
11/02/2017	Q:	In hydrocraker unit in make up gas compressor I absorb first stage KOD LT and LG connected to ATM but second stage KOD LT and LG connected to flare. Is there any reason for that?	(1)
07/02/2017	Q:	We are treating Heavy Naphtha to produce DSN in Naphtha Hydro-treating Unit. The effluent stream from reactor bed flows to a Separator Drum after cooling through an air-cooler. As per the recommendation at the up stream of air cooler, we are giving 350 litres/ hr wash water after each 15 days interval. Even though, instead of NH4Cl salt we are getting Iron Chloride salt at the suction of Compressor strainer. Therefore, frequency of changeover of compressor has increased remarkably. In this case, what should be the preventive measure for the air cooler as corrosion product is generating. This problem has been observed after 3 years of operation life. Can you share your experience please?	(7)
04/02/2017	Q:	We have a semi regen platformer unit and catalyst type UOP-R56. During the regenerating after the oxidation step we stopped at this step The problem of providing electricity occurred and we did not complete the rest of the steps, now the reactors under positive pressure by hydrogen reformer purity of H2 70% Is this situation adversely affects the catalyst after the oxidation step? And what needs to be done in this case?	(2)
04/02/2017	Q:	We use straight run Heavy Naphtha from Tank which has floating roof. Now, my question is what should be the limit of moisture or water content in wt ppm level before entering Naphtha Hydro Treating Catalyst bed. Currently, we have 104 wt ppm moisture in HN feed can this quantity could be the cause to increase the pressure at the inlet of Reactor suddenly to create a peak of DP across the reactor bed? Currently, DP across the catalyst bed is 3 and it has reached gradually after the 3 years of operation cycle but become confuse about the sudden peak. So, please help.	(5)
03/02/2017	Q:	Our FCC feedstock is 30% AR, 20% SR VGO, 50% CR VGO. Our Vapor line DP increases steadily (sometimes drops) and now it became over 0.43kg/cm2. We have some ideas about developing during TA but is there anyone who has ideas about dropping the coke during normal operation? We are trying 1. ROT increase 2. Feed Temp increase 3. Rx STM increase(ex. Lift STM) 4. Excluding Crude which has high asphaltene component Is there someone who had suffered from vapor line dp and has some clue about dropping vapor line dp?	(4)
03/02/2017	Q:	What are the key tests with specifications for Alumina or Ceramic support balls for catalyst used in refinery ? What maximum/minimum values of Apparent porosity or Water absorption should be the specification for good inert support balls to be used in Sour Shift units of Gasification complex?	(1)
26/01/2017	Q:	Current DP across the Naphtha Hydro-treating Reactor is 3 and it is giving peak frequently without giving a gradual increase of DP. Why is the pressure at the inlet of Reactor is suddenly increasing for the few second but coming down to previous position again? However, we are thinking Catalyst top bed is blocked by coke, iron scale and other metal contaminant. Besides, we are getting some Ash color and salt type dirt at the fine mesh filter at the suction of NHT compressor. So, i need to know what could be the probable composition of the dirt? For this, we assumed that it could be fouling product from the separator drum or dust of alumina ball from the bottom of Catalyst bed. Now we are facing frequent compressor changeover and cleaning of suction strainer. So, please share with me if anybody have similar kind of experience and help me to sort out what could be the composition of dirt.	(3)
24/01/2017	Q:	How can we reduce the excess hydrogen content in a hydrotreater off gas stream (off gas from reactor effluent separator/flash drum, stripper off gas)?	(3)
24/01/2017	Q:	What is the difference between hydrogen consumption ratio (makeup gas flow rate/ oil flow rate) and recycle gas-to-oil ratio (recycle gas flow rate / oil flow rate)? What will be the effect on the amount of make-up hydrogen required if we reduce the recycle gas flow rate?	(5)
22/01/2017	Q:	We are operating Full combustion FCC with hydro treated VGO from VGO hydrotreater. Sometimes VGO HDT sends their back was material along with Hot hydro treated feed to FCC. Unfortunately many of the times their backwash filter is in bypassed condition. We commissioned our plant one year ago and till now no issues related bottom circuits propped up. We are having 3 MFC bottom pumps with dual bucket strainers for each of the bottom pump. For one month we are not developing flow though CLO pump around pumps (normal flow 800MT/hr for each pump).For present T'put we operate one bottom pump with one suction strainer in line. But for one month the bottom pumps are cavitating and not developing flow and it is observed that the pumps are not getting proper suction flow from the main fractionator column.We are continuously cleaning our suction strainers and some times we are getting soft coke & catalyst but sometimes finding not much. We lowered T'put due to this issue and running two pumps instead of one pump and all the strainers are in line. Still day to day the condition is deteriorating and not improving. Reason is not known for suction lines chokage issue. We are maintaining MF column levels on lower side but to our surprise the suction lines seem to got choked. Our slurry BS&W didn't cross 0.3wt% at any point of time during the period. Anyone suggest -- 1) How to mitigate the problem while plant is in running condition 2) How to avoid this type of problems what corrective actions to be taken wrt feed, Circuit flow and all. 3) Any system available to clear the MF column bottom circuit chokage issue.	(4)
19/01/2017	Q:	We have a 50,000 bbl/d capacity crude unit designed for Iranian light crude oil. The main crude column needs to be replaced due to ageing. We would like to take this opportunity to revamp to unit capacity as well to about 70,000 bbl/d. Based on a previous study carried out, the unit capacity can be increased up to 70,000 bbl/d by installing a pre-flash drum before the charge heater. However, now we have to replace the main column. In another study carried out, it has been identified that the some modifications are required to be done to the charge heater such as re-tubing with different metallurgy and changing the passes from 1 to 2 etc. if the unit capacity is increased up to 70,000 bbl/d (without a pre flash drum). I would like to know whether installation of straight 70,000 bbl/d capacity column or installation of same capacity 50,000 bbl/d along with a new flash drum (to avoid charge heater modifications) is more economical.	(4)
19/01/2017	Q:	Can we use utility water as water injection to desalter? What's the Max TDS in the water injection to desalter ?	(1)
16/01/2017	Q:	Why we need to purge the PDI across each bed in DHT reactor with recycle gas?	(1)
15/01/2017	Q:	What is the best technique in terms of cost and time for online sealing of valve body leakage in which high pressure boiler feed water is streaming?
12/01/2017	Q:	We have an issue with our RG compressor in hydroprocessing unit. The flow of the RG compressor (Reciprocating single stage) decreased all of a sudden while taking scheduled changeover of the RG compressor. Flow went from 22000 Nm3/hr to 17000 Nm3/hr. We thought it may be due to some problem with the compressor that we took changeover so after a while again C/O was taken and the previously running compressor was taken in line but the result was same. The other process parameters are same like the HP separator pressure and temp remains same. the power consumption of the compressor got decreased from 125 KWH to ~85 KWH. We have checked the spillback valve of the compressors and cleaned the strainer of the compressor but no results obtained. MUG compressor flow remains same and the MUG discharge is in the Fin Fan outlet to HP separator. The purity of the RG remains same. And one thing to be noted is that the D/C pressure didn't change, the S/c pressure got inc by 1-1.5 KSC at the time of C/o but now its normal. The RG suction drum is common for the both compressors. It was noted that for past few weeks the suction drum level got inc and draining was done a bit frequently, so could carry over of the Hcbn liq to the compressor cause this reduction in flow?. The one imp thing to be noted is that both the compressors are not developing the flow. the flow has got dec to 17000 nm3/hr and is constant at this value, no further reduction is there, it has been a week since the event. (suction valve plate should be OK as the s/c temp is not inc) Pls give your valuable suggestions. Additional: Thank you Mr. Rupesh for your valuable time and comment. Actually we have checked the unloaded valves after taking the compressor for a maintenance and checked it at site (operational wise) but the working was found normal. Actually after doing a thorough study we have come to an conclusion (as of now) we found out that there is a increased liquid carry over to the compressor. We have checked the strainer in short durations. And the possible cause could be some internal integrity damage at RG suction drum or High pressure separator (suction point of comp). So this activity of integrity check could be done only in available shutdown activity. As the gas to oil ratio is less than earlier but not low at alarming level, management took the decision of waiting till planned shutdown. P.s: I will update you once the activity is being done.	(2)
12/01/2017	Q:	We are currently designing a new grassroots unit for diesel hydrotreater (DHT). There are 2 different opinion when it come to hydrogen mixing point: either it is mixed before or after combined feed exchanger (CFE) . The view for the mixing point to be after CFE have concern about polymerization or faster fouling inside the CFE while the view with mixing point before CFE saying the impact will be totally the opposite. What is the basis/philosophy for DHT design on where to put the mix point?	(8)
05/01/2017	Q:	Why is the RV of surface condenser sealing with condensate from surface condenser pump in hydrocraker unit?	(1)
05/01/2017	Q:	There are 2 hydrogen plants in our company, We use NG as feed(SMR Process) to produce high purity hydrogen. The raw hydrogen stream comes from steam reformer, after cooling down which is then sent to PSA to recover high purity hydrogen. The problem is that we have a tube bend and the catalyst has last been changed in 2011, we don't need to run plant at full capacity as our need is not that much, We are thinking of postponing the changing of catalyst for a year or so, but is it feasible?? What is the time when i should know that methane slippage is more now. Till how much percentage of methane slippage i can afford in plant which doesn't hamper CO Shift Catalyst and PSA Catalyst. Also when i should know that its time for The Reformer catalyst to be change? There are some comments from outsources about waiting for 6 months as we are getting purity and methane slippage is within limit. Would you please advise on how much methane slippage is ok if maximum hydrogen production isn't concern but specific consumption should be low, which is the current scenario.	(2)
05/01/2017	Q:	Recently we encountered a failure in one of the Boiler feed water pump. Observations were as below. 1. Pump tripped after running for 30 sec when it reached its full disch pressure of 100kg/cm2G. 2. Trip was due to high bearing vibration on NDE side. 3. Rotor was moved towards DE by about 2mm. 4. Rotor was seized( could not rotate with hand). 5. NDE oil decolorised slightly. 6. upon dismantling we found that NDE bearing inner race was seized to shaft. NDE bearing was totally damaged. 7. DE bearing was fine and no change in oil color too. 8. While operation, discharge valve was fully closed( according to operations min circulation as well as balancing lines were fully open). Online probes not able to provide required spectrum. Now we are struggling to analyze the cause. Pls suggest the way forward and also if you have link to similar failures.	(4)
04/01/2017	Q:	In my refinery there is a 15 kBPSD LSRG sweetening unit in which caustic washing procedure followed by MEROX oxidation process. In case of feed change scenario, is there any solution in terms of gas condensate sweetening by means of before mentioned facilities? If yes, what are the changes in terms of capacity, chemical consumption, and mercaptan removal efficiency? If there is any revamp, which sections need to be resized?	(2)
04/01/2017	Q:	The most common (in fact just ) application is stripping steam for stripping at the Crude distillation units. Is there any alternative to stripping steam, such as nitrogen, for stripping of steam at a Crude distillation unit? Is there a literature/research? What are the advantages or disadvantages?	(2)
03/01/2017	Q:	I need information about mechanism of steam turbine associated with recycle gas compressor and also the function of dry seal gas, secondary separation and separation gas. I would also like to understand the reason of tripping in high vibration.	(1)
03/01/2017	Q:	We are facing plugging of 350 distillate pump strainers in the VDU (lube oil refinery). The 350 distillate is the middle cut of the distillation column. Since Sunday, the pump strainer has been cleaned more than 5 times due to coke deposition. All operating parameters have been compared to the PFD and no deviation has been observed except that the pumparound flow above the 350 distillate bed is less than the required. Also this problem started after a revamp on our vacuum distillation column in 2013. Since then there has been severe coking in this pump and it requires monthly cleaning. But as of now the problem has become severe and the strainer is getting plugged in a matter of hours. Your advice/insight on troubleshooting the problem will be appreciated. Additional info: We have sent the samples for analysis and are waiting for the results. The heater skin temperatures were running high, and we adjusted it. However, we are still seeing coke in the strainer. Although the frequency of plugging is reduced. How can I increase the flow on the 1st pumpdown. The flow of the 2nd and 3rd pumpdown is above 50 m3/h but the 1st pumpdown is less than 35 m3/h.	(5)
31/12/2016	Q:	What is purpose of primary and secondary seal in RGC compressor ?	(2)
31/12/2016	Q:	In our DHT plant we are preocessing Light gas oil and Heavy gas oil. Diesel product 95% recovery maintain at @355degc. Diesel product density maintain @822. We are optimising kerojet production over diesel in condensate fractionation point. As we draw more kerojet at condensate fractionation point Diesel become little heavy. After reactor outlet in stripper we are facing problem of less reflux and resulting in higher overhead temperature. Our diesel product total sulphur content is maintain in range of 4-6 ppm. How to increase reflux flow in stripper with kerojet maximisation at condensate fractionation unit? Is there any relation between total sulphur of diesel product and stripper reflux flow?	(5)
27/12/2016	Q:	We have found black solid deposits upon cleaning of our CCRU Net Gas Compressor First Stage Strainer. Upon analysis of composition, we have found that the sample contains hydrocarbon plus a significant amount of Chloride and Iron and with traces of Aluminium, Magnesium, Silicon, Phosphorous and Sulfur. What could be the source of these black solid deposits?	(6)
25/12/2016	Q:	In steam generator why the CBD line take out from high point than IBD?	(4)
23/12/2016	Q:	Why do we need Forced Draft and what is its function?	(6)
22/12/2016	Q:	We are operating CDU/VDU @ 110% throughput. We have a Demister Pad installed at the top of the vacuum column. The DP of the demister pad is increasing @ ~1mmHg/10 days. This is resulting into higher Flash zone pressure causing dropping of Vacuum gas oil into Vacuum residue. We operate the column at 23 mmHga top pressure. Also we have noticed chlorides in our Vacuum diesel stream (First side cut of VDU) in the range of 10-20 ppm w. What can be the cause of this fast increasing DP and what measures can be taken to arrest that?	(9)
22/12/2016	Q:	What are the main contributes to CDU (crude distillation unit) and what is the benchmark or reasonable percentage of loss across CDU?	(2)
16/12/2016	Q:	Can anyone pls let me know the best practices being followed in the industry to estimate the Delayed Coker product yield and qualities wrt to feed properties.	(4)
12/12/2016	Q:	In our Naphtha Stabilization unit, feed after preheating leaves the HE through a 10" dia pipe and then immediately split in to two vertical risers of 4" dia and again joins back to a 10" dia pipe before entering the stabilizer. What is the purpose of this risers with reduced dia? In P& ID it is mentioned as two phase flow.	(2)
09/12/2016	Q:	what is partial and post burning in FCC regenerator ?	(2)
04/12/2016	Q:	We have gland condenser in our unit. Why there are provided PDV in tube side? In tube side flow come from condensate pump and shell side flow come from ejectors.
02/12/2016	Q:	I'm working in hydrocraker unit and we have recycle gas compressor. Why the condensate from condensate pump which is suction from surface condenser one line goes to RV for sealing. Also why we have expansion bottle for surface condenser. The sources to expansion bottle Medium pressure steam boiler feed water using for start another sources steam turbine drains and ejectors condenser condensate.
01/12/2016	Q:	Any practical solution for polythionic acid corrosion in furnaces? We are finding difficult to implement NACE RP0170 standard.
28/11/2016	Q:	Does anyone have any experience with catalyst fluidization in oxychlorination zone of Regeneration tower in continuous catalyst regeneration unit? We have experienced high catalyst dumping recently after this unit shutdown. This catalyst dumping contains high catalyst dust. Is there any parameter to check whether is the catalyst fluidized or broken inside the Regeneration tower? Thank you very much.	(3)
25/11/2016	Q:	We have a semi regen platformer unit. After regenerating the catalyst, unit was started up and observed that reactor 1 delta temperature (we have 3 reactors ) is low and almost same as reactor 2 delta temperature. And the Platformate RON is also low at about 92 whereas the expected RON at start of run is about 94. This is the first time we experience this kind of a behaviour. There was no sulfur ingress or any other change in the feed stock (Heavy naphtha). The issue seems to be in reactor 1 and other two reactor delta temperatures are similar to the previous cycles. Can anyone help me on possible causes for this issue? Additional info: Appreciate the valuable comments. To add some more information, We do process only the virgin naphtha. Sulfur and nitrogen are less than 0.5 ppm as required. Feed is from Murban crude which does not have high metal content.However, it appears that the reactor 1 delta temp is in decreasing trend and reactor 2 delta temp has increased slightly. H2 purity also low and gases and lpg are on higher side. PONA test indicated that paraffin conversion is low compared to previous cycle SOR conditions. Catalyst samples were checked after oxidation and reduction steps. Appearance of reactor 1 samples were better compared to reactor 3 except the reddish rust coating in reactor 1 was high. But, this coating in reactor 1 was same as in previous cycles samples as well. Also, we are maintain little higher cl level as this is the 9th cycle of the catalyst and expect lower cl retention in catalyst. New info: By today, the reactor 1 delta temp has further decreased and reactor 2 also is seems to be in decreasing trend. A new information is that there was a upset in recycle gas compressor during regeneration (oxidation step). Seal oil loss increase due to seal damage and both the seals were replaced along with damaged bearings. But, labyrinths haven't changed. And we observed some seal oil in compressor discharge line ( some drops of seal oil leaking at the compressor discharge isolation valve flange). Therefore, we checked at casing drain line and another low point in discharge line. First day (two days ago), we found some significant amount of oil collected. After draining them, the next two days found only small collection. Anyhow, now we are doubtful about a lub oil contamination. In addition, can there be a possibility of channeling the first reactor? Because if so we have to dump the catalyst during regeneration. Another thing is that during regeneration, there was a strong detection of hcl in reactor 1 outlet ( more than 500 ppm).	(10)
21/11/2016	Q:	What are the industrial practices being followed in refineries to mitigate polythionic acid corrosion in furnaces?	(3)
29/10/2016	Q:	How does one measure how much dispersion steam to inject, relative to the feed?	(2)
29/10/2016	Q:	How does the Regenerator/Disengager slide valve operate with regards to slide valve DPs?	(1)
24/10/2016	Q:	Has there been a case in any Refineries where the backwash stream (post backwash) is routed back to the cold feed tank instead of slops. The idea is to minimize sloping and reprocess it.	(4)
24/10/2016	Q:	What is the working principle of pressure differential control valve.	(2)
24/10/2016	Q:	What is the difference between process shutdown (PSD) and emergency shutdown ( ESD).	(5)
19/10/2016	Q:	What is effect of Pressure, temperature, LHSV and H2/Feed ratio on gas oil sulfur removal?	(4)
18/10/2016	Q:	In our FCC (Deep Catalytic Cracking) Unit Spent catalyst slide valve(SCSV) DP suddenly decreased from 0.70 to 0.35 kg/cm2. All parameter such as aeration purge point pressure and flow, all types of steam flow, reactor and re-generator DP are normal. What is the reason for this?	(5)
08/10/2016	Q:	Question is based on Desalter operation. 1. What can be possible reasons of mud in brine but no traces of oil during normal desalter operation? Is desalter paramters temperature, pressure and mixing delta P plays any role in it? 2. What is the role of Pressure and Temperature in desalter operation? 3. On what basis, Transformer KV setting to be changed in desalter? 4. What is the role of Mixing Valve DP in desalter operation and when does it require to be changed?	(2)
28/09/2016	Q:	Could someone explain me the procedure to calculate the diameter of distallation column reflux accumulator?	(3)
28/09/2016	Q:	What is the reason behind DMDS injection in CCR Platforming Unit ?	(5)
27/09/2016	Q:	What is the importance of minimum CCR and ashpalatens in Coker feed. Do we really need to maintain certain minimum limits for these feed properties?	(3)
24/09/2016	Q:	We are using Superheated HP steam (P-38 kg/cm2 g, T- 380 oC) to preheat our stripper feed. I want to replace this Superheated Steam with depressurized saturated HP steam (P- 25 kg/cm2 g, T-250 oC). But I am finding it difficult to calculate how much steam I will save. Can anyone help me in finding out the amount of steam for the same rate of heat transfer of 2 MMKcal/Hr. Also I need to know the heat transfer coefficient for both type of steams. Note: The steam at above given saturated steam parameters is not actually saturated but we need these parameters. Thank you all for your replies....We are not going to apply this change right now...currently it is just in study phase. Actually what I believe is: 1. superheated steam should never be used for heating purpose as it has very low heat transfer coefficient (similar to air) as compared to that of saturated steam. 2. so the heat transfer in the convective film formed by superheated steam over the tubes will be very slow. 3.therefore to make use of the heat available in the degree of superheat, we have to increase the area for heat transfer. 4.Also the latent is higher in case of saturated steam (which is the main heat available for heat transfer in case of steams). 5.Also the latent heat increases as pressure of steam decreases. That is why we thought of this change. But acc to your answers, I think my knowledge about steam heating is not accurate and I am missing out something somewhere. Kindly help me in this issue and kindly correct me if I am wrong somewhere.	(4)
22/09/2016	Q:	We have problem of failing silver strip corrosion in storage tank of jet fuel and same time rundown sample is always clear. Please suggest solution.	(3)
20/09/2016	Q:	I have a question regarding the corrosion issue in fractionator on CDU. However, during the turnaround we have noticed very severe corrosion on the first three trays of column. The third tray has mostly corroded. These trays are made out of Monel. The top pumparound goes from the third to the first tray. The corrosion coupon that are placed on the suction of pump-around pump have shown different corrosion rates during last year - from low to severe corrosion rate. The top temperature is lowered to about 120 oC to maximize middle distillate yield. Did anybody face with similar problem? I know that ammonia, amines, nitric acid are corrosive to monel. I am suspicious about the presence of tramp (or even neutralizing) amines on the first three trays. However, in open literature on internet I have found also different opinions the resistance of monel on hydrochloric acid. Did anybody face similar problem? Could it be the issue due to change in the crude blend? Any help would be helpful. Thank you in advance.	(7)
14/09/2016	Q:	We have replaced lead sulphur guard absorbent in Hydrogen unit. H2S is observed at lead and lag sulphur guard absorbent outlet. What can be the reason for it? What is the max H2S limit for pre-reformer I/L feed? Unit is operating on off gases and Natural gas Plant.	(3)
13/09/2016	Q:	What steam stripping is preferred method for Diesel streams and re-boiler type of stripping is preferred for Naphtha?	(4)
05/09/2016	Q:	We have field small refinery to produce diesel ~10000 BFD API =36, BS&W=0.05 and salt= max 4 PTB in our plant already designed one stage deslater my question in such case need to operate this unit I mean mix crude with service water or no need. See below the water and crude desalter in/out result: (see attached file) We faced problem with over head water accumulator with high chloride and iron content and ph fluctuating value out of range (5.5-6.5) as you can see from attached file results. Note that we injecting neutralized amine which is diluted with service water 1:3 with total rate is 7 gpd ( naphtha reflux to crude tower injection point) and corrosion inhibitor with rate 8 gpd (upstream of overhead condenser exchanger). Moreover, over head exchanger is experienced high corrosion, tubing crack at inlet ends no fouling problem has been reported for desalter downstream (Heat exchanger tubing) we used Antifoulant chemical (crude discharge pumps). Using water wash is the root cause of corrosion and high chloride level at over head accumulator. What the source of high chloride level (our crude is very low PTB & BS &W). It is worth to mention that we closed deslater operation for long time but we face same problem high chloride, iron and ph value fluctuating. What the source of chloride our crude feed low salt and BS&W values. Your recommendation is highly appreciated	(6)
01/09/2016	Q:	Can fresh hydrogen be used in Hydro-cracker reactors as a quench media in case of recycle hydrogen failure?	(5)
31/08/2016	Q:	We are facing color problem in our Crude Distillation Column, during processing Color of Naphtha noted +17 instead of +30 what are the possible causes of this color problem. Also color of Kerosene become off spec +10 instead of +30 or +28 what are the possible causes of this problem. We checked all the heat exchangers for Possible leakage but no leakage observed.	(7)
29/08/2016	Q:	In the vacuum distillation unit, we face problem with Gas Oil end point i.e., VGO 95%, Anyone have any idea how to solve this problem or anyone have seen this in any refinery?	(5)
12/08/2016	Q:	I have a question regarding desalter brine quality, as follows: The desalting of same crude is done by two desalters of different geometry (not two stage desalting, two CDUs). I underline that desalting is done efficiently in both units with respect to salt content in desalted crude. The difference is in the content of sulfides in desalter brine. The desalter that has lower sulfide content in brine is more cylindrical, while the another one "tends to be more spherical". The higher sulphide content represents higher load for waste water treatment plant. My opinion is that this behaviour can occur because of longer residence time of oil and wash water in emulsion volume (or the volume ratio of emulsion volume and total desalter volume). I think that perhaps the emuslifier dossage or or delP on mixing valve are higher. Has anybody faced similar issue in the refinery? Any opinion and experience would be helpful.	(2)
05/08/2016	Q:	How can chimney tray pressure drop be estimated?	(4)
02/08/2016	Q:	We are going to plan for introducing PFO in our delayed coking VR feed (not more that 5 MT/Hr). PFO having higher diolefine content. as i heard that it can create problem in down stream unit hydrocracker like gum formation. so kindly give your comments can we go for PFO introducing in VR feed? what actions we have to take before introducing PFO? can diolefins create problem in our heater? because previous study tells that high parafinic & napthanic feed not good as a feed for DCU but they didn't tell regarding diolefins.	(1)
28/07/2016	Q:	I am working as production Engineer in FCC block which consists of FCC and LPG Treater unit. LPG treater treats cracked LPG from FCC and Delayed coker Unit.IT has capacity of treating 404 m3/hr.We are experiencing a peculiar problem these days. Our LPG is getting contaminated with light yellow colour at the outlet of LPG treater unit. LPG ex FCC and coker unit is clear and having no signs of yellowish colour but at outlet it is failing. Copper strip corrosion and weathering tests are absolutely fine. The following are the observations -- 1) These units are commissioned 6 months ago and we didn't come across DSO formation in DSO settler but LPG quality is ok (Probably due to low mercaptans load in LPG, DSO is not forming in the process) 2) The lean amine H2s loading in FCC & DCU LPG washing is around 1200 -2400 ppm. May be noted here that on earlier occasions with this loading of amine,the downstream treater unit was giving good LPG wrt all lab tests. 3)The only problem is with colouring with which we are struggling. 4) sometimes we experience yellowish colour at the unit inlet of LPG treater.Even at the outlet of FCC & DCU also.But the colour is not that much remarkable.But in treater outlet the pale yellow/dark yellow colour is visible upon complete evaporation of LPG.Sometimes 0.5 to 0.1 ml of yellow residue is left and sometimes not. 5) We took complete shutdown of unit, depressurised, all caustic drained from system and vessels and fibre film contactors were water washed and again took the system inline but the yellowish colour in the system LPG still coming.The custic regenration is good and quality is good and copper corrosion test is ok. The reason for yellowishness we unable to find out. Can anyone share their experiences in dealing with this type of typical problem in MERICHEM section of caustic wash of LPG?	(6)
27/07/2016	Q:	I have question about Desalter operation. I need to know which wash water is recommended for desalter, references and codes such as API, NACE....etc I know that some refinery companies are using service water or stripped water. I asked above question because I investigate about corrosion failure for topping plant (cooler coils for mechanical seal at residue pump)	(3)
22/07/2016	Q:	What factors affect aromatic saturation in hydroprocessing of coker heavy gas oil? How can the aromatic saturation be minimized for heat balance benefits in the downstream FCC unit?	(6)
20/07/2016	Q:	We have heatless air dryer which already do a change over dessicant few weeks ago. As per ANSI/ISA-7.0.01-1996 point 5.1 that : a. the pressure dew point (PDP) shall not exceeding 4 deg C at line pressure. b. PDP as measured at the dryer shall be least 10 deg C below the minimum temperature which any parts of the instrument air exposed. Actual Data : Dew point : -18 deg C (atm dew point) Pressure outlet air dryer : 6.6 kg/cm2 g. our lowest ambient temperature for 17 years is 18 deg C Design Data : Dew point : -20 deg C (atm dew point) Pressure outlet air dryer : 8.5 kg/cm2 g. I am trying to calculate the PDP using dew point calculator and got PDP design is 6.4 and PDP actual is 6.0 deg C. Is it allowable to use that instrument air quality?
19/07/2016	Q:	Why is a rundown block-in timer required in modern hydrogen compressors for hydrotreating applications?
15/07/2016	Q:	IN our HCU Recycle Gas Compressor Turbine, make BHEL from one month Turbine Front & Rear journal bearing vibration suddenly increase from 15 micron to 80 micron for about 10 minutes and came back to normal during this period turbine bearing temperature also increase 3-9 degree centigrade. Please suggest the root cause. We do centrifuge of lube-oil once in 24 hors about 2-3 hours and lube oil also replace in december 2015.	(1)
11/07/2016	Q:	We are facing a problem due to the high content of phenol in LPG treatment spent caustic. Due to this high levels, we are having problems to discard this to the wastewater system. I do not expect to have such levels of phenol (over than 5000 wppm) in a caustic solution used only to treat LPG. Is it normal to have high phenol content in these type of spent caustic? The sulphides level is lower than this. The LPG is produced in a Delayed Cooking Unit and is previously treated in a amina section to remove H2S. The caustic treatment is a Merox type, but due to some operational problems, the caustic strengh used is 17%. The phenol level is high even in the spent caustic of the extraction section.	(5)
06/07/2016	Q:	I am working in hydrocracker unit. Since two month LPG is getting failed due to positive H2S and in copper corrosion test. We are maintaining debutanizer bottom and top temperature 186 & 78 degree C and pressure 16.5 kg/cm2g. Our LPG r/d flow is10-12 m3/hr while lean amine flow is 20-25 m3/hr. When we check caustic strength found 20-22% which is quite normal. Generally we change caustic in 5-7 days. Our system is like this LPG comes at top of debutanizer and goes in amine absorber at bottom and lean amine mix at top of absorber after amine wash goes to water wash amine settler where water circulation is done by pump before going to water wash LPG and water is mixed and mixed in mixer. After water wash LPG goes to caustic wash tank through nozzle but no circulation pump is there (Tank). After caustic wash LPG goes to sand filter and then goes to Deethaniser for FG removal and cooled in Water cooler and goes to LPG storage tank. Please suggest the solution.	(9)
06/07/2016	Q:	At present in our VGO hydrotreater we have conversion of around 19.5 % to liquid distillates. we are facing problems with low recycle gas purity: 84-85% C1 and C2 content is high around 13%. What could be the possible reasons? We have recycle gas scrubber after the cold separator.	(4)
06/07/2016	Q:	We are working in a hydrocracking unit and since we start up, we haven't had a good copper strip corrosion data in the light nafta, we have 4a and the best we have achieved consistently is 2b. We lowered the pressure in the main stripper from 125 to 115 psig, increased overhead temperature from 282F to 292F and increased the stripping steam from 8000 lb/h (design) to 9600 lb/h. Also in the debutanizer we have drop the pressure from 160 to 140 ans still we don't have good results. What can we do in order to reach the nafta copper strip corrosion in 1A? Additional: Thank you for your answers, I checked the steam and I saw it is 175 psi and 390F, so we are going to heat up more the steam and we are going to try increasing more the flow, but what could happen if I increase it too much, maybe the control valve 100% open and still not get the copper strip corrosion ok?	(6)
04/07/2016	Q:	I wish to know whether it is possible to install a H2S analyzer in the FCC gascon section stripper column bottom liquid stream. The composition is C3-C10 hydrocarbons (propylene to naphtha range) and a little H2S and ethane. Also, a bit of RSH and COS are present too. The requirement is to have an H2S analyser in this stream so that any slippage of H2S from stripper can be detected immediately and appropriate corrective action taken with minimum effect on downstream process. Is there any other indication of H2S slippage which can be used for monitoring purpose.	(2)
29/06/2016	Q:	We have Shell and tube heat exchanger named E-201-11. This E-201-11 is exchanger just before pass heater of furnace of CDU. The service fluid is desalted crude (shell) and vacuum residue (tube) from bottom column. Shell operating pressure is 19.7 kg/cm2 and tube operating pressere is 25.8 kg/cm2. Pressure desain shell 30 kg/cm2 and pressure desain tube 36 kg/cm2. Hydrotest pressure shell 43.5 and tube 37.5 kg/cm2. What the main consideration of installing TSV at outlet of desalted crude? Does it because of thermal expansion? Now we are installing spare exchanger for E-201-11 but the type is plate and frame HE. The operation mode will be one HE operated and one HE spare/standby. My questions are : Do we need to install relief valve at desalted crude outlet of new HE? Can we use 1 TSV for 2 HEs? What may cause thermal expansion since reduced crude being pumped by bottom CDU?	(6)
29/06/2016	Q:	I am working on performance review of sulphur recovery unit (SRU). Recently we conducted a performance test in SRU. In this regard I wish to know the correct method of measurement of sulphur recovery. Some people believe that sulphur recovery should be merely based on measurement of sulphur in feed minus that in incinerator stack whereas I strongly believe that sulphur balance must be carried out which includes sulphur in feed and stack plus the product sulphur recovered in pit/storage. Material balance is a key to any performance test of the plant. Hence I believe that product sulphur measurement in pit is essential for estimating the % sulphur recovery. Kindly confirm if my understanding is correct. Alternatively please advise other methods of sulphur recovery measurement and the most accurate method to be followed.	(1)
29/06/2016	Q:	Can someone advise the method of sulphur recovery in a Performance test of sulphur recovery unit (SRU) in the sense whether % sulphur recovery can be measured by Sulphur in feed X 100/product sulphur received in sulphur storage? There are some people who believe that sulphur recovery can be estimated by measuring the sulphur in feed (A) and sulphur species in the incinerator stack (B) and simple subtraction of (A)-(B). However I strongly believe that the sulphur balance of the whole plant should be done which includes quantity of sulphur received in storage pit. Please advise. I would be grateful if somebody advises various methods with pros and cons of each and finally the best method practiced in the industry.	(1)
29/06/2016	Q:	We have Shell and tube heat exchanger named E-201-11. This E-201-11 is exchanger just before pass heater of furnace of CDU. The service fluid is desalted crude (shell) and vacuum residue (tube) from bottom column. Shell operating pressure is 19.7 kg/cm2 and tube operating pressere is 25.8 kg/cm2. Pressure desain shell 30 kg/cm2 and pressure desain tube 36 kg/cm2. Hydrotest pressure shell 43.5 and tube 37.5 kg/cm2. What the main consideration of installing TSV at outlet of desalted crude? Now, we are installing spare exchanger for E-201-11 but the type is plate and frame HE. The operation mode will be one HE operated and one HE spare/stadby. My question is : Do we need to install relief valve at desalted crude outlet of new HE?
28/06/2016	Q:	Is it possible to remove metals (Fe,Ni,V) from vacuum slop or vacuum residue streams? If yes, how?	(3)
28/06/2016	Q:	What is the average energy efficiency of Steam turbine driven centrifugal compressor (Total Condensing)?	(1)
27/06/2016	Q:	In case of heavy residue upgrading, we are encountered with vacuum residue as feed. The main features of this feed especially about contaminants and problematic materials are as below: Total sulfur>4.5 wt% Conradson Carbon >25 wt% Ni+V >500 ppmwt Nitrogen ~ 1 wt% We have two cases for VR upgrading project, One is RCD+RFCC and another is HOIL(Hydrocracking)+FCC. Both of these cases use huge amount of fresh catalysts because of high possibility of catalyst deactivation and poisoning. So the operating cost should be high. Is this rational to charge such a feed to the catalytic system directly or is it better to use the process to somehow get rid of metals at least? If we need to use the solvent deasphalting system at the upstream of two before-mentioned cases and draw off about 20% of feed as pitch, we will succeed to lower the operating cost and increase the reliability of catalytic system because of the elimination of the major part of the metals. But in the opposite side, we have missed 20% of primary feed as pitch that it is a low value product. So the profit margin of the residue upgrading cases will decrease. However, as a second question, can we miss 20% of feed charge at the expense of increment of catalyst life cycle?	(5)
26/06/2016	Q:	How do we calculate the weight percent for NH4CL in the stream?	(1)
16/06/2016	Q:	What are the potential causes for higher pressure drop in FCC stripper column?	(4)
15/06/2016	Q:	We have crude distillation unit and normally operated at 0.3 kg/cm2 top pressure. Since the change of feed composition which tend to the lighter crude then the operating pressure reach 0.9 kg/cm2. do you have any experience to limit the operating pressure of CDU in order to make sure valve tray inside the column not released from the tray itself? More info: Maximum allowable Working pressure of CDU Column is 3.5 kg/cm2 Desain operating pressure is 0.6 kg/cm2 (top pressure).	(4)
13/06/2016	Q:	Why is heater outlet temp of VR feed ie COT temp maintained at 498C not 487 or 467 or 477 or 475 or 482 or above 500? And what is effect of temp and pressure on coke yield inside drum?	(3)
12/06/2016	Q:	Can someone please tell what global delta T minimum is, in pinch analysis?	(2)
08/06/2016	Q:	A trip is provided on high tail gas temperature of Sulfur Recovery Unit. It will bypass the amine system & tail gases will be directly routed to Incinerator. Why this trip is provided?	(3)
06/06/2016	Q:	Why is stripping steam used in crude distillation column?	(5)
02/06/2016	Q:	Ours is Axens liacence CCR we are facing frequent problem of regen gas drier cyclomatic valve stucking and when valve opened some power type material observed must be desi ant. Does anyone suggest how to overcome this problem. Second issue is though regen drier working fine dew point varies from +5 to - 30 deg c. Is this because of activated alumina property loss or dis functioning.	(2)
01/06/2016	Q:	How can we calculate the recycle ratio in coker unit?
31/05/2016	Q:	What are the potential problems if we have higher grid pressure drop than expected at conditions?	(7)
31/05/2016	Q:	Our client has recently started processing heavy crude slates from Western Canada. They are having an issue with their Desalter Brine Treatment Unit (BTU, which is a pre-treatment plant for oily solids removal before being sent to the de-oiling train) with higher than design temperatures and light hydrocarbon carry over. Does anyone have experience with this issue? Is steam stripping prior to BTU an option for dealing with this issue? Additional: Thank you for the responses so far. This has provided some insight into the issue. As a follow up, is there any experience with steam stripping of the brine. I believe some refineries in US have this unit for BTEX removal. How efficient would this be for light hydrocarbon removal? Also any insight into requirement of an equalization tank upstream and if solids removal is recommended upstream of the stripper?	(4)
31/05/2016	Q:	What is the typical Distillation D-86 we maintain for LCGO and HCGO streams in Delayed Coker unit? When trying to maintain the D-86 Distillation for LCGO heavier what are the specific issues we can face in Coker fractionator? We want to achieve D-86 T95 at 385 deg C, is it possible or we can face issues related to mis-operation or coking in the column? Additional info: Our worry is related to initiation of coking for HCGO stream if we try to cut the LCGO heavy up-to 380 deg C or 385 deg C. As per typical guideline of Licensor, 370 deg C should be the end -point of LCGO stream.	(2)
30/05/2016	Q:	I have noticed during simulations of CDU ovhd stream that the dew point temperature increases with the increase of neutralizer dose. Also, I noticed that the pH of the aqueous phase remains low for certain temperature range below mentioned dew point temperature. As I have learned, this point is called ionic dew point and is characterized by lower content of water (therefore high H+ concentration). Does anybody have more experience with this phenomenon? Could it be the reason for severe corrosion in ovhd stream?	(2)
30/05/2016	Q:	What is the molality in a solution containing 0.30 Kg mole of solute and 600 kg of solvent?
17/05/2016	Q:	In our CCR we are facing with the feed side plugging of the Packinox CFE heat exchanger. Could you tell me the reasons of this phenomenon? Have anybody experienced the same? What about the solutions? Till when is it worth cleaning?	(7)
17/05/2016	Q:	Why does Chloride stress corrosion cracking and PASCC only happens in Austenitic SS?	(1)
15/05/2016	Q:	How can sulphur in Kerosene and RVP of Naphtha in CDU be optimized using APC?
15/05/2016	Q:	Crude heater is twin cabin type which is operated at 367degC for heating crude from preheat-2 to crude distillation column. There are total 8 passes, 4 passes in each cabin.Pass 1-4 in one cabin and rest 5-8 in another cabin.From past 8 months, To minimize the deviation in all passes coil outlet temperature,when flow is increased in pass 5 & 8,its coil outlet temperature increased rather than decreasing and pass 6 & 7 coil outlet temperature reduced when its flow reduced.Also, this effect is observed in skin temperature. However, it is confirmed by checking temperature of radiation outlet with temperature gun and ensured the deviation. When flow in passes 5-8 is made equal, deviation in its coil outlet temperature reduced for the same heater box temperature. However no such issue is found in rest passes i.e. pass 1-4. What can be the possible reason?	(2)
14/05/2016	Q:	Are there other methods of removing salt from crude oil besides using Desalter?	(3)
13/05/2016	Q:	How to limit the coke content on spent catalyst in a Platforming reactor?	(8)
13/05/2016	Q:	What are the ways to reduce cutter stock % in visbreaker unit without affecting fuel oil quality? What are the factors one should consider while selecting particular stream as a cutter stock? And, what is typical % ?	(2)
11/05/2016	Q:	What are the recommended dosages of caustic in the crude unit for controlling overhead boot water chlorides? What is the desired limit of sodium in VR? Do anyone has experience of dosing organic neutralizer in crude?	(6)
11/05/2016	Q:	LPG amine absorber is design for 15t/h sour LPG from crude unit and delayed coker unit and we are running it at 20t/h. Amine flow rate is 24t/h for absorption. Column operating conditions is 13.8kg/cm2 and 36degC. Delta T between lean amine and LPG is maintain between 5-8degC. We are facing problem of continuous Hydrocarbon carry over in Rich Amine from absorber. What can be the possible reason?	(5)
11/05/2016	Q:	Can someone share experiences of corrosion in alkylation units ? How do you control it ? Do you add chemicals for the same?	(3)
11/05/2016	Q:	What is the difference between I-8 and I-82 catalyst for Penex Reactor?	(2)
10/05/2016	Q:	Our crude vacuum distillation column overflash pump suction strainer gets fequently full of coke. Overflash pump suction temperature is 374℃~385℃, flash zone pressure 21mmhg, top pressure 5mmhg. Metal contents of overflash are 154.7ppmw(Ni 36ppm, vanadium 118.7ppm) and Metal contents of Vacuum Residue are 223.8ppmw(Ni 49.2ppm, Vanadium 174.6ppm). How can we prevent this?	(7)
07/05/2016	Q:	What is the definition of Overflash in a crude distillation column? What are its advantages and disadvantages? Does it ensure liquid flow between gas oil draw off tray and flash zone?	(7)
06/05/2016	Q:	We experience quite at lot of catalyst in the riser bottom after shutdown. What can be done to avoid this catalyst slumping during the course of shutdown?	(1)
03/05/2016	Q:	What are the advantages of using a chemical injection quill for dosing chemicals on crude column overhead system? What are the process parameters need to be specified for a quill?	(4)
02/05/2016	Q:	Regarding C5-C6 isomerization, has anyone an RVP vs RON correlation of Isomerate product?	(2)
25/04/2016	Q:	We are looking at alternative option(s) that could expedite the unloading of residue desulfurization unit catalyst (from reactors) other than typical vacuum-out/jack hammering approach. We have heard about the CO2 explosive technique - and just wondering if anyone has any success stories with that? Any other feasible approach to be explored?	(4)
17/04/2016	Q:	When do we use helical baffles in heat exchangers? In my plant there is a heat exchanger having helical baffles. When I checked its data sheet it says its helix angle is 20 degrees. What does that mean?	(2)
16/04/2016	Q:	Currently we are using service water as wash water to our desalter in CDU. Heat exchanger has LP steam on tube side and wash water on shell side where the wash water gets heated to 120 deg C before going to desalter. When we are trying to use a mix of service water and stripped water as wash water, our exchanger is getting fouled (Scales of salts are being formed on tubes within 2 days). The metallurgy of tubes in CS. IN other CDUs we are able to use stripped water along with service water and no fouling of exchanger is observed. How to proceed to identify the cause of fouling?	(7)
16/04/2016	Q:	In one of our CDU’s recently we had a leak on the joint between the ¾” overhead neutralizer injection line and 24” overhead vapor line of atmos column. Internal corrosion was observed on the leak area. The pipes thickness was measured at different parts around the leak area and found to be OK. It indicates localized corrosion. We are using neutralizing amine as neutralizer. We are unable to find the root cause of the failure. Are there any instances like this in other refineries? If so, what might be the probable reasons?	(2)
16/04/2016	Q:	In one of our CDUs, the wash water to desalter is being heated in a heat exchanger with LP steam on tube side and wash water on shell side. Normally we use service water as wash water. Provision is there to use stripped water also. But whenever we are using stripped water the exchanger is getting fouled with salt scales on tubes and pressure drop across exchanger is increasing within 2 days. We are not using complete stripped water also, while using stripped water, service water is also going as wash water through exchanger. The metallurgy of tubes is CS SA179. How to proceed for analysing the root cause of fouling. It is not observed in other CDU desalters where same type of facility is there.
14/04/2016	Q:	In Some refineries ( not in all ) There is provision Secondary air supply to Burner in Fired Heater to keep flame pattern in shaped. but as Secondary air is not taking part in Combustion process will it not effect to Excess O2 % calculation ?? Is value shown by Digital Device ( Excess 02 %) will be reliable in thus case ????	(6)
14/04/2016	Q:	I have seen some designs in reciprocating compressors which give machine tripping on low low pressure of forced feed lubricator pressure on 2 out of 3 voting logic where as some manufacturers give only alarm and no tripping on low lubricator pressure. Why so?
13/04/2016	Q:	We are facing severe choking problem in jacket cooling system of reciprocating compressors. Currently we are using service water for closed loop circulation but the effect is such that after two or three months of cleaning, the flow area available reduces by more than 60% on an average. Is anyone facing similar problems..? What may be remedial action. ? We flush the system during every available shutdown. During flushing a think slurry like liquid sometimes black in colour is discharged. Service water we are using has similar parameter that of industrial drinking water with slight high Cl content. Additional: The iron content of service water used in the closed loop system is 0.4ppm. We don't suspect any tube leakage in exchanger as well. But surely there should be a problem with the quality of water we are using. The type of deposit we observed is muddy type hardened along the inner wall as lumps. Breaks down if we hammer the outer surface of pipe during flow inside. http://sailinchemicals.com/wp-content/uploads/2015/05/02_Corroded_potable_pipe_-_Credit_-_Nu_Flow_America.jpg The appearance is similar to above image except that the colour is slight orange in nature and more like globular lumps. Additional: It's the reciprocating compressor handling Hydrocarbon and hydrogen. There is no pinhole leak in any lines. After starting of condensate top up, we have found it much better. Only problem with BFW/ condensate is the working temperature. We have managed to change in one of the compressors. however , the other one needs to be done	(8)
13/04/2016	Q:	In our CDU , recently we faced an leak between the joint of 3/4"neutralizer line and 24" overhead vapor line. On observing the leak, it was found to be corroded only near that joining location. The thgickness of the overhead line and neutralizer injection line were measured and found OK. The neutralizer line is joined to overhead line through a half coupling. The leak was on the halfcoupling also. Thickness of overhead line is 9 mm, halfcoupling is 6 mm and 3/4" neutralizer line is 5.56 mm. We are using neutralizing amine as neutralizer. pH is being maintained betweeen 5.5-6.5 and chlorides and Fe in atmos boot water is also under control. We are unable to find the reason for the leak. Are there any instances like this in other refineries? Please help.	(2)
13/04/2016	Q:	As per HAZOP recommendations in one of our CDUs, the recommendation was to provide TAHH with 2oo3 logic to trip the furnace on High COT. Are there any such trips in any heaters? Is it really necessary to have such a trip ? In case, the trip is provided, what should be my temperature on which the furnace should trip?	(3)
09/04/2016	Q:	I recently heard that passivation of Hydrotreating catalyst before shutdown will reduce the hazards by reducing the time of Inert entry in the reactors during shutdown. A process called Catnap passivation is used for the same. Can anyone brief whether it is useful and beneficial...?	(1)
05/04/2016	Q:	In our crude distillation unit, Main Fractionator bottom pump (Service RCO) is having frequent primary seal leak, period varying from 8 hours to around 2 weeks. The crude processed is North Gujarat Crude which is a high TAN crude having RCO potential of about 65%. Suction specific speed was checked which is well above its rated value. How this problem can be solved ?	(1)
05/04/2016	Q:	Effects of high pH on corrosion. Low pH can cause so many adverse effects but what are all the possible effects of high pH? This question arises because of limits used for pH. There is always a limit to the upper side too. For example, pH should remain within 5.5 to 7.5 in Crude distillation column. What are possible effects of pH> 8?	(5)
28/03/2016	Q:	What is the correlation of increase in Delayed Coker yield with increase in Coke Drum inlet temperature?	(5)
28/03/2016	Q:	I am looking in the possibility of replacing the let down valves after the CHPS and HHPS bottoms (in Hydrocracker), with Power Recovery Turbines. Is there way to estimate how much power would I get? And is it reliable to use the power recovery turbines instead of let down valves? Other than that, are there other alternatives to recover that power?	(1)
15/03/2016	Q:	We were using spent caustic from merichem unit in net gas scrubber instead of fresh caustic to treat off gas in our isomerization unit. It has caused heavy corrosion in monel distributor inside the scrubber. What may be possible reasons for corrosion? Has anybody else faced the same issue?	(3)
10/03/2016	Q:	We are producing bitumen from atmospheric distillation column thanks to low API crude. In crude distillation unit, all atmospheric residue is directly sent to the bitumen tankage. We can produce the 50/70, 70/100 and 160/220 bitumen spec. easily from atmospheric distillation columns. However, we have some obstacles to get on spec about increase in softening point in bitumen. We have maximized the furnace outlet temp., stripping steam rate and also diesel draw amount but still softening point value is not in limit value. When we maximize the all operation parameters, increase in softening point is still above the spec values. (Limit value is 9 C for 50/70 bitumen, we could get 11 C which is the best value that we have got.) At this point, we want to ask a question that do you have any practice about increase in softening point in bitumen? Do you have any advice to get better increase in softening point in bitumen?	(1)
10/03/2016	Q:	1. What is the contribution of lower/upper LCN recycles and lower/upper C-4 recycles towards dry gas and c3/c4 yields, assuming that riser outlet and regenerator dense bed temperature are constant. 2. What is the contribution of lower and upper slurry recycles towards coke and slurry make? We have a low CCR feed and coke/slurry yield is low. So, continuous torch oil injection is there to maintain regenerator dense bed temperature.	(3)
10/03/2016	Q:	What are the factors need to be considered while selecting wash water to an overhead of the crude column? Currently, the only source of wash water is from desalted crude and stripping steam to the column. We have observed salt deposition in the overhead coolers and of the opinion that wash water will be a good option in future revamp in spite of using chemicals in the overhead.	(1)
10/03/2016	Q:	Does anyone have any experience in using fuel oil for heaters/boilers firing? What is the typical size of bucket filter (i.e. mesh size) at pump discharge that supplies acceptable particle size to the burners? What would be the typical minimum filtration size, anything lower than < 10 micron with bucket filter?	(2)
03/03/2016	Q:	Does increasing CDU load have an effect on overhead corrosion?	(1)
02/03/2016	Q:	Which are the causes of an temperature increasing inside of an absorber tower amine-gas? anf if this happens what are the amount of increasing, our operational inlet temperature amine is 45°C (113°F), gas 39°C (102 °F), outlet gas temperature is 60 °C (140 °F).	(1)
22/02/2016	Q:	Why is reactor feed introduced at top of the reactor?	(2)
19/02/2016	Q:	About DCU. Can someone tell me if there's a mathematical correlation, study, paper or model that relates furnace metal tube´s temperature and transfer line temperature?. I need to estimate operative circles between decoking with different scenarios and I don't have much data about these.	(1)
19/02/2016	Q:	What are the techniques used in CCR unit to reduce catalyst dust while draining catalyst fines?	(1)
17/02/2016	Q:	We are facing some problems of coke carryover from drums even on low throughput. This problem, as per analysis done by us, was caused by deagglomeration of coke particles which in turn were easily getting lifted at lower overhead vapor velocities. What are the properties of Crude which help in agglomeration of coke particles?	(1)
14/02/2016	Q:	Is Tatoray reaction (Reactor in which C7+C9 gets converted to C6+C8 aromatics..licensed by UOP) prone to run away reaction? If it is then what are the possible scenarios when run away reaction may occur in Tatoray units?	(1)
13/02/2016	Q:	What are the conditions of auto-ignition of hydrogen rich gas, when leaking through any point of hydrogen recycle system to atmosphere? Is there any differences between hydrogen rich gas and hydrogen make-up gas regarding this issue?	(1)
09/02/2016	Q:	What will be the PONA content of vacuum gas oil which is used in hydrocracker?	(1)
09/02/2016	Q:	In hydrocracker unit what are the amount of heat of energy invloved for following reactions. 1) olefin saturaion 2) aromatic saturation 3) denitrification 4) desulfurisation	(1)
03/02/2016	Q:	We have LPG caustic wash and water wash systems.Similarly,we have Naptha caustic wash and water wash systems.Frequent caustic carry over in product LPG and Failures in copper corrossion due to exhausted caustic solutions is a operational problem.Is there any continuous monitoring instrumentation available to check circulating caustic strength in caustic wash system? Similarly any instrumentation exists for monitoring recirculating wash water for caustic carry over symptom needing wash water replacement? If so advise/share	(4)
01/02/2016	Q:	For how long we can run the hydrotreater in recycle mode , if less feed is available?	(4)
28/01/2016	Q:	What is the purpose of pre-heating the sour water feed (by exchange with the bottoms of the column) before entering the sour water stripper, if it will increase H2S content and water?	(6)
26/01/2016	Q:	I am looking after delayed coker unit. We are operating 4 drum coker with 1kg pressure, 496 COT. We are frequently facing problems during coke cutting, in terms of Hot spots, bed collapse, lot of stem comes out at cutting deck during intial drilling operation.. When ever we tried to increase cot , coke drum cone portion cutting becomes very difficult. Can anybody tell me what are the reason's for this, how to avoid?	(2)
25/01/2016	Q:	Our Deep Catalytic Cracking unit Wet Gas Compressor (WGC) seems to be an over-designed one as its operating at the minimum governing speed(MGS) with the anti-surge valves around 35% open even at 90% plant capacity. Due to this the speed/performance controller is operated in manual mode making it difficult to control the reactor pressure. Is it possible to change/lower the MGS of turbine so as to bring the speed control in the unit's operating range and thus keeping the reactor pressure control in AUTO. If not, is it advisable to tune the ASVs so that they close at a lower load?	(5)
20/01/2016	Q:	How can I calculate heat of reactions in a hydrocracker unit?	(1)
20/01/2016	Q:	Can someone tell me why steam is not introduced in Delayed Coker Main Fractionator like other fractionator columns in refinery??	(5)
18/01/2016	Q:	What is simplest method to Convert Nm3/hr to kg/hr For gas mixture ( H2 +H2S)?	(2)
13/01/2016	Q:	I m working in DHDS unit. where Reactor outlet material ( H2s, H2, Treated Diesel, N2 compounds etc) flows to series of Exchangers( 10 no.) tube side . Currently we found minor leak at drain line (CBD) of last exchanger outlet (press.44 kg Temp 125 °c) . Try to attend with online clamp with material filing( Benzola material used) but no effect. Any other material or method to fill up the leak?	(2)
08/01/2016	Q:	In our semi regenerative catalytic reforming unit we are facing problems of low recycle gas purity.70-72%. Octane has been in the range 92-93 as per design. Reformate yield is around 83% against design of 86.%.Our stabiliser off gas production has been incresed by 3-5 % and reflux control valve has been opened fully. Ratio of C1+C2/C3+C4 is higher 1.9. PCE dosing @1.5 ppm	(8)
06/01/2016	Q:	Is necessary to remove all coke in a soaker drum of vibreaking before starting? What the risks? The coke covers 20% of the flow area.
01/01/2016	Q:	Our NHT feed is designed for C5-90 cut Straight naphtha with no olefins, We are facing problem of increase in reactor outlet temperature of approx. 5 degc(from 324 to 329 degC) for the last 2-3 days . our feed comes from storage tanks( N2 blanketing) which is directly coming from avu column what could be the possible reasons for high temperature increment in NHT Reactor exotherm? Please kindly suggest the causes	(6)
29/12/2015	Q:	In our new octanizing unit (axens) we have gas dryer in catalyst regeneration section, but in some cases we need to bypass the dryer and we don't know can we do this without shutting down the regeneration section or not?	(4)
26/12/2015	Q:	Our Deep Catalytic Cracking unit, commissioned an year ago, is constrained with high stripper/absorber pressure drop problems. When stripper feed temp was 42 deg, stripper exhibited high del pr even at 80% loads. After failure of HPS inlet condensers cooling water exchangers, the stripper feed temp increased to 67 deg C. Though the stripper del P peaked around at 95% load, but absorber column del P exceeded the max operating value. What may be reasons behind stripper del P incursions? What is the optimum stripper feed temperature?	(4)
25/12/2015	Q:	We are getting very high iron and chloride content in our stripped water processed in sour water stripper unit which is used in our DHDS unit. What can be the possible reason and what we can do to minimize it?	(5)
21/12/2015	Q:	In our FCC, we are facing problem i.e. flue gas line TSS-FSS flange leak, causing heavy erosion of the flange and catalyst loss through the leak. Therefore, i request you to confirm whether is it possible to do lip seal joint for these flanges or any other parameter to check the compatibility for lip seal joint of these flanges..	(3)
18/12/2015	Q:	1) Does the higher hydrocarbon condensing at the discharge side due to the increase in pressure in a liquid ring compressor can go back to the suction side if the volume of condensation of the hydrocarbon is more due to the change in the vapour composition? 2) Which affects the capacity of the liquid ring compressor a) heavier hydrocarbon like C5 & C6 in the suction or b) Heavier hydrocarbon vapour in the discharge port due to increase in the discharge pressure due to compression.
14/12/2015	Q:	How much fuel gas (typically) can be used as stripping medium for the treatment of sour water (i.e. 150-170 kg of steam per m3 of sour water)?	(2)
11/12/2015	Q:	We are facing frequent choking problem in phenolic water stripper bottom pump strainer. Phenolic stripper is operated at 1.4 kg/cm2 of top pressure. Column top temp is 93 deg C & bottom temp 129 deg C. Column bottom section has reboiler which use saturated LP steam (157 deg C). It is prudent to note that phenolic water feed pump is not getting choked. Can anyone have a solution to overcome the choking issue??	(2)
11/12/2015	Q:	The bottom part of our atmospheric distillation tower operates at 350oC, and we are giving the superheated steam to the column at around 420-430oC. Let's say, we want to decrease the temperature of superheated steam to 400oC but still it is superheated steam of course. Might it have any effect on the distillation of the products or the quality of the products to decrease the temperature in this manner?	(7)
11/12/2015	Q:	I am trying to find out the bore dia of restriction orifice plate to be placed in flushing oil line of 3/4" S80 going to a flow instrument handling Clarified oil. To calculate bore dia and thickness of restriction orifice plate, I need either pressure drop or flow across the plate which are not available. Flushing oil pressure is 14 kg/cm2 g and the flow instrument is operating at a pressure of 10.7 kg/cm2 g. How can I calculate bore dia with these details?	(2)
10/12/2015	Q:	Why does Hydrogen run counter to Joule-Thomson principles for gases?	(3)
05/12/2015	Q:	TLV and STEL of H2S is 10ppm and 15ppm, for SO2 it is 2ppm and 5ppm! But H2S is considered more toxic than SO2. Why?	(1)
04/12/2015	Q:	We are operating HCGO/VGO as feed in Coker hydrotreater unit with system pressure of 95kscg. But actual feed quality is much better than design feed quality.In fact Hydrogen partial pressure is maintained more than design 91 instead of 86 with purity recycle gas as 95%.We thought of optimizing hydrogen consumption as well as power reduction by reducing system pressure . Can anybody tell ,will this attempt help us to bring power in MUG? otherwise how much can I go down further on system pressure ? And I wanted to calculate based on feed spec, how much gas oil ratio is required for my system? Can anyone share calculation basis to arrive gas oil ratio and system pressure to maintain?	(3)
04/12/2015	Q:	For the first startup of crude distillation unit, since we did not have any startup gas oil for flushing procedure (cold and hot circulation), we used the crude as flushing stream. According to operating manual, after establishing of gasoil we should store it into relevant storage tank and then stop the process. After that we should flush the system with existed gas oil, again. I want to know, when we are producing gas oil why should we stop the process and go back to flushing mode?	(4)
26/11/2015	Q:	Recently, because of some difficulties, we have substituted demineralised water injection system with HP boiler feed water branched from HP BFW header. So, HP boiler feed water is being injected upstream of air cooler while it contains oxygen scavenger, amunium, and phosphate materials. In addition, the temperature of HP BFW is 80 degree centigrade higher than demineralised water's. By focusing on this, are there any consequences about this substitution for a long time of operation?	(1)
22/11/2015	Q:	We have some LPG Merox units with amine absorber before the Merox unit. We use MDEA in the amine absorber and we have experienced some problems of amine carryover in the LPG. Can anyone comment on the impact of the amine contamination in the Merox units? Besides the possible formation of emulsions, could there be any other problem?	(6)
16/11/2015	Q:	What is the range of UOP R134 catalyst density? Is it ok to assume that the density of Fresh catalyst (R134) is the same with the Spent Catalyst when calculating the weight of the catalyst? Is it possible to overload reactors (3) in a (vertical) stack with catalyst in CRU?	(3)
16/11/2015	Q:	We have recently observed a high production of off-gases from our Vacuum Distillation Column. We performed the distillation for the feed and observed that the initial and 5% boiling point had reduced significantly. Could this be the reason for the increase in the off-gases? On the other hand, we suspect an air ingress into the system. Is there is any way to detect/prove that there is an air ingress into the system? Added by questioner: Thank you very much for your input. I gained a lot of insight from your answers. After closely studying all your suggestions, we took into consideration a number of points and implemented them. One of them was sampling the off-gases, from which we found a high % of Nitrogen which clearly indicated air ingress. As a result, we tightened the transfer line gasket and the off-gases flow reduced by 50%. Thanks once again.	(6)
14/11/2015	Q:	What could be the causes of sudden drop in conductivity of Jet fuel in a storage tank??	(2)
13/11/2015	Q:	We are suffering from water carryover with tail gases form quench top in tail gas treater unit of Sulphur Recovery Block. In case of absorber bypass due to S/D of Common Regeneration Unit; tail gases are routed from quench tower top to incinerator which results in water accumulation inside incinerator which is a major problem. To tackle this it has been planned not to bypass absorber and flow tail gases from absorber without any amine flow. I wish to know what could be possible ill effect or problems with the same?	(1)
07/11/2015	Q:	Why at low plant load S/C ratio is to be kept high?	(3)
05/11/2015	Q:	we are suffering coke formation inside our VDU heater, considering high tube hardness we can't preform steam air decoking, the other alternatives are pigging and chemical cleaning. Any advice about the difference between these methods, concerning risks, operation, concerns, disadvantages?	(3)
04/11/2015	Q:	What is the test method for determining hydrocarbons in amine solution?	(1)
28/10/2015	Q:	We have cook formation inside the coils of VDU heater and the metal of this coils are suffering from a hardness, Which method is the optimum for decoking, steam air or pigging to avoid metal damage?	(3)
28/10/2015	Q:	Is it feasible to reduce CDU heater HOT to reduce CDU column pressure ?	(2)
22/10/2015	Q:	In a small topping plant we are experiencing a high quantity of organic chloride in Naphtha: about 5-10 ppm whereas requirement is less than 1 ppm. We don't know where this is coming form. Crude has less than 2 ppm (the astm method to determine organic chloride in fact distill off naphtha to check organic chloride). Is there a treatment method? Heard that activated charcoal can be used. The other issue is the inlet line to tank has 1.8 ppm but the tank has 5 ppm.	(1)
21/10/2015	Q:	What is the acceptable level of hydrocarbon removal (%) across the Activated carbon filter in Amine slip stream?
21/10/2015	Q:	What is the maximum level of hydrocarbons permissible in lean amine so as not to cause foaming in the FCC offgas Amine absorber?	(2)
19/10/2015	Q:	We have Cyclemax continuous catalyst regeneration in CCR, but it has been observed that regeneration gas flow to Regenerator FI reading goes low and on low flow Hot shutdown occurs. Its LP and HP tappings have been cleaned , but still it shows low flow. Can you please suggest what else could be the reason and how to resolve such issue??	(3)
18/10/2015	Q:	We are looking for a non hydrotreating based technology to decrease condensate sulfur content to lower than 200 ppm. There is a condensate stream in our refinery in which its sulfur content decreases from 3300 ppmw to 1000 ppmw by caustic wash and we need a further decrease of sulfur content to minus 200 ppm, but not with hydro desulfurization. Please advise.	(5)
16/10/2015	Q:	What is the max temperature up to which we can circulate recycle gas during start up without pre-wetting the catalyst in unionfining process to avoid sulfur leach out from catalyst? (Main catalyst KF 757 1.5E STARS)	(2)
08/10/2015	Q:	What happens if I put a Reciprocating compressor in a loop i.e The discharge of the compressor is sent to its suction? What do you think will happen to the temperature, wattage and pressure in the circuit?	(2)
02/10/2015	Q:	In a condensate refinery (50 API) where only source of water is the feed (less than 0.2 %) with salt values are less than 2.0 ppm, we have observed huge corrosion in the stripper, atmospheric column and stabilizer overhead line. All the overhead receivers run dry and water quantity is very low. Please note that there is no addition of chemicals like corrosion Inhibitor, neutralizer or ammonia. The top temperature for all the columns (except stabilizer)are in the range of 130-160 deg.C (pressure is 3-6 par). What are the possible reasons and how to prevent the same?	(2)
25/09/2015	Q:	What is maximum limit of Iron in the Platformer Feed? What is the effect on Platformer catalyst like R56 or R86? How can we control Iron in the feed with suitable filters?	(2)
23/09/2015	Q:	What are the reasons for variation in JP-8 fuel conductivity and how can they be minimised?	(2)
22/09/2015	Q:	Is it possible to reduce reactor stripping steam ring steam flow below minimum, if min dP criteria is passing? This is to increase regenerator dense phase temperature as we are not able to make required coke.	(3)
12/09/2015	Q:	What is the most cost effective method of removing sludge from a crude tank bottom?	(1)
07/09/2015	Q:	What is the difference between weathering and RVP?	(3)
04/09/2015	Q:	We have two trains of Sulfur Recovery Units having capacity of 35 MTPD. It is planned to carry out Turn Around Maintenance (TAM) of these units shortly. I request sulfur experts to share their experience in emptying the molten storage pit and steps to be taken to handing over the pit to carryout inspection of steam coils, storage pit walls and floor.
01/09/2015	Q:	Currently I'm doing pump test with water, I want to know what is the best way to compare the flow from the FT and the flow in the pump curve, the Flow Transmitters are set for hydrocarbon with SG of 0.65 but I'm doing the test with water which SG is 1. Do I have to correct the flow to HC flow at conditions or standard conditions in order to compare the flows with the curve?. How can I do that?	(2)
01/09/2015	Q:	In CCR platformer high purity hydrogen is produced using PSA, PSA outlet tailgas contains 40-50% H2, flow is about 4-5 TPH and pressure 5-6 Kg/cm2g. Can we use this gas to recover further Hydrogen by PSA or membane separation processes? We have a spare PSA available. Can we feed low purity gas to PSA?	(2)
31/08/2015	Q:	How is 'COS' formed in FCCU riser-reactor section and what are the measures necessary to minimize its concentration to avoid slippage of 'COS' into product LPG/Propylene?	(4)
28/08/2015	Q:	Any experience about neutraliser, filmer dosage and wash water incection into the O/H line of mail fractionator on FCC Unit. Is it allowed to mix neutraliser anf filmer into the washwater line? What is common practice for injection of neutralizer, filmer and washwater and why?	(5)
28/08/2015	Q:	We have Refinery off gas PSA processing CLPS off gases from hydrocracker and CCR off gas at 23 kg/cm2g. Tail gas from this PSA is at 0.5 kg/cm2g which is compressed to 4 kg/cm2g using oil flooded screw compressor and routed to fuel gas header. During upset or flow variation in PSA frequent LO filter choking is observed for the screw compressor. Sometimes the filter choking is so fast that compressor trips on high differential pressure between LO and gas. What could be the reason for such high filter choking during particular time of PSA variation. We then clean the oil using continuous filtration and it takes 2-3 days to again normalize the things. Once the lube oil DP gets normalized it continues to run longer without any LO filter change out. Blackish deposits are observed on filter cartridges. Is anyone facing similar issue in tail gas screw compressor? What remedial actions are available to resolve the issue?	(2)
25/08/2015	Q:	We have safety valves on LNG discharges tank discharging to atmosphere through a tail pipe approx. 25m long.To prevent ignition of the release in the event of a lightning strike, would it be acceptable to provide a flame arrestor on the vent?	(4)
20/08/2015	Q:	We have a two coke drum DCU. We are facing issue of high Sulphur content in our pet coke. The feed quality has been fairly consistent. Normally we have been operating with a cycle time of 18 hrs & COT of 501 Deg C since last two years. The issue of high sulphur has surfaced over the last two months only. Can anyone suggest the reason?	(5)
20/08/2015	Q:	We are operating a kettle reboiler connected to a distillation column. Heating is in a 3 metre long U-tube steam heat exchanger. Steam is at 10 kg/cm2 pressure. In the shell side dilute alcohol is evaporated at temperature of 100 deg C.U-tubes are welded in the tube sheet. we are facing the problem of frequent leakage from welding. Tubes and tube sheet are SS316 material. The tube bundle is adequately supported. Does condensing steam create vibration in the u-tube? Welding leakage from top few rows are predominant.Would appreciate for suggestion to avoid such problem.	(2)
19/08/2015	Q:	We are operating our DCU with COT at 501 Deg C. The feed quality is also more or less constant. For the last month and a half months we have seen increased sulphur in our coke in excess of 9 wt %. Can anyone suggest the probable reasons?	(2)
15/08/2015	Q:	What's the safest way to clean a Acetic Acid Pipe line of 100 meters of longitud, to cut with fire and repair? Currently we clean the pipe lines getting them full with water, 30 tons/hr flowing to an a storage tank truck, around 30 minutes, after we use nitrogen to blow (7 bars) the acid and water to a tank truck. We do this three times, to make sure the pipe line its very clean. After that, we dry the line with air, 8 hours, then we seek LEL % whit a SIRIUS MSA device, if there is a 0.0 % LEL, we inject a inert chamber (using nitrogen very low pressure). Then we make the first cut using fire. We use nitrogen because its a inert gas and it displaces the air and so we prevent the formation of an explosive atmosphere. If you have another practices or examples I'll be glad to learn.
14/08/2015	Q:	Many of the operating plants inside a refinery complex use fresh caustic to sweeten the gases/Naphtha products. Almost all of this spent caustic is then transferred to Effluent Treatment Plant of this spent caustic. Are there processes available which may be utilised to regenerate this spent caustic?	(4)
13/08/2015	Q:	In a vacuum column overhead ejector condenser, Cooling water supply pressure and cooling water return pressure (Both at ground level battery limit) to condenser (as provided to vendor) is 3.5 Kg/cm2(g) and 2.5 Kg/cm2 (g) respectively. As per the elevation drawing and layout, cooling water supply pressure at inlet of first stage condensers appears to be around 0.34 Kg/cm2g considering static head and frictional loss. At the outlet of condenser pressure becomes -0.16 Kg/cm2g considering differential pressure across first stage condenser in cooling water side as 0.5 Kg/cm2. With this condition cooling water flow will be established across condenser or not? If not, will placing the isolation valves of return line at ground level help in water circulation across condenser?	(1)
10/08/2015	Q:	In Hydrogen plant steam flow is fixed at 30-70 % plant load in Haldor Topsoe unit, while in Linde hydrogen plant steam flow is fixed in between 30-50%. What are the reasons for this difference?	(1)
05/08/2015	Q:	Could high moisture in recycle gas contribute to cracking in CCR reactor?	(4)
03/08/2015	Q:	Why is the Pitot tube placed at a 45 degree angle during installation in cooling water supply? What is the reason for placing at this angle?
31/07/2015	Q:	In our wet Gas compressor we experience frequent seal oil migration/leak into lube oil. Wet seals exhibit low MTBF. How can we eliminate seal leak and enhance sealing performance? Is dry gas seal a reliable solution in wet gas compressor?	(4)
30/07/2015	Q:	I am measuring the level of the catalyst in regen with d/p transmitter,the distance between taps is 498 " the density of lower section 25#/ft^3 and upper 3#/ft^3 What is the cal range " WC? It's continuous purge.	(1)
30/07/2015	Q:	Please advise as to how catalysis bed levels are measured in FCC REGEN using differential pressure also how density is calculated from d/p. Are dip tubes used similar to bubble system?	(2)
29/07/2015	Q:	In our VDU furnace there are 4 cells & 1 coil/cell. In last few days suddenly few coils in cell 1,2 & 4 from the bottom started lifting up from the support inside radiation zone. Even few coils are floating continuously. While RCO entering the furnace pass4 comes first then 3,2 &1. Coils are horizontal. What could be the reason?	(1)
29/07/2015	Q:	For VGO Hydrotreating units at the upstream of the FCC, we currently use COMO Catalyst. The unit is operated by maintaining constant Sulfur spec in the sweet VGO which goes to FCC. Typically VGO feed sulfur is ~22000wtPPM and Nitrogen is ~2200 wtPPM. After processing in hydrotreater, sweet VGO sulfur is ~1500wtPPM and Nitrogen is ~1000wtPPM. Now the question is that if I change the catalyst from COMO to NiMO catalyst and maintain remaining all operating parameters same, what would be the Nitrogen conversion if I operate the unit by maintaining Sulfur level 1500wtPPM which is same as earlier? Will the Nitrogen conversion increases because of NiMo catalyst or it remains same since we are constraining the unit severity by maintaining same sulfur level?	(4)
23/07/2015	Q:	In our VDU furnace there are 4 cells & 1 coil/cell. In last few days suddenly few coils in cell 1,2 & 4 from the bottom started lifting up from the support inside radiation zone. Even few coils are floating continuously. While RCO entering the furnace pass4 comes first then 3,2 &1. What could be the reason?	(2)
20/07/2015	Q:	In CCR unit we have 85% rich H2 coming from PSA as off gas. Currently we are using in the fuel gas mixing feeding our furnaces. I would like to ask whether it can be used in more fruitful ways? Can it be combined in HGU at any stage as we already have 85% pure hydrogen??	(3)
13/07/2015	Q:	What are the methods available to maintain the electrically traced liquid sulphur pipe (OSBL pipe) when the elbow leaks?
13/07/2015	Q:	What is the meaning of regeneration cycle duration in ccr refromer? And how could the catalyst circulation rate be about 200 and the burning capacity is a round 12 ?
10/07/2015	Q:	We plan to purchase regenerated catalyst for our kero and LGO hydrotreater. We did regenerate our own catalyst, but never purchased one from an external company. What parameters should I pay attention to, what are the recommended limits for poisons and other parameters to guarantee a near-fresh activity and lifetime?	(3)
02/07/2015	Q:	Currently we have issues in our naptha cracker plant where our production is limited due to cooling water temperature. Since it is monsoon season, the cooling tower is not able to cool the water effectively. What are the alternative solutions or modifications that can be done to increase efficiency of cooling tower?	(1)
29/06/2015	Q:	Currently my plant is experiencing overhead vacuum fluctuation from 20 mmhg to 40 mmhg. The design overhead vacuum is 20mmhg and maximum throughput is 20MB. The ejector system consist of 3 stage ejector. The first stage ejector consist of 2/3 ejector and 1/3 ejector load. The second stage ejector consist of 3 ejector, and normally 2 out of 3 online. The third stage ejector also consist of 3 ejector, and normally 2 out of 3 online. We had perform field survey and found that the second stage ejector temperature is relatively low compared to the other ejector (26degC vs 70 degC) Earlier, we suspect air ingress in to the ejector and we had perform online inspection. and indeed, we found 1 coin size leak at one of the first stage ejector and the leak had been repaired. however, the vacuum fluctuation is still there. We had also verified all the other ejectors for leaks but unfortunately no leak was found. We are also having issue with the ejector condenser. the third stage ejector outlet temp is relatively high compared to the other condenser (65degC vs 40 degC). This problem was there since a few years which had eliminate the condenser as the root cause of the fluctuation. Currently we are trying to search of other weak point which can cause air ingress into the ejector/vacuum system. Appreciate your feedback on the matter.	(4)
24/06/2015	Q:	In cyclemax of of CCR unit, we had issues with fines collection for around 15 days. But thereafter when we performed the fines collection 350 kg of fines was removed. This surprisingly seems to be large amount. Is it due to new catalyst ? What should be the real amount of fines collection per day? What could be the reasons for higher fines generation?	(3)
23/06/2015	Q:	In HDS reactor the hydrogen consumption coming down when catalyst life moving to end of run ,even though the feed and product sulphur remains the same.( usually the temperature of BED have to increase for achieving the same product quality). What is the reason for this hydrogen consumption reduction?	(2)
21/06/2015	Q:	In vortex flowmeter flow corrections ( for std volumetric flow ), when one should use compressibility and for automated calculation in a dcs or excel, instead of compressibility, can density be used?
20/06/2015	Q:	We are facing frequent issue of moisture carryover in the light naphtha stream to our hydrotreater. Does anybody have experience of putting a salt drier in the hydrotreater upstream to remove the moisture. What sort of damage it can cause to the catalyst?	(5)
17/06/2015	Q:	What are the causes of high pressure drop in Kerosene hydrotreater reactor (Kerosene hydrotreating Unit) and how can they be solved?	(4)
16/06/2015	Q:	In VGO HDS,fractionator Naphtha produced contains presence of H2S. So Naphtha is routing to slop. We have increased steam to stripper to reduce the H2S content in Naptha. But no effect obseverved.What can be done to avoid H2S presence of Naptha for routing to storage?	(5)
16/06/2015	Q:	We are observing high CS2 content in our straight run naphtha. This is not on regular basis but frequent and sometime it goes up to more than 20-25 ppm also. Please advise what can be source of such high CS2 content in naphtha intermittently. The sources may be narrowed down to: 1. Presence of CS2 in Crude itself- Please suggest the probability of the same and if any known crude with high CS2? 2. Since CS2 formation requires very high temp, can it be formed in crude heaters? or any other process? 3. Though probability is less, can it come from recycle hydrotreated naphtha?	(2)
12/06/2015	Q:	In Hydrogen Generation Unit the pre-reformer reactor (having Ni based catalyst) differential pressure increases after every unit start-up by 0.1-0.2 kg/cm2. Before reformer feed cut, naptha vapor warmup line is kept lined up and reactor is kept at 470-490 deg C. Also, before naptha feed cut, catalyst re-reduction takes place under hydrogen+steam atmosphere. What is the reason for del P increase after every unit startup?
11/06/2015	Q:	On every "hydrogen generation unit" start up, the Pre-reformer reactor differential pressure increases by 0.1-0.2 kg/cm2. Before Reformer feed cut, the reactor catalyst temperature is maintained 470 - 490 deg C Before feed cut, naptha warm-up line lined up. What is the reason for Pre-reformer del P increase?	(2)
07/06/2015	Q:	What is the difference between UOP R-234 and R-264 catalyst? We have been provided later kind after first TA and replaced former.	(1)
07/06/2015	Q:	In our CCR reactor, there is coking taking place due to which many a times L-valve assembly for catalyst regeneration line gets choked. As far I know Metal catalyzed coking is one of the reasons, so we maintained proper DMDS flow as per licensor. I would like to know what might be other reasons for coke lump formation in reactor. Coke lumps filling the scallops were found during TA opening. Additional: Choking occurred in spent line and not regeneration. During TA coke lumps were removed from scallops by cutting and created window for coke removal and again welded, which unfortunately delayed TA.	(4)
06/06/2015	Q:	We have a screw chiller compressor which is for refrigeration in recontact section of CCR naphtha Hydrotreating unit. We are trying to start it after TA but getting tripped after 3-4 sec. All electrical and rotary side are fine. It is having Interlock of PDI between lube oil discharge pressure and gas discharge pressure. Every time it trips on this and sometimes feed alarm fail comes. Also filter on pump discharge was choked earlier. Please suggest troubleshooting this problem.	(3)
05/06/2015	Q:	We have floating roof naphtha tanks. I want to calculate floating roof weight displacement volume with, density at 15 degc, weight of floating roof. Please suggest a formula.
04/06/2015	Q:	In our single stage centrifugal compressor primary seal gas is ethylene. N2 is provided as backup in case C2 pressure drops due to any reason. What is the safe logic for seal changeover from C2 to N2? Primary Seal gas flow control valve and flow transmitter is in vendor package. There are individual on/off valves in C2 and N2 supply lines, these are in client's scope. Differential pressure transmitter is available across N2 supply on/off valve.	(1)
03/06/2015	Q:	Why is the pilot tube placed at a 45 degree angle during installation for provided reading in flowmeter of cooling water supply and return header? What is the reason for placing at this angle?
30/05/2015	Q:	We have hydrotherapy unit , consisting of cobalt molybedium (s-7 and s-120) reactor, reaction temperature 610 F system pressure 24 bar.We have a problem for two months that is the reflux drum of stripper got very low thickness observed, its boot water has PH 2.0----2.5, iron greater than 100 ppm while chloride was 1000 to 2000 condensate injection 8bbls/h from condenser inlet. We have already done the cleaning of all heat exchanger , overhead condenser, overhead reflux drum. Then start up of the unit was performed but condition remains the same. Please share your opinion regarding this problem.	(2)
26/05/2015	Q:	Usually for protecting trays/column internals from any upsets, an upthrust of 1 or 2 psi is considered. But if the vapor/liquid traffic inside the column is known, how to estimate the upthrust during normal operation?	(2)
26/05/2015	Q:	We have one solvent regneration column which has 4 baffle trays and below which there is a stub-in reboiler at the bottom. Also at the bottom, steam sparger is provided(we think same might have been provided to reduce the boiling point of the column bottoms liquid). Column operates at vacuum (-0.2 kg/cm2g). Column bottom temperature is 187 deg c.Fresh solvent is taken out from top and heavies are removed from bottom intermittantly.The stub in reboiler utilises MP steam(16.5 kg/cm2g) while sparger steam enters at 127 deg C & 1.5 kg/cm2g pressure. The problem is, tubes of this bottom stub in reboiler fail every year and many times, tube bundle is replaced. In recent inspection, the bottom two trays were also found to be fallen & accumulated at bottom.Wanted to know, whether is it a good practice to push steam through sparger in the liquid pool over the bundle of stub in reboiler? And, column bottoms liquid is at 187 deg C & steam enters at 127 deg C. Will that cause steam getting superheated and exert forces on tube bundle & trays above? what could be the possible reasons for both failures and what should be done to avoid them in future?Also, would appreciate any good material or information on mechanical stregthening of trays and various calculations involved.	(5)
22/05/2015	Q:	We are designing a direct contact heat exchange system wherein there is a packed bed, hot water enters top of bed at 68 deg C and leaves the bed at 51 degC. Gas which is rich in methane & ethylene enters the bottom of the bed at 33 deg C and leaves the bed at 65 deg C. The intent is gas should get heated to 65 deg C. We are concerned about low approach temperature at the top of bed (68-65=3 deg C). Wanted to know anyone has any experienece with such system? Will that low approach is achievable? Please suggest any other similar system where we can check.	(1)
21/05/2015	Q:	Would like to get expert advice on crude preheat train. We are not able to get the design preheat temp. In the preheat train the last two exchangers are in series. As per design tube side outlet of last exch. should enter at 323 temp. in the shell side of upstream exchanger with both exchangers operating at MTD of approx. 23-25 degC. However as per current operating conditions there is max. heat recovery in last exchangers with very high MTD and the outlet temp. is reduced to very low 290 degC. Due to which the upstream exchanger is operating at very low MTD 8 degC. Based on this finding will it be advisable to partially bypass the last exchanger to achieve the tube side outlet design operating temperature or there is some other issue? Additional Information: Thank you for the replies. I have gone through detailed preheat train analysis and found that in one of the analysis where we were getting the desired preheat temp. there was no cross pinch in the same exchanger as the inlet temp. had sufficiently increased. And this was possible since the flow was meeting the design data. Thus we might have to increase the outlet temp. (keeping in mind the flowrate) from last exchanger but that again has to be analysed since there is one more exchanger in the upstream of train which is in series to these exchangers.	(6)
20/05/2015	Q:	We use immersion type Electrical Heaters in our Refinery. What experience do others have with reference to their cleaning and any replacement of parts?
15/05/2015	Q:	I am working in a Divalproex sodium production plant where we are producing by spray drying of that solution to make the form of powder. Sometimes there is powder choked in the spray chamber. Then we have to shut down the whole system and trying to clear choke. When the choking is cleared, again the process started. So I just want to know why it happens. Is there any rectification for this trouble? If anybody knows about it please help me....	(1)
12/05/2015	Q:	Is it possible to inject DCU Coke fine particles (~ equivalent PSD of FCC Catalyst) into FCC regenerator to avoid using torch oil and afterburning? What are the Pros and Cons of using the same? Please share the experience if any refinery tried the same.	(1)
11/05/2015	Q:	I would like to know the proper actions to be done when there is a loss of PCE injection in the catalyst regenerator of UOP CycleMax CCR Unit. If for instance, the loss of PCE injection (both injection in feed and in catalyst regenerator) would not be addressed immediately and PCE injection would not be available for an 8-hour duration or more, to avoid platinum agglomeration or other cases, will it be better to run the unit in hot shutdown/cold shutdown, or can the catalyst endure the loss of PCE injection, and be able to normalize once injection is resumed upon availability.	(2)
08/05/2015	Q:	We have storage tanks for all products and lines connected to Getty for tankers loading/off loading and the distance about 7 km all lines 14/16 inches and ended in terminal by movs (motor operating valves only). My question is can we install gate valves upstream of movs for maintenanc ? ( the terminal still under construction)	(2)
06/05/2015	Q:	How do I check whether the water cooler tubes have punctured heat exchanger? Cooling tower is tapped with various units like GSU, DPD, SRU etc. Gas is coming in cooling water return line. The unit in-charge says our units are ok. Can we check at heat exchanger? How?	(4)
05/05/2015	Q:	We are currently having problem in debutanizer of our naphtha hydrotreater due to ammonium chloride deposition. However, we do not have online water wash and we do not want to shutdown our unit. We are thinking of injecting steam (while the unit is commissioned). Is onstream injection of steam in the debutanizer to remove the ammonium chloride deposition applicable and effective in a debutanizer? If yes, what are the parameters we can check to safely conduct this activity? If no, are there any other way in order to remove the ammonium chloride deposition without shutting down the unit?	(6)
02/05/2015	Q:	We have refrigeration package of NH3 as refrigerant, from the last 6 month we facing the problem of oil carry over to Chiller and KOD. we have to continuous drain out oil from the chiller and KOD while receiver level is constant in LT and LG both. NH3 package super feed currently isolated as it is suspected that might be there is a leak in super feed coils since its pressure equivalent to receiver pressure. but the LT of super feed is very erratic,a DP type LT which has been attended many times but problem still as it is. please suggest me what type of LT to be provided for the super feed level and what can be the reason of oil carry over to chiller and KOD.
01/05/2015	Q:	In a centrifugal pump the seal flushing oil is supplied from external source. But whenever the discharge valve of the pump is closed the seal flushing becomes zero. What is the probable cause?	(3)
01/05/2015	Q:	I am looking after Delayed Coker Unit. One of the most obvious problem occurred in DCU is high skin temperature of heater coil due to different reason. Due to high skin temperature we are forced to run the unit with low throughput. Online spalling is not permitted by management due to some reason. My query is to avoid high skin temperature in some section of the tube should we put off the burner near that section or can we pinched the burner? But putting off the burner will increasing firing at the other section which may lead to coking up at that section. So what should I do?	(3)
30/04/2015	Q:	we are facing problem of high skin temeprature in one of the pass of CDU charge heater (106,000BBl) refinery. After thermography, it shows even more. we have done following actions: 1. PUT manual the FC for that pass and manually maximized the flow through this pass only. 2. shut off the burner adjacent to this burner. 3. can not do the decoking for the crude heater. Furnace's Pigging is planned next year (2016). But now, we are going to inject the LP steam online into one of the pass. LP steam is used only in case of: - Furnace tripped due to pass flow low low. - Furnace tube fire case. What possible outcomes we can expect with this activity? will it benefit? is there any other technique to remove spalling? Outcome: Thanks for valuable comments. In recent shutdown (planned turnedaround of the plant), we have managed to perform pigging of crude heater and after that, results are much better. no more skin temp issues. We have done pigging for pass more time, tube conditions are normal now.	(4)
29/04/2015	Q:	In a CCR unit we are observing coke type material seeping out from reformate stabilizer column bottom pump suction flange. Although we are dosing DMDS in the feed but can MCC be a reason for this? Else what are the possibilities?
29/04/2015	Q:	We are facing issue of LPG product offspec due to total sulfur high. we have a UOP LPG merox treamtent unit (LPG enter from CDU to absorber> filter> coalescer> Prewash>Extractor>sand filter). design RSH in LPG feed to Merox is 800 wtppm. but currently due to feed, we are processing upto 5000 wtppm. which parameters to be checked thoroughly in order to reduce this offspec. 1. Regen caustic quality (Mercaptide & Disulfide) feed to extractor. 2. LPG to Prewash ? 3. Lead acetate test of which streams will help us to identify at field rather than sending samples and wait for results.	(4)
25/04/2015	Q:	Which is preferable for naphtha hydrotreater catalyst regeneration in situ or off situ , and if in situ what are requirements and steps for that process?	(2)
23/04/2015	Q:	I was asked for evaluation of doing the leak test and pressurization step in the Hydrocracking unit start up with Nitrogen instead using Hydrogen. We have 1 reciprocant compressor for make up and one centrifugal compressor for recycle gas, I would like to know what do I have to consider to make this evaluation, what I know by now is that my recycle gas molecular weight is 4 and N2 is 28, so my centrifugal compresor could not be able to increase the pressure more than 250 psi (aprox). what should I take in account?. Is there any gain doing this?	(4)
23/04/2015	Q:	We process condensate to produce ATF. For 2 months ATF color is deteriorating day to day. What could be the reason?	(2)
22/04/2015	Q:	There are several different options to increase liquid production and reduce coke yield in residue coker units. One of the most widely used is try to operate coker drum at low pressure. But what are the possible options to reduce further the operating pressure in the coker drum? Could the minimum pressure limit (alarm) at the wet gas compressor inlet be reduced? We currently operate at 0,4 kg/cm2. Has anyone experience operating at lower pressure at this point? Has anyone experience installing an on-line water wash in top of main fractionator or condenser to remove salts? In that case, which is the maximum DP reduced with this option? Has anyone experience implementing any other modifications (increase vapor lines diameter, etc)?	(2)
21/04/2015	Q:	I would like to ask about required H2/HC ratio and coker naphtha processing in a naphtha hydrotreater. We have a unit processing a mix of straight run and coker light naptha. Unit consists of two reactors, one for diolefin saturation and one for HDS and olefin saturation, both use regenerated NiMo catalyst. Colleagues intend to raise coker naphtha ratio, which is currently maximized in 12%. I made some calculations which resulted, that coker naphtha has around 90 Nm3/m3 chemical H2 consumption, and the units H2/HC ratio is around 60-100 Nm3/m3 depending on throughput. 12% naphtha results in ~16 Nm3/m3 chemical H2 consumption. If I remember well, the H2/HC ratio should be at least 5 times the chemical consumption, in this case 5*16=80. Am I right, or can this value safely be reduced? Does anything else restrict the max ratio of coker naptha processing? Temperature raise is about 25-28 °C on HDS reactor with an inlet temperature of 290 °C.	(4)
18/04/2015	Q:	What is the minimum FCC riser velocity to be maintained to avoid catalyst slumping or back mixing in the riser?	(1)
15/04/2015	Q:	Has somebody experience with petroleum hydrocarbon resin simulation and separation?
13/04/2015	Q:	I would like to know what is the difference between phenolic stripped wash water or non phenolics stripped wash water in the hydrotreater or hydrocraker process.	(4)
05/04/2015	Q:	Are there approaches/techniques/instrumentation to gauge if you have fouling occurring (from salt deposition) in top trays on crude unit? One can measure top section tray DP, however, the DP may take time to build up. Are there other things besides DP that may give you quicker response on fouling taking place in top trays of crude tower?	(2)
31/03/2015	Q:	Kindly advise the emergency procedures if a LPG road tanker is toppled on the road. What is the procedure for salvage if it does not leak? What is to be done if it leaks and catch or does not catch fire? What is to be done if it forms a vapour cloud?	(2)
27/03/2015	Q:	We are process tar sands crudes at this refinery. The issue is with our vacuum unit steam educators in the VDU, the primary inlet screens are plugging up. We inject a amine neutralizer into the steam to protect the vacuum condensers piping from corrosion. The steam flowrates have reduced drastically. If you have experienced similar issues please let us know. even though we have redundant eductors (3 in parallel) we would like to understand the root cause of the fouling. the deposit analysis have shown major components as C & O. N is also present in addition to Zn.
25/03/2015	Q:	I would like to know if when we design a transfer line of CDU or VDU heater then do we consider erosional velocity as a constraint? The mixed phase velocities in transfer line are frequently higher than calculated erosional velocity (from API-14E).	(4)
24/03/2015	Q:	We have FCC (DCC) commissioned last year, full combustion regenerator. We are facing following problems: a. Both DFAH and torch oil were in line to satisfy heat balance requirement of Rx-Reg. Torch oil firing results in high afterburning in regenerator ovhd line. Also slurry recycle (feed recycle to MF, not slurry generation) injected at reactor stripper section. Is there any possibility of increase in coke make if we stop fresh feed preheater and inject feed at low temperatures? what are other solutions? b. Even after stopping DFAH and torch oil, we are facing problems of afterburning in regenerator. Is the afterburning due to slurry injection at rx stripper section (afterburning temp comes down when reducing slurry recycle), or any maldistribution in combustion air distribution? c. Regenerator Flue gas stack SPM is high when doing soot blowing of Flue gas cooler tubes. Is this due to inefficient working of TSS-FSS or more fines in the circulating catalyst?	(2)
13/03/2015	Q:	Salt content in desalted crude oil should be less than one PTB. However due to some reasons the salt content of desalted crude oil is higher than a PTB , what can be the effects , or the changes it can create in the downstream process?	(6)
13/03/2015	Q:	We are going to carry out steam air decoking in VDU during shutdown in our refinery for the first time. Before that only spalling has been done. I am a fresh Chemical Engineer. So I would like to know what are the problems those are generally faced while air burning process and what are the possible solutions to avoid these problems?	(1)
12/03/2015	Q:	What is the significance of installation of Oxygen analyser to analyser oxygen in ejector off gas line? And what is impact of oxygen in ejector off gas line?	(2)
12/03/2015	Q:	Why does API 618 not cover plant or instrument air compressors that discharge at a gauge pressure of 9 bars (125 psi) or less?
27/02/2015	Q:	We are planning for revamp in naphtha hydrotreater feed / effluent exchanger system. Could anyone guide us on the minimum hot end approach can be taken to design the system. At present we are having hot end approach at 60 degC. Can we add another shell to decrease the hot end approach as we are facing severe constraints in the hydrotreater furnace?	(6)
23/02/2015	Q:	We are trying to determine the appropriate lab test and normal analytical ranges in order to bring imported MVGO to our new hydrocracking unit. Licensor is concerned is about presence of Na and Cl but also other contaminants such as P. What are the normal ranges of Na, Cl and other metals to bring to the hydrocracking unit to avoid catalyst damage?	(2)
21/02/2015	Q:	We are proposing the idea of installing Auto drain valves in our product tanks viz HSD/MS/SKO. Can you all share your experience if any regarding its performance? Will it lead to reduction of HC loss during tank draining/preparation for product despatch?	(1)
21/02/2015	Q:	In a Sulfur recovery unit, reaction furnace minimum skin temperature should be how much to avoid corrosion due to acidic condensation?
20/02/2015	Q:	Is there any mercury limit in crude oil to avoid Alloy 400 LME corrosion? What is the best metallurgy solution for HCl overhead corrosion and LME by mercury corrosion on the same CDU unit?
13/02/2015	Q:	Any refinery experience with mercury contaminated crude oil processing from corrosion point of view?	(3)
13/02/2015	Q:	In the CO2 recovery section of Ammonia plants, using MDEA, are there any advantages to keeping the exchangers using cooling water on the tube side (e.g.Lean solution cooler, LP flash gas cooler) vertical, instead of horizontal?	(1)
13/02/2015	Q:	In the CO2 recovery process using MDEA solution , in ammonia plants, is it always the practice to mount the LP flash drum directly on top of the HP flash drum, instead of separate mounting?	(1)
10/02/2015	Q:	What is the effect of temperature on phenol removal from sour water (sour water from FCCU) in the crude oil desalter?	(1)
10/02/2015	Q:	Why is caustic added in the SWS column?	(4)
02/02/2015	Q:	During Crude distillation unit start up activities, water travels from crude storage tank to crude tower when furnace outlet temperature was 172C. It caused crude tower trays to dislodge. What if level of crude tower remains high then flash zone, does level of crude tower have significant effect on tray dislodge? Our system is furnace operated crude tower.	(2)
30/01/2015	Q:	From the corrosion point of view, would it help in improving the performance if vertical exchanger is provided in the crude overhead circuit? Comment on self-draining of the shock condensation, effect on deposit built up and water wash performance? Suggest preferable design of the heat exchanger?	(1)
28/01/2015	Q:	We are installing SS 310 skin thermocouple with heat shield in our DCU. The tube material is A335 P9. Our integrity department insist we perform buttering and PWHT for the installation. My questions: 1. Anybody have experience in such installation of skin TI where you have buttering and PWHT due to the dissimilar material weld? Does the TI's perform properly? 2. Is it a practice to have buttering and pwht for the installation? Buttering is due to dissimilar metal welding and PWHT is the requirement due to P9 material. 3. Our existing skin TI does not have buttering layer, and in our record, there is no PWHT done for the existing installation. Is it a practice? Any code or standards does it refers to?
23/01/2015	Q:	What is the effect of sending LPG (pressure about 9 kg/cm2G and temperature 50 degC) into a floating roof storage tank (atmospheric pressure design) contains heavy hydrocarbon component (C8+)? LPG flow will be only 4 ton/hour where the tank capacity is 60000 m3. If the heavy hydrocarbon quantity in the tank is high enough, will it eliminate LPG tendency to vaporize? Also the solubility of LPG in hydrocarbon, will it reduce or eliminate LPG vaporize?
21/01/2015	Q:	What are criteria for providing the bypass line in the control valve? In NG fuel line from 32 ksc to 5 ksc pressure drop at 70 deg C, can we provide the control valve bypass?	(2)
21/01/2015	Q:	We have a kettle type reboiler with weir plate and its liquid outlet is going regenerator in benfield process of co2 removal in ammonia plant. Is it necessary or required to put vortex breaker in the reboiler liquid outlet? Which design is applicable for designod reboiler?	(1)
18/01/2015	Q:	When water travels with crude, through furnaces into the crude tower, what process indications reflects on process parameters/tower profile?	(5)
14/01/2015	Q:	What should be the design pressure for wash water system in air cooled exchanger in atmospheric distillation unit? Is it mandatory to apply wash water in spray form? It will be helpful to if anyone provide reference about the spray nozzle for this application.	(4)
10/01/2015	Q:	Electrical Conductivity of the Turbine Fuel decreases with time , if it is 700 picosiemens at Merox outlet and after few days it declines to nearly 100 -200 picosiemens in the tanks, it is a normal phenomenon. We had found in certain cases the electrical conductivity has increased twice the observed value. Caustic, Surfactants were not found in the fuel. What are the reasons or factor , electrical conductivity of the fuel can increase ?	(2)
08/01/2015	Q:	Why is autoignition for lighter hydrocarbon higher than for heavier hydrocarbon?	(2)
07/01/2015	Q:	I have looked many databooks for some alkanes standard entropy of ideal gas at 298.15K, but the standard entropy values of the following components was difficult to find. I'd be very grateful if anyone can scan their databook pages for me. thanks ahead. 3methylhexane, 2,2dimethylpentane, 2,4dimethylpentane, 3,3dimethylpentane, 2,2,3-trimethylbutane	(2)
07/01/2015	Q:	What are box, skin and arc temperature? What is the sequence in magnitude of all these i.e. which one is higher than another in a furnace?	(1)
06/01/2015	Q:	Why is centrifugal pump discharge line smaller in diameter than suction line?	(2)
04/01/2015	Q:	What is refiners experience with reference to reformer packinox exchanger effective cleaning ? How can this exchanger be best cleaned?	(3)
01/01/2015	Q:	What will be the impact of crude blend on FCC product yield? if we are processing 95% hydrotreated VGO and 5% of non-hydrotreated VGO (i.e. Sour VGO). although the feed to the FCC is mainly hydrotreated, will crude blend affect the product yield?	(2)
30/12/2014	Q:	This question is related to kerosene merox unit. After processing kerosene in merox unit, what are the main reasons for poor saybolt color of kerosene product? If kerosene feed to the merox unit has saybolt color of +26, kerosene product from merox unit observes saybolt color of <16. Can someone explain the possible compounds which causes color problems to the kerosene product? If we go to Kerosene Hydrotreater, there will not be any issues of color problems and in fact it will be improved because of olefin and aromatic saturation. Please share any literature or chemistry related to the kerosene color problems in merox units.	(3)
25/12/2014	Q:	To increase the energy efficiency of Steam turbine, we take it in extraction mode from total condensing mode. When we tried to increase the extraction steam flow, the turbine exhaust temperature increased. Why does the turbine exhaust temperature increase at these conditions?	(2)
24/12/2014	Q:	We need to know about dewaxing catalyst or any other catalyst which can be used to reduce the wax obtained during pyrolysis process of plastic to fuel oil conversion. I need the guidance if any one can inform me.
23/12/2014	Q:	Is there any guidance that chemical vendors (or design folks) use around minimum differential pressure requirements for ensuring good dispersion of overhead filmer stream and neutralizer stream (via an injection quill) in the overheads of a crude unit for corrosion control?	(1)
23/12/2014	Q:	What is the effect of methanol (50%) water(50%) mixture on SA179 metal when the temperature is 230-250 deg celsius?
22/12/2014	Q:	I have a question about energy optimisation in Oil Refineries: how we could monitor the best technology in plant , included the HTR and HCR units , as we know that the mail suggested methods are related to Pre-heat train of crude?
22/12/2014	Q:	In our RFCC we have a purge treatment unit to remove the catalyst fines from the flue gas before leaving through the stack. The PTU utilizes about 25 m3/hr water for scrubbing and this water after clarification and oxidation leaves the unit as discharge. I would like to know about the possible destinations for the treated PTU water and availability of alternate methods which does not require water for scrubbing.	(1)
22/12/2014	Q:	What happens to the catalyst if water goes to naphtha or diesel hydrotreater reactor along with feed which is having Nickel molybdenum catalyst.	(2)
21/12/2014	Q:	We have an RFCC with a downstream purge treatment unit which consumes about 25 m3/hr of water in the scrubber. This water is clarified and aerated in towers before being discharged. Presently due to certain limitations we are required to reduce this quantity and route the effluent to BTP. What other alternates are available for treating/routing this water from purge treatment unit?
20/12/2014	Q:	Our problem is catalyst tapping blockage. 1- Tapping are for regenerated catalyst slide valve differential pressure ( high leg ) 2-Stand pipe is sloped (about 25 degree) 3- Tapping located below stand pipe and there is cold : It shows catalyst don't flow there (Top of stand pipe is hot ) 4-Purge air could not enter to tapping but amazing catalyst comes out from tapping. (It's like a check valve) Have you had similar experience like our problem ?
19/12/2014	Q:	What are the major modifications are required for processing Light kero in DHDS unit in place of Diesel ?	(4)
18/12/2014	Q:	I'm doing a work about octane rating, but I haven't find the Research Octane Numbers of cis-1,2-dimethylcyclopentane and trans-1,2-dimethylcyclopentane. Who can tell me?	(3)
11/12/2014	Q:	In order to decrease storage costs and to get rid of some imposed restrictions for intermediate products as feed for downstream units, is it possible to connect output of upstream unit (e.g. distillation unit) to downstream unit (e.g. Hydrocracker) directly? Because of sequential changes in crude feed characteristics, we have encountered some surge and instability in straight run products of distillation unit.	(2)
30/11/2014	Q:	What's the best way to clean out the main column after reactor catalyst lost?	(1)
21/11/2014	Q:	What are the Pros and cons of Steam stripping and Reboiler? When designing a column, what are the factors that decide to go with each of this?	(2)
21/11/2014	Q:	We have different fired heaters with fuel oil and gas burners in our refinery. It is seen that the metal tube surface is coated with fine layer of powder (slight yellow colour) externally. This is loosely held to its surface (as seen through inspection door) and reduces the heat transfer leading to high skin, arch and stack temperature. My suspicion on the Fuel oil quality became stronger. So I found that Clarified oil from FCC is not going to the Fuel oil tank. Upon testing the IFO for ash content, it came out to be 0.075%. Is this okay? Any other testing is required? What probably might be the reason for this powder coating and measures to solve the problem?	(2)
19/11/2014	Q:	What are the Pros & Cons in case of Hot start-up of Hydrogen generation unit? Why it is generally not preferred and also why is there no detailed procedure given in operating manual ?	(1)
19/11/2014	Q:	I am working in Hydrogen generation unit. Our naphtha vaporiser in HDS section got fouled frequently. What shall be the reason behind choking of naphtha vaporiser?	(1)
19/11/2014	Q:	Is it possible to have caustic stress corrosion cracking in the bottoms heat exchanger in a CDU? We are injecting caustic downstream of the desalter at 5 deg Be to ensure 20 ppm max chlorides in the overhead sour water. Can excess caustic, if there is any, be present in the reduced crude as caustic and cause CSCC? Bottoms is on the shell side of the heat exchanger.	(1)
14/11/2014	Q:	My question is if we will do evacuation test for DHT reactors -20 PSIG How do I know how much offset of Positive?
13/11/2014	Q:	Please could someone explain the difference between the following: 1. Internal reflux 2. Circulating reflux 3. Pumparound	(2)
12/11/2014	Q:	How to calculate N2 requirement (available at 7barg) to pump horizontal closed drain vessel liquid (located below ground with dimension ID 6000mm x S/S 6800mm) to atmospheric flare KOD at a elevation of 7.5 meter.	(1)
11/11/2014	Q:	On what criteria the selection of brass tube bundle is made over Carbon steel? In a corrosive environment can Brass tube bundle be used in place of SS tube bundle?
11/11/2014	Q:	What is typical specific natural gas consumption [(NG Feed+ NG Fuel)/Hydrogen; wt basis] for hydrogen generation unit?	(1)
08/11/2014	Q:	I am working in an HGU unit. I want to know if olefins or unsaturated compound increases, what will happen in prereformer catalyst.	(2)
07/11/2014	Q:	I'm going to implement APC in a FCCU soon. What's the best source of information to learn the complete (even the minute) details of FCCU so as to complete it successfully?	(1)
01/11/2014	Q:	We would like to reduce the net minimum flow of our Visbreaker unit in order to increase our flexibility. Our concern is that this will lead to shorter runs due to coking in the furnace. Do you have experience regarding the various available options: recycling VSB gasoil or VSB residue? Co-processing LCO or slurry from FCC? Increase the injected BFW/steam to the VSB furnace passes? What would you advise?	(3)
01/11/2014	Q:	in our naphtha hydrotreater with TK527(TOPSOE) CATALYST we have to treat a naphtha with 200 ppm oxygenate (MTBE), but we don't know is it harmful for catalyst or not?? operating condition: feed=240 m3/hr reactor inlet temp.=315 deg c system press.=30 barg (this unit is upstream of CCR UNIT)	(2)
29/10/2014	Q:	Our FCCU (Stone & Webster) shows high BS&W in CLO stream, even though charge rate is low at around 150 tonns/hr. Design capacity is 215 tonnes/hr without any bottom (CLO) recycle to the feed. Now lab result of BS&W shows in the range 0.4 to 0.7 . Our intension is it keep it always below 0.4 . What are the remedies to tackle this problem without shutdown?	(1)
25/10/2014	Q:	For boiler feed water production we use lake water. I am interested to which lab methods are available for determination of humic and fulvic acid in water. Which filters are the best for their removal?
24/10/2014	Q:	What is Nelson Complexity Index factor for ATF,Gasoline and LPG Merox , Sulphur Recovery Unit process ?	(1)
24/10/2014	Q:	What is Nelson Complexity Index factor for ATF, Gasoline and LPG Merox , Sulphur Recovery Unit process ?
22/10/2014	Q:	Any industrial experience with TEMA "F-type" shells with condensing service on shell side? What are the disadvantages? For a service with wide boiling/condensing range and temperature cross, can it be used?	(4)
22/10/2014	Q:	Please anyone who can help with information on the use of n-hexane , thinners otrso isoparC and peroxides in the polymerization reaction of LDPE high pressure ( 20,000 psig ) autoclave reactor type	(1)
20/10/2014	Q:	We are operating Born Canada Vertical furnace in our refinery for crude oil distillation. It is being observed that some tubes comes closer to each other. And some are swinging like pendulum although we are operating at 80% of design flow rate. Can you share reason of this behaviour.	(1)
20/10/2014	Q:	What quantity of steam is required in distillation column and side strippers per barrel of crude/products.	(3)
18/10/2014	Q:	We are operating our NHT unit at 125% of its capacity. To maintain NHT reactor RIT, its heater firing is very high. As per our observation firing is very high due to heaters absorption heat duty is 55% only. we want to modify our furnace to increase its absorption heat duty, kindly suggest us what modification is required to increase the existing heaters efficiency?	(5)
15/10/2014	Q:	Can you please advise some literature sources or design guidelines for Naphtha Stabiliser design.	(1)
14/10/2014	Q:	Fuel gas knockout drum is sized for minimum surge time of 2 minutes between 19.5 barg to 16.5 barg for compressor change over. I would like to calculate the surge volume. How?	(1)
14/10/2014	Q:	I am working in Hydrogen generation unit. In hydrogen export line one Low point drain flange caught fire due to minor leakage of hydrogen but no source of ignition was there. We could not find reason why auto ignition happens without source. If anybody know give some reason.	(5)
09/10/2014	Q:	We have two level transmitters for FCC reactor. Since last few months back we are facing malfunction of one of the level transmitter. We use to flush/ blast the High pressure tapping of that level transmitter for few minutes. The transmitter works well again for few days after flushing. We observed that there is no any effect to the other transmitter. The Low pressure tapping of both transmitters are at same elevation and High pressure tapping are at different. What could be the possible reason for this case? Or it was only due to bubbling bed fluidization issue or due to damaged/ plugged air grid.	(1)
09/10/2014	Q:	We are facing problem with debutanizer reboiler operation due to fouling and we didn't get enough reboiling and bottom temperature. It forces us to reduce the plantload and reduce debutanizer feed. Can increase in debutanizer feed temperature help us to process more feed? And if we increase the stripper bottom temperature, what are other precautions to be considered? Like increase in stripper pressure with respect to temperature for fuel gas specification.	(3)
03/10/2014	Q:	In our DHDS unit we recently we noticed product colour changed after the reactors. After some days product colour reverted to normal. Can anybody please explain this colour changing mechanism?	(5)
25/09/2014	Q:	Can we process FCC's Clarified oil (CLO) or Decant oil as feed to Hydro cracker? My question is that Unconverted oil from Hydro cracker is usually good feed to FCC, So I would like to know if we process FCC CLO in hydrocracker then how much of it will it to convert to Unconverted oil in Hydrocracker? We will use filters to reduce catalyst content in CLO so that hydro treater won't get affected.	(2)
24/09/2014	Q:	I am working in Diesel Hydro Desulfurization unit where diesel is produced in sulfur less than 200 ppm. after the reactor the effluent contains , Hydrogen gas . sour water an diesel. diesel is further sent to stripper where light unstabalized naphtha is separated and diesel is sent to water removal. Operating conditions of stripper are 245 C inlet , 156 C overhead & 240 bottom temperature. Operating pressure is 8.1 kg/cm2. MS steam is used with pressure 11 kg/cm2 and temperature 195 C.In the downstream of stripper diesel heat exchanges in exchanger , Fin fan coolers , trim cooler and finally go to Diesel Coalescer for moisture removal at temperature 56 C. We are facing frequent chocking of coalescing cartridges with rust particles. i need to pin point the possible location where corrosion can occur and why in order to avoid frequent chocking of cartridges with black rust particles.	(3)
22/09/2014	Q:	What is valve TRIM?	(1)
18/09/2014	Q:	At our unit we have observed polymer on the tubes of reboiler, the reboiler being stab in, requires shutdown and tube bundle removal and cleaning. Looking for any online chemical injection continuous that could avoid the scaling or polymer formation.	(6)
15/09/2014	Q:	What are the best operational practice to res-use the catalyst fines collected from Third Stage Separator (TSS) installed in the down stream of regenerator?. Whether these catalyst fines can also be utilized to improve the other thermal cracking process ?	(1)
07/09/2014	Q:	We are having reflux drum for primary absorber. the entrained net overhead liquid is collected in the reflux drum. the liquid of reflux drum is pumped out internittently to high pressure seperator. I want to know that can we line up this hydrocarbon back to main fractionator or to deutanizer feed line? If we line up it to main fractionator then it wont accumulate in primary absorber reflux drum and build up the level in reflux drum.	(2)
05/09/2014	Q:	In a hydrotreater I have normally seen shutdown valve provided on HC line exiting the HP separator. The shutdown valve will close upon sensing low level in the HP separator. Shutdown valve is provided between HP to LP interface. Level indication failure of HP separator will lead to gas break through from separator to stripper and stripper is not designed for such high pressure conditions. But in a kerosene hydrotreater unit I have seen the shutdown valve tripping logic on high-high pressure in HC line exiting the HP separator instead of low level in HP separator ( this low level tripping is not present ). The tapping for pressure ( 2 out of 3 tripping logic ) is taken from downstream of angle valve (pressure reducing valve ). What can be the reason of changing the shutdown valve closing logic from low-low level in HP separator to high -high pressure in the HC line exiting the HP separator?	(3)
03/09/2014	Q:	We found a high TAN, ca. 0,4 mgKOH/g (usually 0,1), on a LCO cut. What could be the explanation?	(3)
30/08/2014	Q:	Dead legs/purging point, vent point of the pipelines, pressure vessels, heat exchangers are generally consist of a valve and threaded cap at the end. During turnaround is it mandatory to check the thread of the nipple whether it is thinned or thread damaged especially when it is found the thickness of the pipe is satisfactory.	(2)
25/08/2014	Q:	What would be the good choice as an absorbent in Sponge absorber? Either Light cycle oil or heavy cracked naphtha (Lean Oil) from main fractionator.	(1)
21/08/2014	Q:	In a team discussion about the start up sequence of Naphtha Catalytic Reformer, everyone was wondering about the effect of prolonging the hot hydrogen circulation across the catalyst bed more than 12 hours. The question rose from the fact that usually the Stabilizer (Debutanizer) Tower in the Reformer Unit is started parallel with reactor heating up, in such a way that when Reactor has reached the required temperature for charge in the liquid feed, the Stabilizer Tower has been ready to strip out the light ends. But it's not seldom that Stabilizer Tower is suffering from un-predicted prolonged problem --- such as very frequent bottom pumps' strainer blockage-- while reactor inlet temperature has reached the feed cut in temperature. Under such situation, the start up team was in the pro-cons whether to keep the hot hydrogen circulating across the reactor for few more hours till the readiness of Stabilizer Tower, or to immediately cool down the reactor loop. The first opinion merely consider about the time efficiency, while the second group worried that alumina support of the catalyst will undergo a phase change due to hydrogen embrittlement on this alumina. Has anyone here had the similar experience, and can give us more enlightenment on this matter?	(1)
21/08/2014	Q:	If top pressure is maintained on lower side, what is the effect on top temperature, side draw - off temperatures, pressure profile in the column and on the quantity and quality of overhead product?	(2)
20/08/2014	Q:	I am working at UOP Cyclemax CCR Platforming Unit having R-134 Catalyst. We are facing problem of high HCL in recycle gas. Can Anybody who has worked on same CCR Unit with R-134 Catalyst, share his experience? Additional: Thanks for responding. 1- Our stripper operation is OK regarding reflux ratio & bottom temperature, but the question is if Organic Chlorides are slipping from stripper, then Chloride level on spent catalyst in Platformer Reactors should also increase with high HCL in recycle gas that is not in our case. 2- We are trying to maintain Chloride level b/w 1.1~1.3 wt% by injecting PCE (perchloroethylene) more than design in oxychlorination zone but result always remained b/w 1.1~1.20 wt% on regenerated catalyst & 0.90~1.0 wt% on spent catalyst. Surface area value of Catalyst about 6 months ago was 152 m2/gm while we have changed our whole catalyst in last Turn Around in March,2012 & total 215 regeneration cycles have passed. 3- We have already changed reduction zone vent from upstream of product separator to upstream of Net Gas Compressor. Waiting for your valuable next response.	(4)
19/08/2014	Q:	I'm currently working on a VGO hydrocracker simulation. I want to know some common problems in normal industrial operation in this kind of process.	(1)
19/08/2014	Q:	Retained sample of our Naphtha product found to be decoloured after a couple of months. Naphtha product was w a mix of Straight run and cracked and hydrotreated naphtha. Is there any particular reason for colour degradation of Naphtha on storing?	(1)
18/08/2014	Q:	In an Reformer Stabilizer Debutanizer Column, we do regular water washing of the column to get rid of the ammonium salts. We do this procedure by reducing the throughput and pressure of the column and produce off-spec reformate during the process. We do like to ask if any refiners have a practice of introducing steam into the column while the unit is online to clean the ammonium slats deposits in the column and condenser? If yes, what are the concerns and precautions to be observed? Additional: I would like to confirm that what you had mentioned. HIGH PH contributing to the severe corrosion. We have a similiar system upstream(the first column for the FRN Feed) and found severe corrosion in the overhead system of the distillation column and we found that the pH was very low and ammonium salts, in the range of 4.5. Hence,we are injecting a highly basic chemical to increase the pH and are currently maintaining 9 pH. But to our confusion , we are still finding a very high amount of corrosion. If what you mentioned is true, what we did in the system is not going to help us but rather worsen the condition? Thanks Stephan, Could you please elucidate on the corrosion due to high pH? We have a Debutanizer Column , the first column in the Aromatics Complex which is severely corroded in the overhead due to ammonium salts. The feed is from the refinery , Full Range Naphtha. We had initially of an pH of less than 4. Then we injected an chemical to boost the pH and are currently mainly in the range of 9 pH. But the corrosion is still not under control. Could the high pH be one of the concerns to look at?	(2)
16/08/2014	Q:	In our hydrotreater units SWS reboiler we are having SS 316L tubes while shell is of carbon steel. Reboiler is kettle type, tube side is MP steam(Pr-10 bar and Temp-220 degC) and condensate(Temp-170 degC). During our shutdown we have opened reboiler and found 60-70 percent tube thickness loss from OD side(By ECT method) that is part of tubes which is in contact with shell side fluid and thinning is only on upper portion of tubes i.e. portion where steam is present while bottom tube portion where condensate is in tubes is not having thinning. We want to know following- 1) Reasons for such heavy metal loss/tube thinning from OD side and only on upper portion of tubes 2) Path forward to avoid such heavy loss of metal /tube thinning 3) Any up-gradation required in tube bundle metallurgy of Reboiler.	(1)
13/08/2014	Q:	What is the welding procedure of T-joints in 8 mm bottom plate of tank? Can T-joints be welded before completing short and long joints?
13/08/2014	Q:	Recently we have suffered some problems of Cupper Corrosion test failure in LPG. The LPG came from a caustic treatment for mercaptan sulphur removal. After caustic treatment, the LPG pass through a decanter (with NaOH/MEA solution) and sand filter, which are supposed to remove any caustic carryover from LPG. We do not see any caustic collected in the sand filter, however we have detected Na and nitrogen in LPG, so we suspect that it is not working properly. The sand filter seems not only not working, but also accumulating some contaminants: we have seen sometimes that LPG pass the cupper corrosion test in the inlet, but not in the outlet of the sand filter. We are evaluating the possibility of substituting the sand by any other more effective adsorbent for caustic / nitrogen (amines). The possibilities are: activated carbon, Anthracite or alumina. Has anyone experience with adsorbents for contaminant (caustic, amine, etc..) removal in LPG? Any idea / recommendation regarding the operation of the sand filter?	(2)
31/07/2014	Q:	What is the limit of Oxygen content in Naphtha feed for Hydrotreater to avoid gum formation? What is the ASTM method to test Oxygen in Lab?	(1)
31/07/2014	Q:	Isomerization plant Molex unit has been commissioned.How to asses the Adsorption capability of Adsorbent. Similarly how do we know that Rotary valve parameters are fine tuned ? Separation efficiency would be affected if any of the two above mentioned factors are not optimized.
24/07/2014	Q:	I am working in Hydrogen generation unit. I want to know whether if naphtha preheater tubes got a leak and super heated HP steam went to naphtha side then would superheated HP steam go to hydrogenerator (Co-Mo catalyst)? What is the effect of steam on Co-Mo catalyst life?	(4)
19/07/2014	Q:	Molecular Sieve of the Liquid feed Drier of Isomerization Plant was removed for inspection and it was observed that Molecular sieve is blackish in colour. Is is possible to ascertain the remaining life of Molecular sieve ? How do we know that pores are not choked or damaged?	(2)
17/07/2014	Q:	Is there a way we can assess VGO Hydrotreater is running at Aromatic saturation equilibrium or still scope to increase Aromatic saturation by increasing catalyst volume? We are looking for revamp options of existing unit. Since operating pressure cant be changed to increase aromatic saturation, the only option is to add catalyst by introducing new reactor bed. The question and what I need to prove is that increasing catalyst volume improves the Aromatic saturation. This can be done by proving the current unit is not running at Equilibrium controlled all the times. During EOR conditions, it may reach equilibrium controlled because of high WABT. I need some literature on this. Can anyone share your thoughts?	(5)
17/07/2014	Q:	Need all your expert views on crude oil Basic N2 impact on fouling tendency. This is limiting on crude flex/ optimization as the refinery has CAM limit for basic N2 (150ppm). Need to understand the fouling tendency of Low N2 crude whether this is credible or perceived. Also understand the fouling tendency/reversibility. If credible, please provide if there are ways to mitigate (eg: every low N2 crude processing is followed by crude that can act as cleaning and recover any loss in duty?) Low basic N2 could be good for LRCCU feed and also hope for HCU where as this limit could restrict such crudes from buying/processing… We always used to be on the basis of waxy vs. asphaltic… every waxy run followed by a aromatic/naphthenic crude run to provide cleaning effect. Antifouling was other alternate only in LR circuit and /or SR circuit. Blending of crude based on compatibility to mitigate was another option… There should get some clear guidelines for mitigation if the impact N2 is credible and proven… can you provide any such details and what is minimum technical solution for such mitigations as this will be a clear big lever for crude flexibility.	(1)
11/07/2014	Q:	In our Hydrogen Generation Unit HP steam silica level is running high at about 0.1 PPM against design value of 0.045 PPM. We maintain BFW Ph-9.5, excess Phosphate - 3 PPM, Hydrazine excess 0.1 PPM and continuous blow down Gestra valve is 100% open. Conductivity and TDS is normal. How can we reduce silica? There are no BFW exchanger leakages	(2)
03/07/2014	Q:	Does anybody use MDEA on Amine treating on FCC? We proceed hydrotreating feed on FCC, and we use DEA on Amine treating. We want to switch DEA with MDEA. What should I pay attention to during this switching?	(2)
27/06/2014	Q:	Obj: Increasing recovery of H2 by slightly compromising on H2 purity (from 99.99 to 99.90) Present status: In one of our refineries, the recovery of H2 through pressure swing absorption is around 89.5%. Purity obtained in 99.99% whereas 99.90% is sufficient.	(3)
25/06/2014	Q:	Concern: Trade off between purity and recovery of H2 from PSA Obj: Increasing recovery of H2 on slightly compromise on purity (99.99 to 99.90) Present Status: In our one of Refineries, the recovery of H2 through PSA is around 89.5%. Purity obtained in 99.99% whereas 99.90% is sufficient. Any changes to the operation still gives 99.99% purity thereby reducing the recovery to almost 89-89.5%	(1)
24/06/2014	Q:	How to calculate amine requirement to absorb H2S in hydro treatment unit by just knowing the feed sulfur content?
24/06/2014	Q:	I am working in Heavy cooker gas hydro treating unit.In plant,RGC primary seal drain is connected to CBD.There are chance that by mistake or passing of isolation valves, CBD gets pressurized with 100 kscg gas.Kindly tell me the reason why high pressure drain is connected to CBD?Is not it possible to use pressure reducing valve as safety measure in that line.
23/06/2014	Q:	Has anybody got idea about which metallurgy to select in wash drum outlet line to nitrogen dryer package in CCR. Currently we are having SS 316L metallurgy but because of chloride carryover we are continuously facing problems of localized pitting. Hence we need to upgrade metallurgy such that it should be effective and at low cost.
18/06/2014	Q:	Do anybody have experience in treating Brine from desalters through Tricanters to separate Oil and sludge from Brine?	(2)
15/06/2014	Q:	We use a hot oil system. We are facing frequent failure of gaskets in it. The operating temperature is 330 dec C and pressure around 15 bar. we are currently using metallic spiral wound gasket. These leaks are resulting into unit shutdown or online sealing. 1. Do others have the same issue of gasket leaks in hot oil system? 2. What kind of gasket will resolve above issue? 3. Any special make of gasket? 4. Might changes in operating condition help?	(2)
01/06/2014	Q:	Sour Water stripping = Shell side of feed bottom exchangers containing stripped water is chocking with salts. What could be the reasons?	(3)
31/05/2014	Q:	We are facing rapid chocking problem of our feed bottom exchangers of sour water feed/stripped water. In last maintenance, tube side of these exchagers (Sour Water) there were found amonium salts deposited in form of lumps, that ultimately traveld through tower and back in the shell of these exchangers. These have cuased serious flow restrictions at stripped water pump due to insufficent suction. To examine this phenomena suction straniner of feed pump were opened but found almost clean. That shows nothing is coming from the feed tank. Please guide upon possible cause of this salt built up in shell and tube type feed bottom exhangers.	(4)
27/05/2014	Q:	How could I simulate a Boiling Feed Water dearator on PRO II. flash drum? distillation column?
18/05/2014	Q:	In our vacuum column the column top pressure 75 mmHga and the flash zone pressure is showing 50 mmHga. The gauge near the ejector system is showing 40 mmHga. The PD of flash zone and the ejector system matches with the design value. We have tried changing the gauge and the transmitter on overhead vapor also. The impulse line to the transmitter is clear. what can be the reasons for this erratic reading in the vapor line.	(3)
14/05/2014	Q:	I have question about S content in heavy i light FCC naphtha. We have Texaco FCC unit and processed hydrotreating feed, in RF riser we processed heavy fcc naphtha. We tried to processed little amount of VBB, but we had problem with the S. In VBB we have 30% RSH and 0,8% H2S, other 70% we do not know which sort of S is. Our laboratory can not define which sort of S we have. With processing VBB we normaly rise S content in heavy and light FCC naphtha. Does anybody have advice how to reduce S content in FCC naphtha if we processed some amount of VBB?	(1)
13/05/2014	Q:	Our sour water stripped is fed with Sour water from our hydrocracker unit with respectively 40 000 ppmw and 35 000 ppmw of NH3 and H2S content and a pH of 9. Typical Residual NH3 and H2S in stripped water are respectively in a range of 50 ppmw and 0.5 ppmw. We recently observed that residual NH3 content in stripped water incresaed up to 2000 ppmw while residual H2S remained at low normal value. No change noticed on operating conditions. We also noticed an increase of ammonia content in waste water from vaccum fractionnator overhead vacuum system in the same range (2000 ppmw). We tried to incresase live steam to feed ratio with no subsequent result. What could be possible cause and what could we do to solve this problem?	(3)
06/05/2014	Q:	I would like your comments on use of Coriolis meter vs Positive Displacement meter from accuracy, proving, maintenance, operation point of view for custody transfer of petroleum products to be loaded in tank trucks
02/05/2014	Q:	What are the pros and cons of adding Caustic at the upstream of Desalter?	(2)
29/04/2014	Q:	I'm working on Kerosene hydrotreating unit simulation to remove sulphur from kerosene by using hydrogen. What are the possible components when it mixed?	(2)
29/04/2014	Q:	We are processing a heavy crude of API 18. Salt content of the crude is 80-100ptb. BS&W is 0.8 to 1.2%. We are using stripped sour water as wash water, made up by BFW. pH of wash water is between 7-7.5. We are maintaining a desalter temperature of 150 deg C. We are having two desalters in series, which is supposed to bring down the salt by 99%. but we reached up to 90% earlier. Last two months we are having a high emulsion band. The BS&W of desalted crude is 2-3 and the oil in brine is 1-2% even at minimum delta P (0.3kg/cm2). Water injection rate is 3% to individual desalters (circulation not done as oil carryover with brine observed. The voltage across the grid is as low as 6-10 KV (Tapping at 22KV). We have changed the secondary tapping to 18V and the deslater is showing an improvement in Voltage (10-12 KV) 1.what can be the reasons for this upset? 2. Can you explain the effect of change in secondary voltage? Additional info: We are not adding any scavenger to the crude. Stripped water pH is 6-6.5 and brine water pH is in 7.5 range. What parameters of crude oil should I check?	(4)
28/04/2014	Q:	Who has a reliable cutting water backwash filter for water that has fines and oil residues?	(2)
26/04/2014	Q:	In the Design of a DHDT unit, what are the criterion for selection of a HHPS (Hot High Press. Separator), along with a CHPS (Cold High Press. Separator) or with CHPS only unit? Also, in some configurations of DHDT, we can see a HHPS + CHPS + CLPS (Cold Low Press. Separator / i.e. Flash Drum) What are the criterion for such selection ? Also what are the advantages and disadvantages of the 3 options?	(4)
26/04/2014	Q:	In mild hydro cracker, we have amine absorber column to reduce/remove H2S from Recycle gas. Due to amine foaming, amine is carry over to recycle gas compressor. Any one can share their experience to reduce foaming of amine or how to do Oil skimming in amine columns and what are the parameters to be monitored while doing this activity. How can we know Oil skimming is completed and there is no foaming in the column?	(4)
21/04/2014	Q:	Mild hydro cracker unit fractionator furnace pass flow Flow transmitter impulse tubes are cracked due to Header vibrations. We faced this kind of problem in case of unit is upset due to recycle gas compressor failure. what are the possible chances to get multiple phases in this header. Back ground: Product stripper outlet ....>G-0006...> Exchanger E0004 (Shell side - Pump out let liquid, tube side Reactor effluent) ......> Exchanger E0025 (Shell side- E0004 O/L, Tube side fractionator O/L) This incident was happened after start up of pump G-0006. Any one experienced this kind of problem?
21/04/2014	Q:	What are the uses of shell and tube exchange in Bapco? What are the differences in application between the co-current and counter current in Bapco? and how is it used in oil refineries? Any figures for them? Locations?
19/04/2014	Q:	We have an Axens CCR unit with 4 reactors and I would like to know whether we can maintain different temperature in each reactor? If the answer YES, what are the effect on RON and catalyst? Please share your experience.	(2)
15/04/2014	Q:	In our CCRU plant we have two net gas compressors which are discharging 38000 Nm3/ hr H2 gas (95 % H2 purity). Net gas compressors are two stage reciprocating compressors with recontacting section. We have 4500 Nm3/hr (87% H2 purity) of semi regenerative CRU off gas joining the circuit after the first stage discharge. We are facing problems with very high second stage suction strainer PDIs in our compressors (which is probably due to CRU off gas joining the circuit interstage). Recently we had conducted analysis of the muck we found on second stage suction valve plates. The analysis is : Sr.NO / Parameter / Unit 1 Moisture (@105ºC) % 5.4 2 Loss of Ignition at 800⁰C % 83.14 3 Ash at 800⁰C % 11.46 4 Solubility in water % 13 5 Oil Content % 16.96 6 Iron (Fe) as Fe2O3 % 8.716 7 Acid Insoluble ( ~ Silica etc) % 0.8 Can anyone provide further insights looking at these results?	(1)
13/04/2014	Q:	We have a Steam methane reformer having side fired self respiratory burners. To attain the correct O2 in flue gas of primary reformer, burner dampers are being adjusted. What is the correct sequence for throttling the burners? Should the bottom most burners should be throttled more than the top ones or vice versa?
11/04/2014	Q:	In case of side fired self respiratory burners in reformers what is the correct sequence of adjusting the air? From bottom row burners to top row burners in increasing trends: in 1st row 40%, 2nd row 40%, 3rd row 40%, 4th row 30%, 5th row 30% & 6th row 30% OR in 1st row 30%, 2nd row 30%, 3rd row 30%, 4th row 40%, 5th row 40% & 6th row 40%. This flue gas is going to convection section for heat recovery.
08/04/2014	Q:	We are processing HHCGO in our FCCU. My question is that whether we have to process it as combined feed in feed surge drum or we have to process it by injection through individual feed nozzle a higher elevation. Which is the best option and why? And what is the impact on yield pattern?	(4)
04/04/2014	Q:	We are processing local crude in which sulphur content is very less....Light naphtha is being separated from pre-flash tower...for corrosion control we are using filming amine...the iron content in boot water of naphtha reflux drum is within range...but chlorides are reporting more that 50 ppm... we are also using wash water that is recycling from booth water to the inlet of overhead condensers....what should be the maximum allowable range of chloride content in naphtha reflux drum?	(4)
04/04/2014	Q:	For a given feed quality and constant Reactor temperature, Which of the following gives Optimum yields. a) Higher feed preheat & Low Cat/oil ratio or b) Higher Cat to oil ratio & low feed preheat?	(5)
29/03/2014	Q:	We are having Feed Surge Drum in Diesel Hydrotreating Unit, for maintaining pressure of FSD we provided Blanketing Hydrogen and relief to LP Flare. Fail safe positions for the Control Valves in Hydrogen is Fail Open, LP Flare is Fail Close (Where as it was reverse in previous company where I worked last). If in case of Air failure Hydrogen to FSD CV gets open and may get pressurise as there will be no any relief What may be the basis of selecting the fail safe position of both CVs?	(6)
29/03/2014	Q:	What is the difference between the Antifoulants that are used in Refinery Preheat Train to avoid fouling and CDU Heater to avoid coking in the coils?
27/03/2014	Q:	In the CDU Desalter can we use one demulsifier for different Crudes. Is it possible to test effectiveness of the Demulsifier in Laboratory?	(1)
25/03/2014	Q:	What should be the quality of Desalter wash water make-up? Please clarify in terms of Hardness, PH , H2S,Alkalinity and Chloride content. Deaerated water is not available only limited quantity of Boot water from accumulator is available.	(1)
25/03/2014	Q:	We are frequently observing chocking of crude column overhead boot water pump strainer. There is no sign of of high iron or solid contaminants in boot water and other parameters (like pH, chloride, fe ) are within limit. Please suggest if any one has faced such type of issue.	(1)
22/03/2014	Q:	We want to drain CDU Desalter Effluent Brine to Oily Sewer. Any issues of H2S or smell?	(3)
21/03/2014	Q:	Refinery Practice is to add Demusifier at the upstream of Desalter. But some Refineries also inject Demusifier at the Suction of Crude Charge Pump. Which is better?	(1)
20/03/2014	Q:	We face the problem of Diesel salt dryer drain line blockage. Anyone faced this issue? What solution did you apply?
10/03/2014	Q:	In Unipol fluidized bed gas phase polymerization process of polypropylene (PP) impact co-polymer (ICP) production, PP resin is transferred from reactor-1 to reactor-2 via IRTS (Inter resin transfer system). Due to fouling in IRTS (transfer tank and transfer tank filter) and some times due to actuation of faulty level switch (high level), ICP production has to be stopped. What may be probable reasons of IRTS frequent fouling? The level switch is of neucleonic type. What may be the reasons of actuation of faulty level switch? How to improve operational reliability of Impact co-polymer production?
04/03/2014	Q:	What quantity of iron scales is likely to be generated normally from internal cleaning of Naphtha tank of 10 TMT capacity (18.5 m height) when taken for maintenance after nearly 10 years of continuous service in a Petroleum Refinery?
04/03/2014	Q:	How do we calculate viscosity values of Bitumen at 90°C and 100°C for VG-30 grade (pen 50-70mm, min. viscosity of 2400 poise at 60°C & 350 cst at 135°C)?These values are required to advise a consultant who is engaged to select & supply suitable rotary screw pump.
28/02/2014	Q:	Please share refiners experience of Crude Oil Floating Roof Tanks Roof seal & Secondary seals of synthetic rubber material design life & replacement frequency. At our Refinery Complex there is no leak detection system installed.
26/02/2014	Q:	Can any one explain me for online and onsite repairing and maintenance of electromechanical devices installed at 240 MW CPP of refinery sector.
21/02/2014	Q:	In the crude distillation unit, we face problem with Gas Oil colour. Any one have any idea to solve this problem or any one have seen like this in any refinery?!	(8)
19/02/2014	Q:	After around 5 years services, material Hastelloy C276 (sch 10S) is cracked near the weld (HAZ). The service is HCL. Actually is line is used to upload 32-36% HCl on the tank. (Temp ~ 35C). Can you please tell what is cause for that leak?
18/02/2014	Q:	We have a kettle type ammonia vaporiser. Shell side is ammonia and tube side is steam to vaporise the ammonia. We have observed that tube side (steam side ) remains filled with condensate almost 80% due to its low load operation against the design. Is this operation is correct to run the vaporiser with filled tube condensate?	(5)
18/02/2014	Q:	What parameters govern the Premium on Naphtha other than Demand & Supply parameters Does RVP of Naphtha effects the market premium. If yes, how?
05/02/2014	Q:	Is there any SO2 production due to decomposition of Sulfolane use as a solvent for aromatics extraction?	(2)
05/02/2014	Q:	In our vacuum distillation column three valve trays are replaced from glistch packing in order to obtain more deeper cut of SAE-40 and wash recycle is provided to wash the packing but whenever unit is down due to any failure the wash recycle line gets plugged. We are using SAE-20/SAE-10 as a wash recycle oil. Can we use HVGO for that purpose or any other solution for that problem?	(3)
04/02/2014	Q:	We are trying to figure out how to improve the feed control to our new Hydrocracking and Hydrotreater Units, since one of the feeds comes from the Coker Unit, we want to know how variable are the quality and flow of the HCGO, Naphtha and LCGO, because we are aware it would be changing while coker cycles are taking place. We don't have tanks to store LCGO and Naphtha as feed to the units, so these streams go to the hydrocracker and hydrotreater directly from the coker stripper, and if there is a sudden change in composition or flow, it could lead on a runaway.	(3)
31/01/2014	Q:	Currently I am working in upgrading onshore crude facility plant we have a sour crude stripper column for H2s removal after desalted/dehydrator while existing plant having H2S stripping column first then crude is going to desalted/dehydrator. Is there any reason why? And is there any effect in desalted/dehydrator operation due to H2s presence in crude?	(1)
29/01/2014	Q:	We are having 3 nos. of identical SRU trains (2 nos. of Claus & 2 nos. of CBA reactors) with each having a capacity of 65T/day of Sulphur production. We are frequently facing a problem of second condenser tubes leaks problem and plugging of rundowns due to catalyst dust carry over. Operating temperatures are being maintained above dew point in all three trains. However, tubes leaks problems are coming in only one train very frequently. Can anyone suggest the cause for frequent failure of condenser tubes leaks? C2 outlet temperature is being maintained >150 degC against the design of 168 degC. 1st claus reactor (R1) outlet temperature was being maintained >340 degC. C2 outlet temperatures observed >150 degC even for R1 o/l temperature of 310-320 degC. In spite of maintaining C2 o/l temperature >150 degC, sudden decrease in C2 o/l temperature and increase in system back pressure is being observed due to tubes leaks.	(3)
25/01/2014	Q:	We are facing problem of low heat duty of the debutanizer reboiler. Tube side heating media is saturated high pressure steam. Our steam flow was decreased gradually. We opened steam flow supply valve more to increase the heat duty, but still we did not succeed. We use saturated high pressure steam as heating medium and operating temperature is 482 Deg F (250 C). We as of now ruled out the reason of polymerization because of the low heating medium temperature, but question is that higher shell side tube wall temperature due to low pressure drop and it may lead into polymerization. Can it happen? One more point is that, we have one online sealing clamp at steam inlet line and we injected sealing material three times to arrest leak. I thought that this sealing material might have blocked the control valve upstream cadge/ filter and reduce the steam flow. We had reduced the condensate pot pressure and we observed that the steam flow was increased. What can be the reason for low reboiler heat duty? Is it because of polymerization or chocking of the steam control valve? How can we conclude this problem?	(8)
23/01/2014	Q:	Does overhead water wash play any role to achieve dew point early?	(2)
22/01/2014	Q:	At present we are operating a diesel column bottom pump (saturated liquid at around 300 deg C). Pump runs for 24-30 hours and suddenly discharge pressure drops beyond permissible value and pump needs to be stopped. All other operating parameters are well with in the range. We donot understand the phenomena why discharge pressure needs to be dropped suddenly when all other parameters are same. One of the idea is internal recirculation, pump is developing the vapour some how internally then vapour accumulates and after considerable time pump needs to be stopped. Please advice.	(4)
20/01/2014	Q:	I am currently working in diesel hydrotreater plant. The end products are naptha, kerosene and diesel. According to the lab reports the sulphur content in naptha is 2.7ppm and that in kerosene is 0.5ppm. Kerosene being a higher molecular weight fraction should have higher sulphur content. What is the correct explanation for this?	(7)
20/01/2014	Q:	I have some queries about UOP OLEX process: 1. What is total feed sulfur limit to Olex unit? 2. What are temp. & press. criteria of this unit? 3. Do we get only linear olefins from this unit or all kinds of olefins?
16/01/2014	Q:	In our DCU main fractionator we have refractory laid on first tray (chimney tray), and this is done to prevent coke formation on this tray (coke drum ovhd vapours @420 deg cel comes in immediate contact with HCGO in this tray), i would like to know whether there is any way to identify if coke starts forming on this tray even after laying this refractory. our operating pressure is bottom- 0.77 kg/cm2 (g) and 310 deg cel. top - 0.53 kg/cm2(g) and 105 deg cel. we have pressure transmitters and temperature transmitters across this chimney tray. (our DCU plant will get commissioned by jan 2014 end, I am relatively inexperienced in this unit)	(1)
13/01/2014	Q:	We have steam methane reformer. The outer surface of the tube is having deposits and leading to high fuel consumption as well as high temperature in flue gas side in waste heat section. During turn around we want to clean the outer surface of reformer catalyst tube so that we can reduce the fuel consumption and reduction in waste heat section temperatures. Is there any standard method available to clean the outer surface of the tubes?	(5)
10/01/2014	Q:	We have a single stage desalter that will run more heavy crude about API=23, Wash Water about 7%, T=280F. There are 2 Transformer about 150 kVa each. Is there a good way to assess what this existing transformer can handle in term of max conductivity of crude ? Are there easy calculations one can do if you had crude conductivity, etc?	(2)
10/01/2014	Q:	For an existing single stage deesalter operation that plans to run a heavy crude API of 26, wash water 7%. Vessel has two 150 kva transformer. Are there easy ways to see what is the max crude conductivity that this existing desalter grids can handle? Are there any general guidelines to make such assessment.
08/01/2014	Q:	Lately, have been experienced tube leak in DHDS stripper feed-effluent exchanger, Tubes were plugged and hydro-tested. Four months later, again leak developed and found tubes in bad condition, and was recommended for full bundle re-tubing. I would like to know what could be root cause for this tube failure in short time? Any specific improvement need to be done on internals of exchanger?	(5)
07/01/2014	Q:	Are there correlations available for prediction of coke lay down on CCR catalysts based on Charge rates, N+2 A and operation severity for a CCR Reformer ?	(2)
06/01/2014	Q:	In the Isomerization of light naphtha process with Pt/chlorinated alumina, can this catalyst regenerate in the unit as insitu?	(2)
25/12/2013	Q:	What is salt point at crude overhead?	(1)
25/12/2013	Q:	We are observing an increase in crude column boot water chloride while the processing of RAS GHARIB crude in higher %. The frequent excursions in chloride up to 40 ppm has been observed during the period. It also lowers the boot water pH.The iron values are within specs. It is understood that this crude contains the organic chloride in it which cracks in the furnaces and increase the chloride concentrations. The increase in caustic flow in the downstream of desalter is also not helpful. Kindly share the processing experience.	(1)
21/12/2013	Q:	Does any regulation / Code of practice calls for 300 lb rating Piping around AMMONIA storage tanks (liquid piping and Vapor piping)? Although the operating pressure in the vapor lines is around 500 mm WC , piping used is 300 pound rating Is it mandatory to size the PSVs of ammonia storage tank for fire case? Ammonia shows little affinity towards fire due to very narrow range of LFL and UFL.	(1)
16/12/2013	Q:	Is there any effect of coil steam to improve vacuum bottom viscosity introduced in a vacuum furnace?	(1)
13/12/2013	Q:	Please help us with two below questions: 1. What kinds of reaction will happen when we use ZSM-5 (9.2 angstrom pore size) as catalyst for treating heavy naphtha with range 80 - 180 deg-C? 2. ZSM-5 zeolite is treated by deposite SnCl2 and then calcinating at 450 deg-C in 8 hours? What products will we receive? Maybe RONC increase?
13/12/2013	Q:	We designed and built an octanizing system for upgrading octane number of heavy naphtha fraction with 8 cubic meter per hour. This system have no a hydrotreating package, so naphtha feed goes directly through heater and then reactor. Reactor dimension is 12 m length and 1.2 m diameter. But we use only 2.5 m length for containing catalyst (~1.8 tons). Internals have not inlet diffuser and distributor. Naphtha feed stream enter on the top and exit at bottom. Heavy naphtha has distillation range 80 - 180 deg-C, RON 68. Operating conditions are: inlet temperature 400 deg-C and 5 bar-g. Catalyst is a kind of zeolite with 9 angstrom pore size. It was treated by impregnating in SnCl2 solution and calcinating at 500 deg-C in 8 hours. We run a pilot as 6 lit per hour on 1 kg of catalyst. Efficient has RON 88 and 8%vol gas. But when run the reality system, it can not get that target. Catalyst is very easy to deactivate. Please help me to find some reasons.	(2)
07/12/2013	Q:	What the causes of naphtha diluted in water boot of overhead? visually water boot carbonized and foaming.	(1)
06/12/2013	Q:	Working in a production plant aromatics. The unit of liquid-liquid extraction using sulfolane as a solvent. High corrosion rates are presented and are now breaking equipment. Successful cases could help me with this problem and problem of corrosion in sulfolane? Additional info: Thanks for your answer. Actually we have a problem with oxigen in water system. The primary solvent( wet) is black color and foaming. whitout suspended solids. What best practices have been applied to detect and remove the air inlets in the vacuum system?	(6)
06/12/2013	Q:	What is the suitable Gas detector (for leak detection) in the higher elevations of around 50 meters. The service used were Crude at 75C and Crude column overhead vapour at 117C.
03/12/2013	Q:	The Normal feed for FCC unit is HVGO & HCGo from coker. In case of HCGO not processed 1) Can we get Regenrator temperature? 2) what is the behaviour of FCC unit?	(2)
29/11/2013	Q:	In our system High co2 content reported in VDU off gas analysis i.e., nearly 10%v/v. VDU column operated at 70mmHG and off gas routed in heater without any trapping of H2S. What are possible reasons for high CO2 and O2 content in VDU off gas? H2 % v/v 9.27 CO2 % v/v 9.61 C1 % v/v 33.04 C2 % v/v 15.00 C3 % v/v 17.44 C4+ % v/v 15.68	(1)
27/11/2013	Q:	When a pump feeding a crude column through the heater stops, should the evaporation of the residual liquid in the heater due to the residial heat in the heater refractory be considered for the relief case (e.g. total power failure case)? Or is it normally ignored due to limited inventory of liquid in the heater?	(2)
12/11/2013	Q:	In DHDT unit, RGC anti-surge control valve is opened at around 13-15 %, at this opening deviation from surge line is 0.14-0.20. The design molecular weight of Recycle gas considered is 2.94 whereas actual Recycle gas molecular weight is in the range of 2.25-2.4. Suction temp/ Pres:63 deg C /110 kg/cm2;Discharge temp/ Pres:90 deg C /131 kg/cm2 1.0 Can we fully close the anti-surge valve in order to increase energy efficiency of RGC ? 2.0 what other actions can be taken to minimize RGC anti-surge opening ? 3.0 By Incorporating the actual recycle gas molecular weight in anti surge controller block and compression suction flow transmitter, will there be any improvement in deviation from surge line ?	(2)
09/11/2013	Q:	How H2/HC ratio is calculated? Our design value(in VGO Hydrocracker) is 843 at hydrotreater inlet .Is it just a ratio of H2 gas flow to VGO flow at hydrotreater inlet mixing point. Shouldn't there be any factor of purity of recycle gas to be incorporated? Is H2 gas flow & VGO flow should be temp. corrected values or it is just a ratio of the tags showing in DCS without temp. correction.	(4)
08/11/2013	Q:	What is the most practical way to deplug LVGO nozzle of a vacuum tomer, whitout opening the tower?	(1)
05/11/2013	Q:	What are the main constraints in proper corrosion inhibitor selection for CDU (naphthenic crude oil)?	(1)
25/10/2013	Q:	What is the basis for Designing the LPG service pipe line ? 1) Operating pressure of the LPG (or) 2) Vapour pressure of Propylene in the LPG ?	(2)
17/10/2013	Q:	We have heard in many technical forums about ‘Unit Quench Factor’. We would like to know more on this term, monitoring experiences, correct technical formula & accuracy of this term in predicting stress build-up in coke drums. What are other ways for monitoring stress on coke drums? Are there any standard references/values for water quenching, steam quenching & vapour heating - rates and Deg C/Min?	(1)
15/10/2013	Q:	1) What are the technologies available for FCC flue gas desulphurisarion other than caustic scrubbing? 2) We have FGD using 20% caustic. Can we change to other cost effective methods in the same setup?	(1)
11/10/2013	Q:	If any reciprocating compressor is stopped, what is the condition of suction unloader valve? Suppose discharge loader valves pass why pressure not increase up to discharge pressure but same as suction pressure.	(5)
05/10/2013	Q:	In FCC we are having start up steam/lift steam at riser bottom & atomizing at u/s of feed nozzles. If I need to increase the partial pressure of hydrocarbon, which one is effective?	(2)
03/10/2013	Q:	- I have seen most of the cases Control valve( CV) with 1or 2 sizes less than the pipe size and with Reducer and expander u/s and d/s of CV. - Is there any reason to select lower size CV? - What are advantages of Reducer and Expander of piping u/s and d/s of CV - If i need to select CV size is same with the pipe based on Valve coefficient,what is the the impact Of "no reducer and expander"on CV performance.	(2)
02/10/2013	Q:	Does anyone know where I can get access to a bauxite percolation pilot plant or contract manufacturer to decolorize wax?
01/10/2013	Q:	I need a cost estimation for hydro desulfurization unit (HDS) by amine (DEA) in a petroleum refinery Given data for this unit : -hydrogen sulfide in feed = 8.6 mol % = 86177 ppm - feed =890 T/D -target.< 200 ppm
01/10/2013	Q:	I need to know the overall cost for the hydrogen sulfide removal unit by DEA,...And individual cost for each unit
23/09/2013	Q:	Can we change the trash baskets in heavy naphtha hydrotreater reactor by ceramic balls? (in all turnarounds trash baskets are clean without any scales but assembly of 85 baskets is very hard!!!) catalyst volume is 30 cubic meter	(6)
21/09/2013	Q:	Some deposits were found on the fuel oil heat exchanger. It was observed that at temperature below 100 C no such deposition occcur, but at temperature >=100 C some deposits were found. Please clarify what type of deposits are these and the reason for such deposition.	(1)
20/09/2013	Q:	What is the maximum cracked feed (LCO+LCGO) percentage that can be processed in the DHU unit?	(5)
18/09/2013	Q:	How can I calculate the optimal velocity in furnace tubing? At our gasoil/kero hydrotreater we operate usually at low throughput, but we keep the recycle gas at a higher value than needed for the reaction, to prevent the coking of furnace tubes. I guess that the optimal recycle gas amount could be calculated, but I don't know how to do it. Some additional info: It's the unit manager's explanation that he doesn't want to decrease recycle gas to prevent heater coking. We are usually running on low throughput with 4-500 Nm3/m3 H2/CH ratio. In the last cycle we had pressure drop problems on our reactor, we found solid deposit on top of the bed. We performed a furnace coke burning process during the last turnaround, and found that there was some significant coking in the furnace. Our licensors suggestion is, that H2/CH ratio should be approx. 5 times the H2 consumption. Based on this, 100-200 Nm3/m3 would be enough, but we are running often at 400-500 ratio, which is way higher than suggested.	(3)
11/09/2013	Q:	We are not using wash recycle system in CDU. Is there any drawback to that?	(2)
09/09/2013	Q:	I am process eng. at diesel hydrotreater unit. Recently we decided to treat blending naphtha in diesel unit spec of blending naphtha: IBP=145 dry point=195, sulphur in feed= 2000 ppm, sp.gr of feed is= .7640 flash point=35 deg c. We are planning to produce solvent aw402 from blending naphtha but we have two questions: 1) catalyst volume is 75 m3 and we are worried about LHSV (design capacity for diesel is 18000 bbl/day and minimum throughput of unit is 60%in design case). Is minimum 200 m3/hr for new feed OK or we can process lower feed? 2) What's the minimum inlet reactor temperature to hold minimum cracking because we have problem to set flash point in stripping section. Can we reduce temp. below 290 deg c ?	(3)
06/09/2013	Q:	My question is related with the effect of pressure and HCGO recycle in yields and HCGO properties. We would like to improve the properties of the HCGO product. If you increase the pressure or the recycle, the HCGO quality will be better but the yields will be worse (more coke yield). I would like to know if there is some difference between increase the recycle or the pressure. What option is more recommendable? Both variables produce the same effect (in yields and HCGO quality)?	(1)
05/09/2013	Q:	We operate our DCU main fractionator with Top Pr. 0.57 Kg/cm2g & Top Temp. 99 Deg C. We process VR with more than 5000 ppm normally. Recently column DP fluctuated a lot and we suspected salt deposition in trays. Steam was increased and DP become normal. Queries are: 1. How to calculate salt sublimation temp? What parameters I need to look into? 2. How to estimate salt quantity? 3. What are reasons for salt generation in system? 4. What kind of salts are expected - organic or inorganic? 5. Is it possible that if salt sublimes once and again it becomes vapour once temp increase ie. is phase reversal possible? 6. What are industry best practices to remove salts deposited? 7. Is there any way to avoid salts formation in system or avoiding ingress? 8. Any crudes responsible for high salts or its caustic dosing at crude desalters?
24/08/2013	Q:	Which Refinery Process Units Heater tubes are most often replaced and after how many years of operation?
24/08/2013	Q:	There are two different types of Pilot PSVs used in our refinery 1. Self Pilot (for which Pilot tapping is taken from PSV's body) and 2. External pilot (for which Pilot tapping is taken from PSV's u/s piping can be far from PSV) What is the criteria of selecting 1 or 2?
21/08/2013	Q:	What can be the cause of coloration (yellowish green) in VGO Raffinate hydrotreater effluent?	(3)
19/08/2013	Q:	We are heating desulphurization unit by natural gas (NG) without hydrogen up to 300deg C and being vented in to the flare. Instead of flaring this NG, after coming out out from desulphurization unit can we cool and compress in NG compressor and heat in waste heat section of reformer and feed into desulphuriser unit for heating? Please mention advantages and dis adventages? one of the advantage is vent of NG can be stopped. Any effect on catalyst? Like coke formation etc. Further info: We are only using only NG (CH4-93%+ 7% N2) first in NG compressor and then heating into waste heat section to increase the temperature of NG for heating desulphurisation section. After the heating it is being vent into flare. My opinion is instead of venting into flare can we cool it and again in compress and heat in waste heat section and again feed to desulphurization section to increase the temperature up to 300deg C. Any adverse effect on catalyst etc.? With this arrangement we can avoid venting of precious NG in to flare. No hydrogen is added during heating process.	(2)
19/08/2013	Q:	We are heating the desulphurisation unit with NG without hydrogen up to 300 deg. C and then NG is being vented through the flare. We want recycle this NG by cooling into exchanger and compress in to NG compressor again and heat in reformer waste heat section and to desulphuriser unit. Is this method ok?
19/08/2013	Q:	I have design a liquid distributor for non-foaming system and design liquid load of 5.1 m3/m2.hr and vapor load of 2640 m3/m2.hr. The desired turndown is 50% and turnup is 110%. The column ID is 300mm. The distributor details areas follows: 1. The distributor is 2 - level deck type distributor i.e. instead of punching orifices/holes in the distributor deck, there are pipes fixed to the distributor deck with each pipe having two holes (bottom and top) at a distance of 50mm. This ensures wider operating ranges. distributor deck is circular one piece sheet of 2mm thick 2. The number of drip points (no. of pipes) is 3 and at turndown the liquid head from the bottom orifice is 35mm. 3. The dia of lower orifice is 3 mm and upper orifice is 4mm. Could someone please advise if the type of distributor selected is proper and the design is adequate to ensure uniform liquid distribution.	(1)
14/08/2013	Q:	Can anyone share experience of putting Refinery Off Gas as Gas Turbine Feed? Advantages, Problems, Modifications required if any?	(1)
13/08/2013	Q:	I am studying the conversion of two stages crude dehydration/desalting train to operate as two separate units due to increased wet crude oil production from oilfields. Much apprecaite if someone can share thier experiences, what factors / paramters should be considered for the conversion and is it really feasible to proceed further.	(2)
31/07/2013	Q:	Would using a molecular sieve be the best bet for removal of chloride salt contaminants of refinery fuel gas? We are consistently plugging fuel gas valves, strainers, and burners causing reliability issues with our fired heaters.	(1)
30/07/2013	Q:	We are currently experiencing continued plugging of our refinery fuel gas control valves, strainers and burners. We went through a re-org 3 years ago where one of reformers was brought down. Since then, we have seen an increase of chloride salt contaminants to our fuel system from our other reformer. We currently run 2 molecular sieves in series on or hydrogen header. I proposed to increase heater reliability and reduce chloride salt contaminants to take second mole sieve and pipe the fuel gas header to it. This would of course be after testing hydrogen chloride content with only one sieve in service and projecting those results on compressor reliability from our maintenance group. If no real future damage can be projected and current single phase mole sieve can handle hydrogen system, would a mole sieve for the fuel gas be an adequate route since the vessel is already there and would only require a piping mod?
29/07/2013	Q:	We are facing the problem of almost all flange leakage in reformer inlet after shutdown (normal or emergency) plant licensor is Haldor Topsoe	(4)
19/07/2013	Q:	Can someone please help me with information on any recent advances in the alkylation process in a petroleum refinery and differences in the action of solid acid catalyst and liquid acid catalyst.	(3)
13/07/2013	Q:	If Light Refomate is the only feed of an Isomerisation unit, is there any chance of reflux drum of stabilizer not getting liquid at normal working pressure of 13.5 Kg/cm2g? (Liquid level building at lowering the pressure to 11.0 Kg/cm2g) Is it because of the C4 content is more in reformate?	(1)
09/07/2013	Q:	Why is the pressure drop of a Control Valve at the discharge of a pump in a liquid hydrocarbon service taken as 0.7 bar as a first guess?	(1)
08/07/2013	Q:	What is typical vacuum column off gas composition? We operate our Vacuum column at 410 deg C and 55mm Hg top pressure, recently we are getting high concentration of CO (about 40-50 ppm) in seal pot area where off gas condensate is washed.
05/07/2013	Q:	We have a liquid product named HCGO; ideally it's 280-430 cut material. We are analyzing its distillation by D86 method. same liquid sample when tested with D1160 recovery results were different. Since there is huge difference between 350+ recovery points we are confused as to which method to follow. 1. How to compare D86 & D1160 values - which are more accurate? 2. What is the range of D86 & D1160 test methods wrt. recovery points? Below is table for reference. Both the results are reported up to atmospheric values and in DegC. (OOR = Out of Range) S. No Distillation D-86 D-1160 1 IBP 287 280 2 5% 339 337 3 10% 347 354 4 30% 363 385 5 50% 374 403 6 70% 384 420 7 85% 396 437 8 90% OOR 446 9 95% OOR 461 10 FBP OOR 497	(3)
04/07/2013	Q:	I want to design a Jockey pump for our Refinery Fire Water Network. Which NFPA code is applicable? What would be design basis and criteria for sizing the Jockey Pump? I also want to design Overpressure protection system for Fire Water Network. Which NFPA code is applicable? Some Designers do not recommend to install PCV or Spill Back line to control Overpressure. Why?
04/07/2013	Q:	My question is related to arsenic and mercury contents in delayed coking products. We were thinking of sending coker naphta ang gas to the olefins cracker without hydrotreating beforehand. Both arsenic and mercury could cause problems in this unit. I would like if somebody have had some similar experience or if somebody know the level of these contaminants in these feeds.	(3)
04/07/2013	Q:	I want to know the effect of excess air on dilute phase temperature. Regenrator (Full combustion) is operating at 2% excess oxygen. If excess oxygen is increased to 5% for some reason, what is the effect on dilute phase temperature with same cat/oil ratio and cat circulation rate.	(3)
03/07/2013	Q:	Fire Water Network normally have both Motor Driven and Diesel Engine Driven Pumps for emergency use in case Fire Water Network pressure drops below certain set point. My question is, normally motor driven pumps are designed to kick-in on Auto start. Is it possible to design the operating philosophy so that Diesel Engine Driven pump kicks in first and then the Motor driven pumps? What are the pros & cons ? Is there any relevant NFPA code which is applicable?
02/07/2013	Q:	Issue : Since commissioning our coker naphtha yield remains always on higher side by 1 to 1.5 wt%. The quality of the Naphtha end point also remains on higher side 145-150 Deg C than the design value of 125-130 Deg C. We are operating our fractionator with top temperature 99 Deg C & pressure of 0.56 Kg/cm2 G. Top temperature, reflux flow rate & pressure are same as design conditions. We tried simulating the scenario but could not get any clues from that. Queries: 1. What may be the probable causes of deviation in Naptha end point from design? 2. To what extent can we reduce our top temperature, to drop heavy end of Naptha to LCGO cut below? 3. What are concerns foreseen for low fractionator top temperature operation? 4. To what extent Naptha quality degrades if section trays are damaged or reflux distributor is not working properly?	(3)
02/07/2013	Q:	What are the methods and guidelines to predict SRU Claus Catalyst life.	(2)
27/06/2013	Q:	Our termosiphon reboilers in SWS unit are corroded after only two years. Column works fine, but the tubes in reboilers are leaking, lids are corroded, full of deposits etc. Pipe from bottom of stripper column to reboiler is plugged, almost 90%. Results are poor quality stripped water (with high H2S and NH3). Tubesheet material is SA 266 Gr.2, tubes SA 179 and shell SA 516 Gr.60. Shell side (LP steam): 180C deg. Tube side (stripped water): 130C deg. What could be the problem?	(2)
27/06/2013	Q:	What are the allowable limits of lighter material (Flash point etc) in Process Units Feed like Visbreaker/Thermal Cracker.. ?
18/06/2013	Q:	1. VGOHT is processing Hot Feed from DCU & LVGO/HVGO/HGO from CDU-VDU and combined Crack + Straight Run components from Feed Stroge Tank. I would like to know about quick inference / thumb rule to access %Crack Components in Feed from Sorage Tank by monitoring Reactor Profile and Hydrogen Demand.	(2)
14/06/2013	Q:	We have in our plant diesel hydrotreater unit Packinox Exchangers high dP increment. The dP of Packinox feed gradually increased from 10~12 psi and reached the low limit alarms which is 22 psi in last one month duration. Preliminary observation is showing that the raise in pressure occurred after the increasing of SC#6 from 11 MBD to 15 MBD What is causing this problem, and what is the solution?	(1)
11/06/2013	Q:	The unstabilized naphtha streams from our CDU preflash and crude columns and off gases from hydroprocessing units are processed in Saturated gas plant (SGP). Processing separate out the gas and liquid products by a combination of compression, cooling and fractionation. The gases are compressed and combined with hydrocarbon liquid, cooled in a high pressure receiver to separate the mixture into vapor and hydrocarbon liquids. The vapor after C3,C4 recovery and amine treatment is sent to fuel gas system while the liquid hydrocarbon rich in Naphtha/LPG is pumped to Stripper followed by naphtha stabilizer and finally naphtha splitter to split naphtha into Heavy naphtha and light naphtha. The Stripper is a reboiled 32 tray column with top tray feed provided to remove C2 and lighter components from the liquid product. The stream composition and process condition of stripper overhead vapor is as follows: Stream Description - Stripper OVHD Stream Phase - Vapor Total Molar Rate KG-MOL/HR - 1,021.58 Total Mass Rate KG/HR - 46,931.65 Temperature - C 87.15 Pressure - KG/CM2G 10.3 Total Molar Comp. Rates KG-MOL/HR H2O 12.02 H2 26.49 NH3 0.78 H2S 205.46 METHANE 18.78 ETHANE 179.66 PROPANE 200.35 IBUTANE 91.72 BUTANE 153.85 IPENTANE 33.23 PENTANE 36.16 CP 0.02 C6+ 63.05816096 We are not injecting any corrosion inhibitor in stripper overhead stream. Is it a concern? Should we be dosing a corrosion inhibitor in stripper overhead stream based on the ammonia, water and H2S levels in stripper overhead?	(1)
11/06/2013	Q:	What is the Wheel Chamber in a Steam Turbine? What is its purpose?	(1)
10/06/2013	Q:	We planned to carry out top layer catalyst skimming in our Naphtha Hydro-Desulfurization Treatment (NHT) reactor. The skimming amount will be about 25% of total reactor volume. For this purpose, we have purchased fresh UN-SULFIDED Co-Mo catalyst, that will be loaded on the top of old sulfided catalyst during the near future skimming activities. In order to anticipate the future unit re-start up with PARTIALLY UN-SULFIDED catalyst, we consulted the catalyst manufacturer how to carry out the IN-SITU PRESULFIDING for this new unsulfided catalyst with the presence of old sulfided catalyst underneath . But the recommendations were not convincing. The presulfiding will be "liquid phase presulfiding" where the Sweet ( Treated ) Naphtha is circulated through the NHT reactor under H2 environment, before DMDS injection commences at reactor temperature of 180 degC. The required amount of DMDS for new unsulfided catalyst will be injected at the rate of 0.2%-wt-S of the circulating Naphtha. During this DMDS injection, reactor inlet temperature will be raised up gradually to 270 degC where the H2S breakthrough will happen, and will be on hold at this temperature till all required DMDS is injected. The Unit will then be adjusted to get on specification Stabilizer bottom product before being put on once through operation Please advise regarding to below questions : 1. Will the old catalyst --which had been sulfided in the past -- get the adverse effect during this future presulfiding, such as washed out sulfur from old catalyst surface ? 2. With the presence of old sulfided catalyst under the new un-sulfided one, we are not sure whether the measured exotherm across the reactor, and also the H2S breakthrough ,will be representing the actual presulfiding progress. Because old catalyst will enhance the exotherm and will advance the DMDS breakdown into H2S. In order to protect the new catalyst from thermal damage, what can we do to minimize the exotherm effect from the old catalyst to the new one ? In order to determine the end of presulfiding, can we rely on the total amount of required DMDS that has been injected during the presulfiding ?	(5)
08/06/2013	Q:	We are operating a balanced draft heater in DHDS units. What should be the action on Forced Draft fan in case of tube rupture of the heater and why...?	(1)
06/06/2013	Q:	What is the effect of high moisture (free water) on naphtha hydrotreater catalyst (Ni-Mo) performance?
04/06/2013	Q:	In Naphtha cracker the molecular sieve dryers are regenerated with Methane. But in Isomerization plant(MSQU) the molecular sieve dryers are regenerated with the valuable product isomearte. Is it possible to regenerate with off gas or fuel? is any limitation as these streams contains sulphur...?	(1)
04/06/2013	Q:	If the tail gas of SRU contains more SO2 , is there any chance of smoke formation in stack after incinerator. If H2S slip smoke formation happens and increasing air ratio to control the stack some free. But sometimes in low throughput smoke is coming. is it because of more SOx and NOx...?	(1)
03/06/2013	Q:	What is the Wheel Chamber in a Centrifugal Compressor and what is its purpose?
01/06/2013	Q:	What is the purpose of MFA additive in MS blend? What is chemical composition of MFA?	(1)
01/06/2013	Q:	Our fcc unit works good up to now. In routine checks we find out that the torch oil nozzles are plugged I would like to ask what can be done (the steam atomizing is ok): Can we try to inject oil through the atomizing steam side without steam, in case we need it? Can we try to unplug them using water pressure 50-100bars? Let me explain further. As you know, the torch oil gun has 2 pipelines (externally for steam and internally for oil). In current operation, the steam flows through the torch oil nozzle (external pipeline) and finally routes to the Regenerator. However, we observe that the oil stream cannot flow, due to plugging of the internal pipeline of the torch oil gun. We want to unplug the oil pipeline, via let’s say water or other oil quality (e.g. light cycle oil). Are they convenient? Other ideas?	(4)
31/05/2013	Q:	On line Hygrometers are used to measure moisture content in CRU recycle gas. On many occasions the measured values are suspected to be incorrect by plant people. What type of on line hygrometers are highly reliable and what are the maintenance practices for these analyzers?	(2)
26/05/2013	Q:	Can anybody tell me the approx. cracking temperature of ADNOC Murban crude oil having API gravity 40.5?
22/05/2013	Q:	What is the purpose of adding Ammonia during the regeneration of HDS reactor for Gasoline?	(3)
22/05/2013	Q:	Can propylene be used as a co-feed to H2SO4 Alkylation plant? The plant is designed for C4= with iso-C4 case only. What are the pros and cons of co-feeding?	(1)
18/05/2013	Q:	Is it possible to Hydrotreat Merox treated Naphtha in NHT?	(4)
12/05/2013	Q:	My question is on Acetylene Selective Hydrogenation Catalyst (Palladium –Pd based with promoters): Ethane gas gets cracked in the Cracking Furnaces and the effluent goes through series of processes that includes quenching, heavy contaminants / heavy hydrocarbons removals, Multi-stage Compression, Caustic Scrubbing with Drying leading to De-Ethaniser (DeC2), and DeC2 Column Overhead vapour to the Two-stage Acetylene Hydrogenation Reactors. Main feed Ethane gas has a spec. of CO2: 200 to 1000 ppm; Total Sulfur: 500 ppm; Moisture content: 100ppm and it is directly cracked in the Furnaces. There are other feed streams having Sulfur ppm in the range upto 50 or so, with metal traces at lower ppb levels. The Reactors are operated with Carbon Monoxide level of 1000 ppm to 3000 ppm Max or so, at the upset conditions. Outlet Acetylene ppm levels are stringent in the range of 0.2 to 0.3 to produce Ethylene with 1 ppm Max Acetylene impurity. a) Pl. let me know what all process parameters have direct impact on Catalyst deactivation and thereby short run-time requiring ex-situ Regeneration. b) How will you control the parameters effectively to have much longer Catalyst run-time? c) What is normal catalyst run-time for such Catalysts irrespective of any Catalyst vendors? d) Whether going for Regeneration, would it be recommended to revive activity and selectivity to that of fresh material? Any risk involved in taking decision in favour of Regeneration? e) Vendors confuse often with jargons, Reactivation and Regeneration. Are they one and the same or the process of reviving the spent material to the active phase to prolong the operation with recycle not only due to downtime of plant but also, expensive nature of catalyst with precious metals? f) Pl. suggest suitable catalyst vendors with whom development activity can be collaborated with the company’s R&D Centre. g) Any other important points in relation to specific Catalyst poisons, improving run-time atleast upto 4-5 years if not 10 years+ Your thoughts on this, in whole or part, greatly appreciated.
09/05/2013	Q:	I have laboratory ASTM D7169 data for Vacuum residue of Vacuum unit & Clarified slurry oil from FCC. I want to use them in simulation. As per literature information it is mentioned that for Vacuum residue ASTM D7169 data can be used as True boiling point data in Wt% & i have seen it is giving ok type of match for simulated properties. However, for FCC Clarified Slurry oil (cracked stream) when i input (in simulator) as TBP wt% then even there is lot of mismatch in density itself. Can you please tell me whether for cracked stream is it appropriate to use ASTM D7169 data as TBP wt%? if no, then how to model it in a simulator like Aspen plus?	(2)
03/05/2013	Q:	We are studying the feasibility to capture CO2 from our HMU ( Hydrogen manufacturing unit) reformer. At the outlet of PSA 50-55% CO2 is available ina wate gas stream. Has anybody had experience of CO2 capture feasibility from waste gas stream?	(1)
30/04/2013	Q:	What is best refinery practice for the location of TSVs in offsite area and TSVs discharge outlet?
27/04/2013	Q:	How long can a Refinery Heater be operated above design duty in case skin temperatures are within range and heater tubes design life is completed. Can decoking of such a heater result in any tubes problem i.e bulging, sagging or rupture?	(4)
20/04/2013	Q:	In one of the client refineries which we are working with, they are facing severe corrosion in the 2nd and 3rd stage ejectors of the vacuum column. The current treatment program is adding CI and neutralizer before the 1st stage ejector and during inspection/shutdown there has been no corrosion observed in the 1st stage but huge corrosion observed in the 2nd and 3rd ejectors. Is there are any similar kind of issue faced in other refineries. If so what has been the solution measure taken?	(2)
19/04/2013	Q:	Why do multistage reciprocating compressors have different compression ratio for each stage?	(1)
19/04/2013	Q:	In the case of multistage compressor, why is it that the compression ratio are not set equally?
18/04/2013	Q:	Why does COT of a furnace go down when fuel gas supply pressure goes down (at constant fuel gas composition, though fuel gas main control valve opening increases to maintain COT and fuel gas flow to furnace also increases) and constant furnace throughput?	(2)
14/04/2013	Q:	We have proposed to install a "hot separator" in the recycle gas loop of a heavy naphtha hydrotreater unit operating at a pressure of 65 barg. The configuration which we are contemplating will be similar to kerosene hydrotreater units which usually have both high temperature and low temperature high pressure separators to enable liquid condensed at high temperature to be directly sent to the stripper without cooling. Concerns have been raised by the process licensor that chlorides may be condensed with liquid in hot separator and reach the stripper with feed thereby causing choking/corrosion in stripper. Does anyone have any experience of operating a hot separator in a heavy naphtha hydrotreater? Simulations predict significant heat recovery potential from this project in line with savings achieved in several similar projects in Diesel Hydrotreater units. Can anyone share experience of discovering precipitated chloride salts in the high temperature combined feed effluent exchangers (operating over 200 deg C) during cleaning operation?
05/04/2013	Q:	For a FCC unit processing 50% DVGO and 50% VGO, sulfur content of 0,5-1%, where it can expect the highest corrosion rate?	(1)
04/04/2013	Q:	I am looking to increase reboiling capacity for a column which already has four parallel thermosyphone reboilers. However, there is a space constraint for a new reboiler and also, since there are four reboilers, replacing each with high capacity could be a costly affair. Hence, i am looking for some alternative. Is it feasible to operate a column with four existing thermosyphoe reboilers plus a new forced circulation reboiler in parallel to existing thermosyphone which can be located at some distance from column and hence, there won't be issue of space constraint? could there be any operating difficulties because i have never seen this type of arrangement?	(3)
03/04/2013	Q:	I'm working on a study to design a new control schematics for Crude Distillation Column Pressure Control. Any ideas for CDU pressure control strategies?	(1)
31/03/2013	Q:	What is the typical level of diolefins that corresponds to Existent Gum and Potential Gum Specificaions for Light naphtha and Heavy naphtha?	(1)
29/03/2013	Q:	Please give the possible causes of increased pressure drop in middle and lower catalyst beds in VGO Hydrotreater main reactor. What solutions could be implemented to prevent pressure drop events?	(4)
26/03/2013	Q:	We are going to commission a new refinery which includes Hydrogen Unit also. The Naphtha feed specication for the Hydrogen unit is <1ppm Sulfur and boiling range of IBP-95 degC. But during commissioning we cannot suppy the above naphtha spec. So it is agreed to supply naphtha with boiling range of IBP-160 degC and Sulfur <150 ppm for initial one month. The Feed Desulphurised catalyst vendor says it cannot handle beyond 30 ppm Sulfur. Can anyone share such experience and can advise how to manage the situation. Also what will be the Hydogen yield with changed specfication of feed Naphtha?	(6)
22/03/2013	Q:	We have cooling water contermination. Few drops of oil observed on the water surface. The water is dark and some particles observed on filter paper. Water turbidity becomes high. How can we identify the exchanger leaking?	(1)
15/03/2013	Q:	What is the Nelson Complexity number for MEROX Process and for Deep Catalytic cracking process ?
15/03/2013	Q:	We are using RPMS for refinery LP modelling. Can any one tell what are the other packages and their advantages over RPMS?	(1)
12/03/2013	Q:	In one of our FCCUs we have problems closing heat balance due to the processing of a very hydrotreated feedstock. We have to use torch oil (LCO or fresh feed) to maintain regenerator at its minimum temperature. We are evaluating the possibility of using other feedstock as torch oil. Has anyone experience in using fuel gas or natural gas as torch oil in the regenerator? What major modifications in hardware are required?	(2)
12/03/2013	Q:	Some weeks ago we saw some cracks in the FCC expander blades in one of our FCC units. The cracks appeared suddenly, from one month to another. The fresh catalyst addition rate are very low, so catalyst turnover is slow. It has provoked the ageing of our e-cat inventory. We have measured the attrition of the e-cat, with Jet Cup method (Davison Index), and there is a decrease from 2-3 to 1-2. My question is could this decrease in DI of the e-cat (harder catalyst) be responsible for the mechanical problem in the expander?	(2)
08/03/2013	Q:	In VGO hydrocracker and Hydrotreater, where would you put the purges for the PSVs on CHPS, HHPS etc to prevent it from plugging/fouling due to salt deposition i.e. on the common take off from the vessel or separate for each PSV, right below the seat of the PSV?	(1)
03/03/2013	Q:	We are facing intermixing of shell side medium into tube side in Breech lock heat exchanger in DHDT unit. During maintenance of the exchanger, the shell to tube sheet gasket (sprial wound gasket) was found damaged. The gasket was replaced and hydotested as per procedure. We understood that this type of problem is being encountered in most Refineries. I would like to know whether any specific improvement needs to be done on internals of Breechlock heat exchangers. Has anyone used Camprofile gasket instead of spiral wound gasket for shell to tube sheet gasket?
02/03/2013	Q:	What is the process of speciality chemicals derived from Kerosene, mainly : 1. aromatic solvents (Mineral Turpentine Oil MTO type) for paints & varnishes, pesticides 2. dearomatised / hydrogenated aliphatic fluids (white spirits) for alcohols, ethers, esters : for perfumes, cleaning agents, etc. 3. paraffinic compounds for foams and dry-cleaning synthetic / woolen clothes 4. heavy distillates as solvents for commercial dyes & inks 5. high boiling solvents as lubricants in metal cutting / rolling industry.	(2)
01/03/2013	Q:	I have below doubts regarding Gas Chromatograph (GC)which is installed in the laboratory. GC in the present case is off line (sample is injected not continuous) GC uses Hydrogen as a fuel or carrier gas. a) Is there any chance of leakage of hydrogen from inside GC to outside? b) In the GC room does HAZARDOUS classification applied due to use of Hydrogen and Process samples (hydrocarbons)? c) Does electrical items - switches ,lighting fixtures needs to taken as flame proof, explosion proof or intrinsic safe? d) Can GC be classified as flame proof? If so, what components of GC will be qualified as flame proof? e) Are there any case studies available about explosion in GC room due to hydrogen leakage?	(2)
26/02/2013	Q:	How do you improve fuel gas composition if Refinery Fuel Gas System is found to be 'Too Rich', and thereby improve refinery margin? What should be typical FG composition (minima/maxima) to be maintained for an integrated refinery (full conversion) with downstream petrochemicals (say, 400,000 barrels/day crude processing)? What kind of process adjustments, do you recommend to bring the FG composition acceptable in the above minima/maxima range, so that there is a 'value addition' to utilise Fuel Gas System to utilise 'optimal quantity/quality' in the Fired Heaters in the Complex?	(1)
20/02/2013	Q:	We have NHDT for Isomerization unit. In NHDT wash water used to dissolve the salt, thereafter sour water separated from naphtha in separator vessel. For last 2 months we are unable to separate sour water in separator or even in stripper column. What could be reason and solution?	(2)
17/02/2013	Q:	Please advice about the operation practice of the reciprocating compressor in order to increase life time of discharge valves in the compressor cylinders. We're operating a Hydrogen plant using water electolyser cells - using alkaline which is KOH, operating temp 70C and production rate 170 nm3/hr where reciprocating machines are used to suck hydrogen from a gas holder directly after the cells and discharge it to the high pressure line to the customer (200 bar). The Gas Compressor comprises of 5 stages, where first stage is consits of 2 plate valves. The problem always happens to first stage Gas Compressor. Just 15~30 days after starting, the discharge valves in the cylinder always develops a leak and fails. Upon dismantling, we used to find some debris and gum particle (deposits) in between valve plate and valves top. The problem occurs over and over again. The deposits particle is KOH which comes with the hydrogen gas vapor passing through the suction filter and rest on the valve.	(2)
11/02/2013	Q:	In one of our FCCUs we have an automatic pneumatic fresh catalyst injector to load the catalyst from the catalyst tank to the regenerator. Some weeks ago we start having problems with the fresh cat injection. After inspection of the pneumatic injector, we could see a very hard deposit on catalyst in the injector valve. We found some other catalyst agglomerates in the tank. We believe it could be formed due to a leak in an steam line in the fresh catalyst vessel. After several weeks and trials we have not been able to run again with the pneumatic injector and we must load the catalyst manually, straight from the tank, through the by-pass line of the pneumatic injector. After a very exhaustive inspection, everything seems to be OK mechanically in the all the system (vessels, piepes, etc). The catalysts deposits in the tank have disappeared. We are also having several fluidization problems in the loading pipe to the regenerator, both using the pneumatic or the manual loading. Have anyone experienced similar problems? Could the properties of the fresh catalyst be related to the problem (losses on ignition, humidity, atrition, PSD)?	(1)
01/02/2013	Q:	What is the objective of phosphate injunction in the cooling water network and in any steam disengaging drum in the steam system?	(2)
29/01/2013	Q:	is it possible to Presulphide NHT Catalyst with Straight Run Diesel ? Straight run from CDU can also contain moisture. Can this moisture result in lump formation or reduce the strength of the catalyst?
28/01/2013	Q:	1. How we predict/calculate theoretical life of sulfur guard bed if we know the weight and bulk density of catalyst? Purpose is to absorb sulfur (Organic/inorganic H2S) from light naptha before goind to isom section? 2. Can we use DIH (De-ioshexaniser column) bottom isomerated in Recycle feed in Isomerisation section for increasing the conversion of n-parafins into iso-parafiins? what will be the impact on isom catalyst life? Additional info: Here light naptha means C5-90 CUT coming from Naptha splitter (Ex-cdu unit)	(3)
26/01/2013	Q:	Planning a New Hydrotreater (HDS) Unit to remove Sulfur from Heavy Cracked Naphtha stream ex.FCC Unit. To achieve Ultra-low Sulfur Gasoline specs. (<10ppm), and also to meet Gasoline production, other two Naphtha streams are planned to be treated in the above new Hydrotreater. Naphtha ex. Merox Unit having about 375ppm Sulfur is one of them. My query to subject matter experts are as under: a) Is it recommended to treat Merox treated Naphtha in the above new Hydrotreater? OR b) Bypass the Merox Unit; Only treat the Naphtha stream with aq. caustic (Pre-wash only for H2S removel); No conversion to Disulfides by 2nd stage Oxidation process in the existing Merox Unit. Feed the untreated Naphtha stream directly to the New Hydrotreater. Would appreciate pros and cons of treating the straight run-Naphtha, by-passing Merox Unit and treating it in the New HDS Unit. Many thanks for any useful advise from SME.	(3)
26/01/2013	Q:	In our Haldor Topsoe plant burners mounting plates get red hot at high throughput say 90-100%. What may be the possible reason?	(2)
25/01/2013	Q:	In case of non-contact temperature measurement of the skin temperature of furnace tube, which instrument is better: infrared thermometer or laser pyrometer? What is the allowable temperature difference between thermocouple or thermowell temperature measurement to non-contact temperature measurement?
24/01/2013	Q:	Recycle gas from high pressure separator is being treated in amine absorber. Treated gas then routed to recycle gas compressor (2 stage). We are observing lot of liquid accumulation in the inter stage KOD (after cooler). Liquid sample is analyzed and found that 99.7 vol% of sample contains water and remaining as amine. We are adding water to the amine system to compensate the loss through inter stage KOD. Lean amine to absorber temperature is being varied in the range of 55 to 60 °C to maintain design DT between amine & gas. We have observed that the absorber top temperature is high when compared to bottom temperature. Why only water is getting carried over (in huge quantities) along with the treated gas? Is the same observed in any high pressure amine absorbers. Why temperature profile in the amine absorber is in the opposite direction? Is this related to moving of heat of absorption profile from bottom to top? Further info: If there is a foaming in the column the following should have happened: 1. Fluctuations in absorber bottom level; not fluctuating 2. Severe fluctuations in DP across the absorber; not fluctuating 3. Improper stripping of H2S from gas; not observed 4. Amine foaming tendency test is also done and found satisfactory. In the case of foaming in the absorber, amine should also get carried over along with water. But this is not happening. As i said earlier amine content in the water sample is in the range of 0.3 to 0.5 wt% only. What is the ideal delta temperature to be maintained between gas and amine?	(2)
23/01/2013	Q:	I am looking for any tips for hydrocarbon clearing and cleaning heavy hydrocarbon exchangers using only a hot DF2 wash and then 150# steam. Any suggestions will be appreciated.	(1)
19/01/2013	Q:	What causes foaming in coke drum?
19/01/2013	Q:	Why does the stripping steam trip close when there's a high level in tower?	(3)
18/01/2013	Q:	Is it possible to Presulphide the NHT catalyst with Fuel gas containing H2S?	(3)
16/01/2013	Q:	We are engaged in an intense debate on the Turndown ratio of our Fixed bed radial flow Reactors. These reactors are designed for a Feed flow rate of 24000BPD. However we want to short load the catalyst with 50% quantity that is 45tons instead of 90tons of catalyst and operate the unit at around 12000BPD. With 45tons of catalyst our apprehension is there will be maldistribution of the feed. There is another option of using two reactors instead of three and distribute the 45tons catalyst in two reactors. Your comments are required on these innovative ideas. Would you suggest any modification for the internals at the top section of the reactor?
10/01/2013	Q:	Im working in diesel hydro desulphurization unit. We have one stripper-stabilizer section with common O/H system. Direct stripping steam is used here. We used to get product diesel Cu strip result as 1b. Recently we are not able to meet product copper strip of 1 (we are getting it as >3). The following are attempted to normalize the section: a. Checked the steam line for condensation. Line temperature is at 300 °C and there is no water b. Upstream & downstream exchangers were checked for leaks. No leaks c. Inlet temperature increased gradually from 235 to 254 °C d. Stripping steam increased gradually from 3 MT to 4.5 MT e. Withdrawn more distillate from reflux drum. After doing the above, we could reduce the result from > 3 to 2. Simulated the column with earlier conditions & with present conditions. I could not find any H2S slip in bottoms for both the conditions. Even i tried to simulate the column by taking out few trays. There is no improvement. Please provide your valuable suggestions to improve it further. Also please provide reply for the queries given below: 1. Cu strip result definers with color. But how much H2S will be there in product if the result is 1, 2, 3? 2. How to find out whether there is flooding in the column. DP across the column is at 0.25 Kg/cm2. Will it vary severely if column is flooding?	(5)
09/01/2013	Q:	In a Ammonia storage tank (at atmospheric condition and -33 deg C) when will more boil-off happen: a) If the Ammonia is filled till half of the level , or b) If Ammonia is filled up to full height Tank construction is with Double wall, with perlite concrete at bottom, foam glass at bottom and Mineral wool at suspended deck.	(1)
09/01/2013	Q:	What was the particular properties of Napo crude and the problems that might be encountered during its processing?	(1)
02/01/2013	Q:	We are currently using overhead sour water as wash water for the crude overhead system which is injected just before fin fan coolers. Neutraliser is injected into the vapor line before water injection point. Will injecting neutraliser in wash water line help reduce corrosion in crude column overhead system?	(4)
23/12/2012	Q:	In our CDU column we draw off naphtha (overhead) , kerosene , light diesel , heavy diesel and AGO fractions and 4 pumparound circuits (on kero, light diesel , heavy diesel and AGO sections). The top of the column is cooled by reflux (overhead –air coolers-receiver – column) . From a simulation it appears that approximately 55 % of heat from the atmospheric column is wasted in overhead line (air coolers) and the rest 45% is recovered in pumparounds heat-exchangers. We would like to introduce the additional pumparound (TPA) and recover some of the heat in new heat exchanger(s) upstream the desalter - of course the exact location of the added heat exchanger will be analyzed with pinch study. What do you think about the solution of introducing the additional pumparound in order to recover some of the heat which is currently wasted in air coolers? Maybe some other recommendations about recovering this heat to the process.	(7)
22/12/2012	Q:	Which neutralization method is best for batchwise production of acidic effluent?	(1)
22/12/2012	Q:	Is there a new and advance technology or method to recover the dissolved ammonia in waste water in a pure form?	(2)
10/12/2012	Q:	What is the experimental relationship between 20% Diethanol Amine and 45% MDEA for H2S Absorbtion?	(2)
09/12/2012	Q:	Is it a myth or reality that in a refinery fired heater for the same throughput, same coil outlet temperature and everything else being the same, a fuel oil fired furnace will give a lower skin temperature in the convection section than a natural gas fired one?	(5)
06/12/2012	Q:	Is jet flooding and or foaming a composition only issue for a hydrotreater stripper column?	(3)
27/11/2012	Q:	Between flooded condenser pressure control and hot vapor bypass control in a distillation column which one is more preferable and under what circumstances?	(3)
25/11/2012	Q:	What is the Best Practice for time switchover between standby rotating equipment?	(1)
24/11/2012	Q:	In many molten sulphur pits where solid sulphur is melted with LP steam coils, fires keep occurring. What could be the reasons?	(1)
12/11/2012	Q:	What exactly potash fixation means for reformer catalyst and does over steaming have some impact on catalyst performance? What factors will lead to leaching of potash from reformer catalyst?	(2)
10/11/2012	Q:	We are operating a small refinery in which the crude column has three side draws with h naphtha, kero, diesel there is a kero pa and diesel pa. There was coke in the suction of resid (crude bottoms) pumps to find the cause we opened the coloumn on inspection little coke was found however the trays below kero pumpa were displaced and crumpled no possibility of adding water was observed as stripping steam was added after through purging and was invisible(super heated) steam addition However there was hammering at kero pa on start up which stopped after increasing kero pa temperature to avoid adding subcooled liquid in a sparger on low flow (at start up) the trays above the kero draw were not affected at all Can any one throw light what are the possibility to look for? Running the unit again without identifying the cause of accident doesn't make sense. Besides water surge, which doesnt appear to be the cause, is there any other cause? We were running the column at 30 psig pressure (design operating) is 15 psig can that be a cause? But diff pressure was normal though slightly higher as we were operating with high naphtha yield than normal trays were operating at 50 to 60 npct flood as calculated thru simulation.	(3)
08/11/2012	Q:	We have NHTU section preceding our Platformer in the CCR unit. Initially we were loading NHTU with 60% low sulphur SRN and 40% high sulphur FCC gasoline (from gasoline splitter section). SRN had feed sulphur of 100-150 ppm and FCC gasoline sulphur was around 1200 ppm. However because of some issues we stopped taking FCC gasoline and the plant was taken on 100% SRN throughput. This resulted in higher NHTU furnace load ( as exotherm in reactor and preheat across CFE reduced tremendously ). However the NHTU r/d sulphur which in case of FCC gasoline operation was 0.3-0.5 ppm increased to around 1 ppm in the latter case ( 100% SRN throughput ). Why has r/d sulphur increased if feed sulphur has decreased (all other paramters are constant)? P=45 kg/cm2 and RIT =280 deg cel are the same at in both the cases. Secondly, is there a minimum partial pressure of H2S in the hydrotreater recycle gas needed to maintain and ensure that the reactor catalyst remains in the sulphided state and does not go into its reduced form?	(4)
26/10/2012	Q:	We have hydrogen reciprocating four cylinder compressor. Every time after over hauling we take No Load trial for 2 hrs with discharge valve removed condition. Then we purge with nitrogen, then twice with Hydrogen. Now During Load trial Motor trip on Over load, (0% capacity), after barring compressor around 2 rotation, the compressor started Normal. Why compressor started smoothly after free rotation? We already taken No load trial one day before.	(2)
21/10/2012	Q:	We encounter polymerisation from phenolic material in the KO drum of the SWS overhead system. As a result, KO drum bottom is frequently plugged and this means that in case of massive carryover from the SWS reflux drum the liquid would not be pumped out of the system. Source of phenols is the FCC. The analyses of the polymeric fouling don't give clarity on the other components, but the appearance is similar to phenol-formaldehyde resins. Please note SWS reflux drum is operated at 87 C (to avoid ammonium bisulfide deposition) and the downstream system is traced and heated with steam so that the temperature is normally > 100 C (no water is separated in the KO drum in normal operation). Did anyone encounter similar problems in SWS OVHD systems, and how did you solve them?	(3)
18/10/2012	Q:	We are operating a hydrotreating reactor loaded with topsoe catalyst TK-562 Brim.We have 2 reactor in series guard bed and main reactor. Guard bed reactor is loaded with demat catalyst. During start of run the delta t across guard bed reactor was 28 Deg-C. But during six months we are observing that delta t of guard bed reactor is gradually reducing and had reached 6 Deg-C.Guard bed reactor delta p is normal and is around 1.5 bar. Also we observed that all guard bed rection had been shifted to main reactors and we are getting high delta taround 25 deg-C in 2nd and 3rd bed of reactor. We are operating our unit at 125 KBPSD. What is causing this?	(4)
11/10/2012	Q:	Recently we faced an emergency in our one through hydro cracking unit. We experienced a tube rupture in our vacuum column re-boiler due to over heating and once we introduced emergency coil steam in re-boiler tubes, a major fire broke out in the furnace, leading to complete destruction of furnace. The logic behind introducing the emergency coil steam with pressure of 15 kg/cm 2 was if air will ingress through ruptured tube and make its way to vacuum column, it will lead to explosion of column. Kindly comment on this as it is not clear to us whether it was a right decision or should we wait to cool down the furnace?	(3)
10/10/2012	Q:	During a recent turnaround, it was found that the vacuum unit heater tubes are badly coked (1/2" to 1"thick coke layer as per the inspection Engr). Due to shortage of time we could only manage steam spalling. The heater tubes are plug head tubes ( we do not have any drawing of the plug head tubes). Can we do Pig Cleaning of the tube? Wil the plug make any hinderance to the movement of the pig?	(2)
08/10/2012	Q:	Is that correct that a desalter can't remove organic salt? If not, why not?	(3)
04/10/2012	Q:	As per section 11.1.3 of API 574: "In low-pressure and low-temperature applications, the required pipe thicknesses determined by the Barlow formula can be so small that the pipe would have insufficient structural strength. For this reason, an absolute minimum thickness to prevent sag, buckling, and collapse at supports should be determined by the user for each size of pipe." Table 6 of the same code provides some data for Carbon and Low-alloy Steel Pipe at less than 205 degree centigrade condition. My question is how this strength is measured and in case of temperature higher than 205 degree centigrade what are the values?
01/10/2012	Q:	We are using light isomerate (c5/c6) for regeneration of Feed Dryers in Msqu Unit As moisture is poison for isomeraisation catalyst so why is steam used for heating isomerate initially in vaporiser (shell side-naptha, tube side --steam) from 50 dgec to 147 degc (heating to the boiling point of isomerate)? Then superheater is used for heating isomerate outlet temp. from 147degc to 320 degc. @ 60 degc /hr 1. If vaporiser tube punctured/ leaks then there may be chances of going steam into isomerate. Is process disturbed and will it poison the catalyst? (steam pressure~ 8.5 ksc while isomerate press.~9.0) 2. Why can't we use superheater initially from 50 degc to 320 degc? Is there any problem of heating liquid isomerate or it can lead to coke? 3. Is superheater used for only vapor phase not liquid phase?	(2)
30/09/2012	Q:	I want to boost the pressure of MP separator off gas containing 90% H2 from 24 barg to 70 barg. I want to install Hijector for boosting the pressure. Can anybody suggest what will be the pressure of my motive fluid, whether such scheme will work and, if not, what are the alternatives?	(1)
27/09/2012	Q:	We run a bitumen blowing tower producing off-gases (toxic gases) which we exhaust to an incinerator. What is the recommended material for the valves used in this service?
27/09/2012	Q:	We have a problem in the hydrotreated filters when feeding HCGO. In these filters, we usually feed VGO and we haven´t any problems, but when we try feed HCGO from coker unit, the filters are plugged at the few minutes. The ratio between HCGO and VGO is 30/70% aprox. and the temperature of these filters is 170ºC. The filter element are wedge wire with 75 microns. When the filter is plugged, although the filters are backwashed, the AP don´t go down, and It´s necessary to shut down the unit to clean up the filters mechanically. We are doing some studies to identify the origin of the problem. - Filtration studies to cuantify the solids of both of feeds: HCGO has 150-500 ppm of solids, which are mayoritary coke. VGO has 300 ppm of solids, which are mayoritary inorganics particles. - Asphaltene determination (IFP method): HCGO has 200-500 ppm and VGO has 100-300 ppm. - Compatibility studies: We have done a compatibility study in laboratory, which consists of adding gradually HCGO to VGO, then the mix is viewed in the optical microscope to identify the asphaltene precipitation. In this study we have seen that the feeds are unstable above 15-30% in function of temperature. The higher temperature the higher unstable is the mix, and the asphaltene precipitate at lower HCGO percentage. Therefore, we think the plugging problems are due to the precipitation of asphaltene forming an impermeable layer on the filter, which doesn´t disappear even when the filters are backwashed. My first question is if somebody has experience of this sort of event? We think the solution is not to increase the filter area, but eliminate the problem at its source, to reach a HCGO cleaner wiht less asphaltene content. My second question is related to the effect the asphaltene precipitation with the temperature. I thought that the higher temperature the lower precipitation but we have seen the oppsoite effect.	(8)
26/09/2012	Q:	While cutting a replaceable tube inside furnace, a cut mark by gas cutting tool is found on adjacent good tube. A cut mark of 3 mm depth and 6 mm diameter is created on a 3 inch (originally 5.49 mm thickness) A335 Gr. P5 tube. Should I replace the tube or locally repair the mark by welding? I should add that overall thickness of the tube is satisfactory.	(1)
26/09/2012	Q:	I have observed corossion in my crude overhead line to finfan coolers. The overhead line is not insulated and the temperature here varies from zero to 55 degree celsius. Would insulating the line help me in reducing the corrosion? What are the other impacts of overhead line insulation? Note: We are operating the top temperature 25-30 degress above the dewpoint temperature.	(7)
25/09/2012	Q:	Why is nitrogen blanketing provided for the oxygen-enriched line in a sulphur recovery unit?
24/09/2012	Q:	I work on CDU/ VDU plant as a process engineer . We commissioned performance of the feasibility study concerning revamp of the vacuum system. It appears that we may achieve different vacuum at the top of the vacuum column with different solutions, so we have to consider the best option in terms of the yields of the fractions. Is it possible to simulate in Sulzers proprietary application SULCOL how the yields will change from the vacuum column 1. when I set various pressures at the top of the column (without modification to vacuum column) 2. when I change the structured beds from current structured packing Mellapack to Mellapack Plus or other. I would be very grateful for some information with regard to technical capabilities of this program or maybe some recommendations for other free software of this kind.	(3)
24/09/2012	Q:	In Platforming unit is their a particular process condition under which C7 paraffins will transform to toluene?
24/09/2012	Q:	In CCR Platformer unit nitrogen contaminant leads to a higher delta T in Platformer Reactors. Why?	(1)
23/09/2012	Q:	What is preferable for me to enter a process water or condensate to crude oil desalter?	(1)
17/09/2012	Q:	If caustic dosing suspended due to some unavoidable reasons is it possible to reduce overhead corrosion (caused by hydrochloric acid) by increasing amount of neutralizer like ammonia or amine at overhead of the Atmospheric distillation unit?	(3)
17/09/2012	Q:	What is the expected life of fin tube of overhead air cooler of Atmospheric distillation unit?	(1)
17/09/2012	Q:	What is the expected life of polyurethane seal of floating roof storage tank?
16/09/2012	Q:	AMOC have NMP unit, the outlet pipeline of the solvent recovery tower is changed from time to other as a result of corrosion although the acidity of the solvent is adjusted by soda ash and the material is carbon steel.What are the reasons of corrosion in this part of the unit ?
10/09/2012	Q:	How does Vapor/ Liquid ratio at the bottom tray and Reflux to Feed ratio affect stripping quality? What happens when number of trays is increased?	(1)
10/09/2012	Q:	Why do Olefins have a higher Cetane Number than I-Paraffins?	(2)
03/09/2012	Q:	Emergency Depressurization (EDP) System of Hydrocracker Reactors: Our Hydrocraker unit has two emergency depressurization systems : 7 bar/min (100 psi/min) and 21 bar/min (300psi/min). Assuming a pressure of 157 barg when 21bar/min EDP is activated, how long should pressure decrease at a rate 21bar/min? how does depressurization rate vary ?	(1)
23/08/2012	Q:	One of our condensers --using cooling water as coolant media -- is located at elevated position. We can periodically isolate and dismantle this condenser, and upon inspection , the tube side (cooling water side) of this condenser always suffers from signifcant amount of fouling. One of our colleagues suggests we install an "inline centrifugal pump " on the cooling water supply line into this particular exchanger in order to increase the amount of water flowing through condenser's tube hence minimizing the fouling rate. I'm a bit doubtful about this suggestion, as this exchanger receives the cooling water supply from network header, thus the amount of water supplied to the inline pump will still be the same as the amount of water supplied directly to the exchanger without inline pump. An inline pump, in my opinion, will only increase the inlet pressure of cooling water into this particular exchanger. In my opinion, any attempt to increase the discharge valve opening of inline pump cavitate the pump if discharge flow is higher than suction flow received from network header. I would like to hear the opinion from experts about the inline pump of cooling water network. Additional: Thanks for all.. The suggestion from Mr. Banik sounds interesting, and I'm going to evaluate it. Anyway, I'm still curious with the case of inline pump installed in the cooling water supply line of an elevated exchanger, whether it will be able to pull more water supply from network. My premises are : 1. Let's imagine an elevated exchanger is normally supplied with cooling water flow of X m3/hr. 2. The original supply pipe runs on the same elevation with main header of H m , then turning up towards exchanger. 3. If I reconfigure the supply pipe to turning down of H m below main header, then turning up again H m before further going up to reach the exchanger, the pressure profile inside this reconfigured pipe at elevation of H m will still same with pressure profile of original pipe at elevation of H m. 4. Hence flow of water in supply pipe no. 2 and 3 will still same. 5. If I put a pump in lowest section of reconfigured supply pipe no. 3, then the amount of water flowing into pump suction will still same X m3/hr. 6. As centrifugal pump doesn't suck, but it only pushes, so the amount of water pumped will still same X m3/hr. The only different thing is water inlet pressure to exchanger increases hence water outlet pressure from exchanger also increases. 7. Thus operating the pump discharge above X m3/hr will cause transient inventory loss in the pump casing hence cavitation. Do I miss something or make mistakes in my premises above ?	(5)
18/08/2012	Q:	Forum is requested to share its opinion about Gasket Failure events, due to sudden unit shut down, of Column bottom pumps (Operating@400°C) of thermal cracking Units. Is there any requirement that Gasket be replaced after 2 shut downs? How can sudden Gasket failures be prevented. Pls suggest some recommended practice.	(2)
11/08/2012	Q:	Are there any correlations available for finding the pressure drop for limpet coil? Presently we have a reactor with limpet coil. Water is flowing through the limpet coil (made of 3 " pipe). I want to understand the pressure drop calculation for water which is flowing inside the limpet.
07/08/2012	Q:	Our Desalter transformer has got three transformers supplying to individual grids. This step up transformers are facilitated with three outlet tappings with higher ratings. We always run the desalters with same outlet tappings for all three transformers. Is it advisable to run it with different outlet tappings in all three transformers in a desalter? I would like to know electrical feasibility as well as process advantages?	(2)
02/08/2012	Q:	Is there any possibility of runaway reaction in Naphtha hydrotreater? the feed is contains olefins 4 wt% and sulfur around max 2000 ppm.	(2)
31/07/2012	Q:	Want to know Approach to Equilibrium calculation for the naphtha steam reformer of refinery having reformer exit design methane slip of 2.85 mol% dry basis. I have information on calculation of approach to Equilibrium (ATE) if wet base composition at reformer and shift converter is available. In this case steam/gas ratio can be calculated directly based on moles of H2O available. Normally this is not available from lab. They are giving dry analysis at reformer and shift converter outlet. Based on reformer inlet feed flow, steam flow, C/H of feed, recycle gas ratio, inlet pressure, PDI accross reformer and dry composition at exit of reformer and shift converter; is it possible to calculate ATE. If anyone have develop such formula/corelations please share with me so that I can know the catalyst activity and present ATE of reformer and HT shift converter.	(1)
25/07/2012	Q:	Please give us any suggestions for the online cleaning of Vacuum column overhead condensers. The Condensers are suspected to be fouled. What can be the fouling material in the condensers?	(5)
20/07/2012	Q:	Since a turnaround, we are observing temperature crosses on BES heat exchangers (1 shell pass and 2, 4, 6 or 8 tube passes) of our crude distillation prehat train. This translates in correction factors (F) below 0.75. How can this be possible? I thought temperature crosses was possible on pure counter-current heat exchangers only...	(1)
17/07/2012	Q:	In our refinery the tubes of aero-condenser (air-cooled heat exchanger) suffers a remarkable thickness reduction. In January, 2009 we have replaced all the tubes with 2.77 mm thickness. During routine shutdown in October, 2011 we had found that thickness reduced dramatically. We had recorded the lowest thickness of 1.4 mm. At that time we had replaced the bottom layer of one bank which contains that tube. After that one tube of adjacent bank was plugged due to pinhole type leak. A few months later expansion groove of one tube of this bank found corroded. We had taken few sample thickness in June, 2012 and got minimum thickness of 0.9 mm. We found that only rear end tubes are facing significant thickness reduction. Again there is no vent or drain nozzle/plug in the rear header so it is not possible to clean the header properly during shutdown. After investigating we also found that the dosing of corrosion inhibitor and caustic soda suspended for several times due to unavoidable circumstances. My question is what are the main reasons (including dosing interruption) behind the thickness reduction and what is the expected service life of tubes and header of aero-condenser?	(2)
17/07/2012	Q:	Can you tell me how can cleaning the convection tubes of asphalt heater without change the tubes by chemical or any method because we face several problem and bad condition for convection zone & finned tubes which their fins choked with ashes to improve the convection coil heating duty also access for replacing the deteriorated convection zone refractory?	(4)
17/07/2012	Q:	What is the main difference between Accumulation and Over pressure for a relief valve? could anyone explain their importance while sizing a relief valve.	(1)
17/07/2012	Q:	What is the significance of PSV's discharge coefficient? how it will impact on relief valve sizing?
17/07/2012	Q:	Could anyone explain the significance of PSV's %blowdown value that we need to mention when sizing a Pressure Relief Valve.
13/07/2012	Q:	Currently our client makes all jet A-1 fuel from a conventional Merox treating process. There is a project under consideration where hydro-treated jet will be produced through a Hydro-desulphurization Unit. The hydro-treated jet with have anti-oxidant injected into the rundown to storage and will co-mingle with straight run Merox treated jet before entering the same storage tank. Quality assurance/control team has indicated that the jet product needs to be within 0.5 API of each other in the top/middle and bottom sections of the tank. To achieve this tank mixers or a re-circulation system is being considered. Based on API 2003, section 4.5.5 indicates that conventional low-speed propeller mixing has been in use for many years without evidence of problems from static generation. Other important considerations are the co-mingled jet will be stored in fixed roof style tanks. Secondly there is no anti-static additive injected in the tank at this point as it gets added at the truck rack and marine terminal. My questions are: 1) Do other refineries typically use mixers or a recirculation system on jet tanks when co-mingling different types of jet? 2) Do they use a nitrogen blanket system as a safeguard to protect against static buildup in the tank when mixers are applied? 3) Is it true that as long as the jet liquid level in the tank does not drop below the mixer elevation in the tank that there should be no concerns with static buildup in the tank? (With all product tanks on-site the low pump out level is always above the mixer elevation and a low alarm ring in when approaching low pump out.) 4) Is the only concern on start-up or shutdown when a tank is being de-inventoried for maintenance or initially filled?	(1)
12/07/2012	Q:	In our refinery in India after revamping of Hydrocraker unit for increase of Hydrocraker unit load to by 30% than earlier, Fractionator column perfomance seems not stabilize at all. There was minor modification done in fractionator column for increase of 30% load by replacing some earlier tray with high capacity valve trays & providing some packing ring inside column. But we are now facing problem of high column pressure of around 1.45 Kg/cm2 against design of 1.1 Kg/cm2. For that column remains upset most of the time as naphtha is not removed properly. Our product flash point is also found lower than design. To compensate for flash point & removal of naphtha from product we always kept column top temeprature at higher side of 99 0c than design 93 0c. For that our high naphtha production always remains a concern as light end section found upset. It also observed that our column feed inlet temeprature always kept slightly lower @360 0C than design of 374 0c. Presently we bring down the column pressure to nearly design pressure of 1.1 kg/cm2 by running two offgas compressor. Now I just want to know can we now keep column top temeprature 93 0c as per design for less naptha production and also meet the flash point requirment of products by increasing the column feed inlet to design 374 0c.	(3)
11/07/2012	Q:	How long we can operate a Refinery Heater above its design duty keeping all other Heater parameters within design limits? How can a Refinery Heater design duty be reduced without reducing a Refinery Process Unit throughput?	(2)
30/06/2012	Q:	I am trying to build a model to optimize the operation of Crude Desalter and study its effect on Crude Column Overhead Corrosion. The major salts present in Crude are NaCl, MgCl2 & CaCl2; but in our laboratory we measure only Total Salt Content of Crude (before and after Desalter); we do not measure individual salt. My queries are: 1) How the individual salt affect Desalter performance and Crude Overhead corrosion 2) Is it required to measure the individual salt's content in Crude? 3) Can I assume some typical break-up of individual salt (Note that the type of crude we process changes very often).	(1)
29/06/2012	Q:	1. On what design basis would a vendor recommend pilot operated safety valves in a refinery? In our MSQU unit, they are used in RGC and Make-up gas compressor whereas in HDT unit they are used in H.P. separator and Stripper. 2. How are they different from normal spring type PSV?	(2)
27/06/2012	Q:	I'm a process engineer at a CCR unit. Recently we have huge amount af gas formation because of extreme cracking, and RONC is 97 with total delta t equal to 218 deg c,WAIT=509, EDC IS 0.9 LIT/HR without water injection and our water content in platrecycle gas is out of service! I guess there is a chloride/water imbalance, but I want to reduce cracking reactions to increase RONC so can I have your recomendations please?	(2)
23/06/2012	Q:	1. What is the purpose/function of Steam Ejector in Vacuum distillation column and how it works? 2. Why it is placed at the top of column and why not the bottom in refinery? please explain the barometric concept regarding this installation	(2)
20/06/2012	Q:	After replacement of Platformer Catalyst at our CCR-Platforming Unit, pressure of platformer feed at inlet of Packinox Combined Feed Exchanger increased from 6.0 kg/cm2 to 11 kg/cm2 within 2 months that is major constraint of 100% platformer load due to 100% opening of feed control valve & unit load is limited to 90%. Recycle gas pressure is 5.3 kg/cm2 which is normal. It looks that there is plugging in spray bars due to migration of high dust of catalyst after start up. Have anyone experience to solve this type of problem without shut down of platformer unit by changing some parameters like H2/HC ratio, plat unit load etc.We have maintained H/HC ration at 2.5 mole/mole.	(3)
17/06/2012	Q:	Excuse my ignorance; I am neither a chemist, nor an engineer. My question revolves around RVP and RON properties of aklylate and refomrate. From what I have read (obviously not enough), my logic dictates: 1) Unsaturated hydrocarbon molecules are more volatile than that saturated ones, thus will have higher RVP 2) Lighter hydrocarbon molecules are more volatile than longer chains, thus will have a higher RVP. Questions that are driving me nuts: 1) How can a naphtha feed (with more saturated content) going into a catalytic reformation can have a higher RVP, than the resulting reformate which has more aromatics (unsaturated, cyclical = more volitile) content? 2) Why does alkylate which has more saturated molecules than reformate have lower RON and higher RVP? 3) Which is the most important contributor to RVP of a gasoline blendstock - the length of the hydrocarbon chain or it being un/saturation with hydrogen atoms? In other words, which has higher RVP - an unsaturated aromatic benzene molecule or a saturated paraffin pentane?	(4)
17/06/2012	Q:	Excuse my ignorance, I am neither a chemist nor an engineer. I am actually in finance trying to figure out product properties. I am having hard time understanding how is it possible to have a >10psi RVP naphtha feed go into a catalytic reformer, and have a <4psi RVP reformate come out the other end? My logic dictates the following: 1) The lighter the molecule (shorted hydrocarbon chain) the higher the RVP and lower the Octane (and vice versa) 2) Unsaturated molecules are more reactive and therefore will have higher RVP compared to saturated chains of equal carbon atoms. The questions driving me nuts: 1) Why does alkylate which has more saturated content have higher RVP than reformate? 2) Is the reason for akly having lower RON than reformate the fact that its molecules are lighter than in reformate?	(2)
14/06/2012	Q:	We are having plan to do heater online cleaning on one of our cylindrical type heater...our problem are that we have only 3 small observation hole that really not enough to do the online cleaning. We have idea to open the accessing door (man way) at the bottom of the heater and do the online cleaning through this way. Is there any person here that ever open their manway while heater is in operation?I think it is still save enough because the draft inside the heater is negative so there will be no fire will go out through that way.	(2)
13/06/2012	Q:	Crude oil is likely to contain mercury as pure or as compound e.g. dimethylmercury. I would like to know if somebody can provide level of mercury contamination of crude from different sources.	(4)
07/06/2012	Q:	Our recycle gas compressor has a wet sealing system. We are facing frequent problems of seal leak because of which around 2 lube drums of oil is to be topped in the seal oil reservoir. There is negative delta P(-0.2 Kg/cm2) between seal oil & reference gas. I want to ask is only negative delta P signifies the seal leak of RGC.? Does it signify that our reference gas line is choked? A seal oil Overhead tank is provided above a height of 7.5 m above the seal level. Due to this head there should always be a +0.6 delta P between seal oil & reference gas.	(2)
31/05/2012	Q:	Our sulphur plant is two converter, three condenser designed for producing 180 mtpd sulphur with recovery of 96% and downstream TGTU for tail gas recovery. SRU have very frequent choking in condenser III. Deposits are very hard in nature and can not be removed even with hydrojet. This have made the condenser suseptible for leakages. We operate SRU with acid gas from ARU. Amine is used in HCU and FG, LPG aboserbers treating LPG and FG from DCU and MSB, CDU. Solution is MDEA with concentration of 19%. Oil is also observed in amine and filtration system is not very effective. Amine could be source for initiation of problem in MCC but not able to understand the salt which is depositing in the condenser III. What could be the reason of salt deposits in condenser III?	(2)
24/05/2012	Q:	Is it possible to recover heat from the discharge of reciprocating compressor pushing hydrogen from 20 bar to 120 bar? Is there any safety concerns if we use it to preheat DM water for further processing as BFW? Conditions are like this: 3 stage reciprocating compressor, Hydrogen flow : 3.5 tph, Discharge temperature: approximately 130 deg C in each stage, 1stage suction pressure: 20 bar, suction temp: 30 deg C 2nd stage suction pressure: 40 bar, suction temp: 30 deg C 3rd stage suction pressure: 70 bar, suction temp: 30 deg C	(2)
19/05/2012	Q:	We have 2 combustion air blowers for meeting the total air demand in our FCC unit. Main air blower(MAB) is a fixed speed one while auxiliary man air blower(AMAB) contains VFD. Whenever AMAB is started, oil vapours start escaping from its antisurge vent line creating a vapour cloud. Recently the vent line silencer also caught fire because of this. What could be the reason? Is it normal for lube oil to escape from the blower antisurge vent line? There is also a small 3 inch balancing line connecting the blower casing and the blower vent line downstream of its antisurge control valve, is it a good practice to have this line?	(2)
13/05/2012	Q:	Basic differences between AFQRJOS Issue 25 v Issue 26 may please be explained.	(1)
10/05/2012	Q:	Waste Heat Recovery from Low Pressure Saturated Steam We use circulated hot cooling water to cooling our reactors that operate at high temperature, and we use the flash low pressure saturated steam from this system to heat exchangers in our plant. Since the supply and demand is un-balanced, we use air finned condenser to condense the excess flash steam and recover the condensate. During normal operation period, 19,600 kg/hr excess flash steam is condensed at saturated condition(2.86 kg/cm2g, 142 oC). 10.5 MMkcal/hr heat release to atmosphere. We plan to recover this energy using the adsorption chiller technology or other technology. 1. Since the chilled stream we required (-20 oC / -40 oC and -70 oC three grades) may be not suitable from adsorption chiller, we want to know the electrical power recovery from adsorption chiller technology is suitable or not. 2. Is there standard package suitable for the service mentioned above?
04/05/2012	Q:	Post Turn Around in Mar-2010, we have been facing issue of C3/C4 splitter re-boiler fouling. This reboiler is at down stream of LPG merox unit. Simultaneously, high delta P has been observed across LPG sand filter. Recently we have opened up the LP sand filter and found some sticky material showing some of fouling material is being slipped through sand filter (partially by passed at times) and accumulating in reboiler. What could be the reasons of fouling in LPG Merox? Analysis of the sludge collected from the re-boiler was showing mainly HC, 1.5% sodium, ppm levels of silica and iron. More over lead acetate test was carried out at outlet of sand filter and it was negative showing no sulphur being slipped in treated LPG.	(2)
03/05/2012	Q:	We have four pass vertical tube furnace at our hydro-cracker unit. The feed of furnace is catalytically cracked VGO. After turnaround some tubes of all passes at inlet sides turn their color to black. Why this happened?
01/05/2012	Q:	Over past 5 months, we have suffered from increased (by 25%, 30 ton/day) sulfuric acid consumption of our alkylation unit. Now, we doubt increased non-regenerated alkyl sulfate formed by butadiene and / or increased acid soluble oil formed by olefin polymerization. 1. Actually, the butadiene content of C4 olefin feed has widely been ranged from 0.2 to 1.0% according to our lab analysis (thru PONA analysis), and apparently there is no tend that the butadiene content has been increased. Are there any methods to analyze the butadiene content more precisely. It's known that the butadiene makes non-regenerated alkyl sulfate by strong reaction with sulfuric acid and goes to acid phase, which reduces acid concentration. Are there any methods to analyze the alkyl sulfate content in the spent acid? 2. The C4 olefin feed comes from our RFCC unit which uses ZSM-5 as an additive to boost propylene production as other RFCC's. Can ZSM-5 increase the butadiene content in the C4 olefin feed? Actually, we have used ZSM-5 for a long time in the RFCC unit, and recently we changed the brand of ZSM-5 at the end of last year. Can the butadiene content in the C4 olefin feed be much affected by the type and vendor of ZSM-5? 3. Are there any methods to analyze the acid soluble oil content in the spent acid? Can higher iC4/Olefin ratio reduce the acid soluble oil content in the spent acid?	(4)
24/04/2012	Q:	Why give Top Fire Burners in Reformer in some H2 Plants? What is advantage of that?	(3)
21/04/2012	Q:	We have Spent Catalyst inventory. The new catalyst diameter is 1.6 mm and the minimum Spent catalyst diameter is 1 mm. The spent catalyst has about 3wt% carbon. This catalyst was in use for 10 years. After 7 years operation we have added fresh catalyst in it as spent catalyst diameter is decreased. Before selling the spent catalyst, we want to recover fresh catalyst of high diamater. Forum is requested to share its opinion that this is possible by sieving. What are other options? The spent catalyst is very costly.	(1)
20/04/2012	Q:	We are facing a great problem with our pipelines near cooling tower. The water vapor/mist from cooling tower causing corrosion of these pipelines. We are using enamel paints but did not help us much. Please help me to find out a solution to protect the pipelines from the corrosion.	(3)
19/04/2012	Q:	MEG regeneration system. In our plant we have 2 rich MEG tanks that receive MEG/Condensate/Water solution from condensate flash vessel. Last time during pigging activities we receive many sludge from offshore, and now all this sludge is settled down inside Rich MEG tanks. MEG Regeneration package performance rapidly reduced, pumps could not deliver Rich MEG to regen, strainers getting clogged very fast, HC compartment of MEG flash vessel in MEG Regen package filling rapidly. Any ideas how to improve situation with Rich MEG tanks? Maybe clean Rich MEG using hydro-cyclones, or any other equipment? Any links to useful equipment to be installed, or to similar problem anywhere? TQVM in advance.
15/04/2012	Q:	We need to build very small vacuum distillation unit . We cannot find out how many of oil will crack and we cannot evaluate how many m3 of gases will be generated . So our questions: What should be a capacity of vacuum pump in m3 per 1t/h ? How many gases are usually released ? or give examples from your plants.	(2)
13/04/2012	Q:	How does the MCC (metal-catalysed coking) phenomenon happen in a high temperature fired heater in CCR unit, and how to protect?	(1)
12/04/2012	Q:	Please explain to me what the MCC (metal catalyzed coking) in a high temperature equipment of a Naphtha Platforming unit is, and how to prevent it?	(5)
10/04/2012	Q:	When you have a scenario of low sulfur diesel (50 ppm), what is the impact of Diesel viscosity at 40°C on vehicle emissions?	(1)
28/03/2012	Q:	In desalting, does the wash water added to dilute the crude get emulsified with the crude after mixing across a mixing valve or does this remain as free water? Does this wash water have to be considered while we determine the grid KVA requirement i.e. for separation of emulsified water from the crude? Do we always have to add de-emulsifier chemicals in a desalter or can we operate without them?	(1)
28/03/2012	Q:	I have following questions on desalter: What is typical salt content at crude out from 2 stage desalter? Does mixing of crudes result in more salt slip from desalter than design? Does wash water salt content affect the salt removal efficiency (more salt comes out from desalter)? Does inadequate/inefficient demulsifier result in more salt slip from desalter than design?	(4)
22/03/2012	Q:	I am working in DHT Plant diesel hydrotreater unit and face a proplem with Tempered water system that show the Iron High in Tempered Water System and make Troubleshooting we drain the system many time and make chemical cleaning some time it gone ,but after time it come High we Drain the system completely to remove any residual contaminants and Isolate the amine sample coolers for one week and cleaning and Add N-2819M to achieve a molybdate. how do we solve this problem with the Iron and PH. What is the source of the iron coming ??!!	(1)
17/03/2012	Q:	In the refinery sour water stripper, ammonia content is 90 ppm vs deisgn of 50ppm. ph of stripped water is high @9 and this is being reused in desalters as wash water. Due to this, in our CDU overhead system, the boot water pH is reamaining high in the range of 7-7.5 without any injction of neurtraliser. Will this affect the CDU over head system from the point of view of corrosion? And is it required to dose any neutraliser to CDU overhead in this case? Also, is it ok if the desalter wash water has 9 ph?	(3)
16/03/2012	Q:	if we want to reduce the Hydrogen purity in DIESEL HYDROTREATER the current H2 purity is 99.99 fro PSA Unit now we want to take from other plant (Rheniformer units),During hydrogen plant turnaround, PSA’s are not in operation and only the off gas from Rheniformer units, low purity hydrogen, is available. This make-up gas can be used as hydrogen for the DHT to keep it running for the duration of the whole hydrogen plant outage. the hydrogen from PSA : HYDROGEN ------> 99.99 C1------> 0.1 CO + CO2 -----> 20 MAX H2S ----> ZERO HCL < 1 ***** new hydrogen make-up with a reduced purity, coming from Rheniformer units H2 87.5 C1 5.8 C2 3.6 C3 1.6 C4 0.4 C5+ 1.1 - what is the side effect of low purity for all the plants, recycle compressor, make up compressor and the load in addition the make up it is suitable for for such low purity? What is the impact on -Reaction section -Product quality -Recycle compressor?	(3)
14/03/2012	Q:	After commissioning of distillation unit we found that one of the passes of atmospheric furnace has encountered coke formation problem at the end of radiation zone. Is there any solution to continue the distillation process without doing shut down.	(3)
10/03/2012	Q:	We are fractionating the feedstock from natural gas condensates into Naphtha, Kerosene, gas oil and residual stream. The overhead condenser of the first distillation tower suffers from very bad corrosion. The fact is we are not desalting the incoming feed, due to the salt content is 0.5~1.5 ptb based on ASTM-D3230 test result. We only inject the neutralizing and filming amine to the condenser inlet header instead of feed desalting. Upon condenser outlet piping replacement we found a huge amount of sludge sitting inside the old-thin piping. The sludge is >95% Fe. The questions are : 1. Does ASTM D-3230 also reflect the Sulfates salt in the feed stock? Because the water boot contains total S more than total Cl. We worry that Sulfates salt also being hydrolyzed to produce h2SO4 that corrodes the overhead piping. If sulfates salts are also create corrosion problem than how to check the salt content other than Cl salt? 2. Beside chloride content, what are to be checked in the feedstock before deciding to stop desalting? What is the method to check? 3. We plan to install a water wash system in order to prevent sludge deposition and under deposit corrosion. The problem is the condenser pipe header is non balanced type ( E manifold, not C manifold). We are in doubt whether the water will be evenly distributed to all branch to condenser inlets.	(2)
08/03/2012	Q:	What is 'HSS mode' on a heater?	(2)
05/03/2012	Q:	I am currently exploring the possibility of selling Slurry as Carbon Black Feedstock. Although most of the expected qualities of slurry are able to meet the specs required of the Carbon Black Feedstock, the slurry is still high in CCR (~20 wt% in Max LPG mode) versus the required spec of < 10 wt%. For an RFCC, is there any operational adjustment that can be done to meet the CCR specs?	(4)
02/03/2012	Q:	How to keep the pH in neutralization pit neutra? Alkylation unit uses HF and in the neutralization pit we use KOH. The pH is very erratic ranging from 8-14.	(2)
25/02/2012	Q:	Please advice about the operation practice of the reciprocating compressor in order to increase life time of discharge valves in the compressor cylinders. We're operating a Naphtha Hydrotreater - Platformer complex, where reciprocating machines are used as recycle gas compressors in NHT ( 2 Units ) and as Net Gas Compressors ( 2 Units ) in recontact loop of Platformer. A Net Gas Compressor comprises of 2 stages, where first stage is handling gas with 80% purity and the second stage is handling 90% H2 purity. The RG Compressor in NHT handling gas from second stage discharge of Net Gas Compressor. All compressors are equipped with double block-bleed on the suction and discharge piping. These double block-bleed are left open even for stand by machines in order to enable quick start up action. The problem always happens to first stage of stand by Net Gas Compressor. Just 15~30 days after starting, the discharge valves in the cylinder always gets leak and failure. Upon dismantling, we used to find some debris and gum particle in between valve plate and valve stop. Even after suction surge drum cleaning, the problem occurs over and over again. Please advise whether the stand by machine must be isolated and can only be onlined just before starting or can be left online as long as the suction surge drum is free of liquid ? The gum particle is 100% olefins which is suspected due to di-olefin condensation. And the rust is 100% Carbon which is suspected from coke breakthrough from reactor. But why this olefin and coke never cause any problem to the second stage, or even to the first stage of "non stand by" one, as well as no problem so far to the NHT Recycle Gas Compressor ? FYI, the stand by compressor suction line is 20 m distance from non stand by one. How to solve these all these problems?	(3)
15/02/2012	Q:	Can anybody help me to calculate the total gas flow in the riser section of FCCU	(2)
04/02/2012	Q:	In case of pressure gauge what is the specific use of Gauge Saver and Snubber? When do we select Gauge Saver and Snubber? Why is Monoflange with Block and Bleed required for pressure gauges?	(1)
28/01/2012	Q:	In one of our FCC units (Kellog Orthoflow model), we are suffering severe problems of fouling (fines deposition) in the turboexpander. The scheme of the flue gas circuit is: two stage cyclones in the regenerator + Shell Third Stage Separator before turboexpander + 4th Stage Separator (cyclon) to recover flue gas from fines coming from TSS. We have also observed high level of moisture in the fines from 4th Stage Separator (10-15%wt). So we suspect that the fouling of the expander is due a cold point in the flue gas circuit (where flue gas humidity is condensed) or an uncontrolled inlet of water / steam. Has anyone experienced this kind of problems in an FCCU? What could be the potential causes of the severe fouling of the expander?	(2)
23/01/2012	Q:	My question relates to the minimum MAT activity that can be reached in an FCC unit. The main objective in one of our FCC units is maximum middles distillates, and we run this unit at very low severity. The MAT activity of the e-cat is 54-55%wt, with some punctual values of 52-53%wt. We would like to decrease e-cat activity even further, but we have some concerns and doubts about potential problems that could arise, like definitive loss of cracking activity, significant increase in bottoms production, etc. Has anyone experience running and FCC unit at MAT activity below 52-53%wt? What problems could appear with so low MAT activity?	(2)
20/01/2012	Q:	I am currently managing a high pressure water injection triplex pump in a hydro cracking unit. I am plumbed into the unit with my diesel powered pump that has taken place of two electric drive pumps that have failed for undisclosed reasons to me at this time. This particular job was given to my company on short notice and the only information i have received is that this was critical that the unit still perform at at least 50% production and in the event of a failure of the pump I'm operating the best thing I can do is run. If anyone has any experiences with these pumps could you enlighten me to the hazards involved, the use in process, and any down stream side effects on a refinery when they are out of service? Also I was told that within twenty minutes of shut down on their pumps that their unit would cease to function due to salt build up.	(3)
15/01/2012	Q:	My question relaters to the maximum temperature that can be reached in the feed preheater furnace in FCC unit. We operate one of our FCC units in maximum distillates mode and we want to decrease cat/oil to minimum. Currently, we have the following design limits in the feed preheater furnace: 360C (680 F) in the process size and 419C (786F) in the skin points of the furnace tubes. According to a study by our engineering department, temperature in the skin points could be increased to 467C (873F). But our main concern is that an increase in temperature in furnace tubes could cause coking of the feed. Although the feed to the unit is Mild Hydrocracker residue, that has low tendency to coking. Has anyone experience running FCC units at feed preheat temperatures higher that 360C (680F) in process / 419C (786F) in skin point?	(2)
13/01/2012	Q:	Can DIPA will be used for TGTU applications? Who can do basic design of units with DIPA?	(1)
12/01/2012	Q:	This is regarding selection of tank external floating roof to the fixed roof tank for LGO service. Following criteria has been considered for the selection. 1. Capital cost 2. Maintenance cost 3. vapor loss 4. maximum aggregate capacity with in bund 5. Potential risk of loss of life. Now as per above maintenance cost is coming higher in fixed roof tank than floating roof tank for painting. How the painting cost for the fixed roof tank higher compare to floating roof tank? Since both tank will be similar size & capacity. FEED consultant has considered 2.1 million USD higher in fixed roof per 5 year considering 30 year operating life. I want to know general practice for painting of petroleum storage tank.	(1)
06/01/2012	Q:	We have a p.d compressor which takes suction from crude tower reflux receiver the gas composition is c3. c2 c1 little contents of c 4 and c5 but the excessive quantity is h2s gas. K.O vessel collect the liquid (gasoline ) which is sour. How we can save and use this gasoline after removing h2s from it? Any method for separating h2s from gasoline?	(4)
06/01/2012	Q:	We use air to regenerate caustic in our LPG sweetening units. And we send the off gas to heater chamber to decompose hydrocarbon content and bad odor materials in it. We install frame arresters and skin temperature elements in the piping system of these off gas lines for safety consideration. Fuel gas supply to heater burners, we use typical design (i.e. two blocks and one bleed design initiate by ESD of heater), we do not install flame arresters in these lines. We found one plant outside our refinery, they installed flame arresters in fuel gas lines. Since the oxygen content in fuel gas is trace and well controlled and monitored, we do not think flame arrester is necessary. Please advise.	(2)
02/01/2012	Q:	Naptha generated from Hydrocracker is having less then 5 ppm sulfur mainly of marcaptan type and the CRU feed demands for a sulfur level of less then 0.5 ppm. Existing NHDTs are having T'put limitations. Please recommend some other alternative for the removal of the marcaptan sulfurs so that it can be directly routed to the CRU feed pool.	(3)
28/12/2011	Q:	We monitor the VOC emission comes from our VR, Asphalt and MCB(Main Column Bottoms from RFCC) tanks regularly, and found the VOC emission range from several hundreds to several thousands ppmv. These tanks are fixed roof design followed API code. The VOC contains C1, C2 and C3 compounds mainly, and trace sulfur compounds with bad smell. Since we have successful experience of caustic scrubber installed downstream of tanks to remove trace sulfur compound (i.e. H2S). We plan to install a downstream scrubber to improve this situation. Would you please advice which solvent is suitable for this application (for light hydrocarbon removal from vent), or other system can be used?	(2)
26/12/2011	Q:	My question is related to the potential problems that could appear when the feedrate in a FCCU is reduced to the technical minimum (turn-down) or below. - According to your experience, what is the minimum feedrate that can be processed in a FCCU? 60% of nominal feedrate or does anyone operated below this point? - Which are the most likely limitations that could appear in this point? 1. Insufficient gas flow rate to the wet gas compressor? 2. Insufficient pressure or delta P in feed nozzles? Problems to obtain a suitable vaporization? 3. Insufficient coke production to close heat balance? 4. Insufficient liquid-vapour traffic in the main fractionation? 5. Any other limitation?	(2)
26/12/2011	Q:	I'm processing hydrocraker and my question is about steam turbine vibration hunting. This is Recycle gas compressor turbine and its driving force is HP Steam. I've noticed that HP steam Temp. & Press. was little changed after discovered the problem and controlled them. But vibration hunting has still been occurring and I'm looking for another source of hunting. Could you please advise about this if anything you have a similar experience or knowledge?	(1)
25/12/2011	Q:	Normally Overflash is 3-5 Vol% of CDU Feed. How Overflash may be calculated so that the formula may be incorporated in DCS for optimum Heater Operation resulting in energy saving. Please share some reference for information & study please.	(2)
22/12/2011	Q:	I am operating Pre-topping column at 2.4 kg/cm2 and 118 C . M.P. steam at 12 kg/cm2 at 550 kg/hr is fed as stripping steam. Gasoline reflux at 28 m3/hr and 13m3/hr of gasoline is taken out of overhead condenser. How do I calculate the dew point of overhead vapors?	(3)
21/12/2011	Q:	We have a potential gas plant to process gas at 900psig vol is 250 mmscfd with 8% CO2 with no H2S. Can someone advise me what process to use Membrane or Solvent. Will physical solvent be better or DEA, MDEA for producing pipeline quality gas ie 2% CO2.
21/12/2011	Q:	My question is related with high sulphur content in LPG from crude distillation. In one of our refineries we have detected high sulphur content in LPG from crude distillation. The scheme is as follows: Crude distillation - Gas concentration unit - Debutanizer - Amine absorber - Merox extractive. The high S content is mainly due to high dimethylsulphide (DMS) and dimethyldisulphide (DMDS). We measure high DMS and DMDS both at the entry and outlet of the amine absorber and LPG Merox. We have also seen some unexpected behaviour with these species: DMDS increase through the amine plant (DMDS higher in the outlet than in the inlet) and decrease in the Merox unit. The same with DMS. But sometimes we have also observe that DMDS decrease in the amine plant (??) My questions are: - What could be the origin of DMS and DMDS (synthetic / heavy crudes, slops processing...)?. DMDS could be re-entry sulphur in Merox, but we have observe it in the inlet of amines and Merox (It seems that both compounds come with the crude) - Could be DMDS come from oxidation of methylmercaptan in the topping, Gascon or amines (where there is not Merox catalyst) if oxygen is present in the LPG? - If DMDS is in the crude, according to its boiling point it should end in the heavy light / heavy naphtha. Has anyone observe high DMDS in LPG in his refinery? - Could DMS and DMDS increase or decrease in the amine plant or Merox? (I do not think so). Are these compunds partially soluble in NaOH or could be removed in the sand filter? - DMDS could also come from the circulating NaOH in Merox plant, if quality is not good (high concentratrion of disulphide in NaOH)? What is the normal or recomended concentration of disulphides in regenerated NaOH? - What could be the alternatives to remove these compounds? I expect that nothing can be done in amine / Merox, these compounds are not reactive.	(3)
14/12/2011	Q:	There has been a technology of corra coatings in Pumps impeller which reduce the friction and ultimately the power consumption is reduced. What are the proven practical benefits and who are the vendors?	(1)
13/12/2011	Q:	My question is related with a problem of copper corrosion strip failure (ASTM-D130) in gasoline. We have two tanks of off-spec gasoline: - Copper strip corrosion 3B; SH2=0ppm, mercaptans = 9ppm. Does not improve copper strip corrosion test adding corrosion inhibitor - Copper strip corrosion 2C; SH2=0ppm, mercaptans = 5ppm. Improves copper strip corrosion test adding corrosion inhibitor My questions are: - Could the low level of mercaptans present cause a failure in copper corrosion strip? - Could a NaOH carryover from the Merox unit cause a failure in copper corrosion test? - Any other sulfur compound, besides SH2 and mercaptans, could cause this copper strip corrosion test failure? - Does anyone know any commercial additive for mercaptan removal that could be useful for this problem?	(5)
12/12/2011	Q:	We use two block valves with one blind for isolation at boundary limit of each process unit in our refinery. Gate valve is selected for block valve mainly. For hydrogen system, we select one ball valve (Orbit Valve) installed at main header side, and one gate valve at process side for block valve service. Would you please advice if Rising Stem Ball Valve is better for hydrogen system, and what condition should be used?	(1)
10/12/2011	Q:	Our Vacuum gas oil hydrotreater unit is operating at 125 KBPSD. We are processing feed, HAGO, HVGO. LVGO from crude unit and HCGO from Coker unit.We are having 24 filter for removing contaminants including one backwash filter.Our filter dp during steady state operation is 0.7 to 1.0 bar. We often face problem of high pressure drop of 3.5 to 4 barduring crude unit HVGO pump changeover or during taking of HVGO exchanger in line.In crude unit there are 2 HVGO pump one running and other standby with total flow rated capacity of 1770 M3/Hr.Running capacity 1650 including pump around,IR and product HVGO to our unit.Normally we consume approx 440 to 470 M3/Hr HVGO during steady state. I am not able to find out the root cause for high dp across feed filter during such activity in crude. This results in throughput reduction in ZVGOHT unit. Please suggest the possible cause for increase in filter dp	(3)
10/12/2011	Q:	I am currently working in Naphtha hydro treater, In our naphtha hydro treater stripper and Splitter both column is there, stripper is for removal of h2s and splitter is for removal light naphtha. So can you tell us the what is the difference between Stripper and Splitter? Additional info:- Stripper and Splitter both are having reboiler for temperature controller.	(2)
07/12/2011	Q:	We are operating vacuum gas oil hydrotreater unit after shutdown at 125 KBPSD. At 125 KBPSD we checked the vibration of Combined feed heater connected lines and tubes. Same we checked in product fractionator heater. But after 2 to 3 days it was observed that product fractionator heater pass 1 convection to radiation vibration is significant. We reduced the throughput to 121 KBPSd. But still vibration persists. Can anybody guide me about sudden increase in vibration?	(1)
06/12/2011	Q:	Could you please guide me on ther Naphtha-expansion calculation i.e. the calculation procedure for naphtha, liquid to vapour at various temperatures
06/12/2011	Q:	In my refinery we have Diesel Hydrotreater unit which has undergone an emergency shutdown, following the tripping of recycle gas compressor. The compressor was tripped off due to the false ESD activation of high level switch on the suction K.O drum. Recycle compressor started up and started increasing the reactor inlet temperature . During the DHT unit start up, higher hydrogen consumption of 1.5 vs normal 1.0 MMSCFH and lower system pressure of 620 vs normal of 670 PSIG was observed. My question is where is go the higher hydrogen consumption?	(4)
25/11/2011	Q:	Swivel joints are used in the roof drain line of the floating roof tank. In our refinery we usually replace these during repair work on the tank. In that case the life of the joints is about 10-15 years. But I want to use these joints again. There is no testing facility for these joints. There are 20 swivel joints in each tank so a good amount of money is required to replace them. My questions are: 1. Is it a good decision to replace the joints after 10-15 years? 2. How should we test the joints if we wish to use them again?	(1)
24/11/2011	Q:	Currently, I am working on proposal of Ammonia flare system project for one of the client based in GCC. I have an experience on the HC flare system. There are 2 flare header coming to the ammonia flare system as below. 1. PSV discharge having liquid + gas stream 2. PSV discharge having only Gas stream The PSV discharge having liquid + gaseous stream will be transferred to the Flash tank for separation of liquid & gas stream. The separated liquid stream will be sent to ammonia storage tank & Gas stream connect with the main gas flare header & transferred to Ammonia KOD. I have following question regarding the system, may u consider silly also 1.Why water seal drum is not considered to in this design? HC flare system have a separate KOD & water seal drum for adequate protection against flash back form the flare tip while Ammonia have only KOD integral with flare stack. 2.What is reason for providing the steam tracing to the flash tank?	(1)
23/11/2011	Q:	Theoretically, what minimum flow requirement shuld be specified for selection of Recycle Valve with respect to compensate for drop in suction pressure, provided my maximum flow through the RC valve is known?	(2)
23/11/2011	Q:	What is the safe spill control procedure of the 98% sulphuric acid inside the plant for environment management and safety management? Maximum quantity stored is 200Lit with dyke, but no secondary disposal means from dyke.	(1)
22/11/2011	Q:	When dumping spent catalyst from a semi-regen reformer without a carbon burn: Is the catalyst usually passivated? What is the target LEL for stripping? What is the maximum bed temperature?	(1)
21/11/2011	Q:	We are having a NATCO EDD desalter in one of our crude units and of late we are facing reduced desalting. The outlet salts have been consistently above 1 ptb and sometimes we find inlet and outlet salts to be almost equal. we tried to balance the salt removal across the desalter and tried to do a chloride balance across the crude/prefrac columns, but unable to close the material balance.	(4)
19/11/2011	Q:	How does one calculate amine loading for an amine absorber?	(3)
18/11/2011	Q:	Regarding the LPG Sulfrex Unit in RFCC, I have some questions. We experience the increase of C4 sulfur content last Saturday (11/12) by the forming of the amine absorber(T-20701). a brief unit description is bottom of this writing: sulfur content of C4 goes up from 1~3 ppm to 16~18 ppm Thus we replace the caustic of prewash drum(D-20702) & Extractor(T-20702). But the sulfur content of C4 is not decreased. Investigating the cause of amine absorber foaming, we find the significant change of amine absorber condition. First is difference of amine inlet/outlet flow. Inlet lean amine flow is +6~8 m3/hr higher than outlet amine flow in amine absorber. There is amine carry over to overhead LPG side in amine absorber. Second is LPG carry under to rich amine side in amine absorber. Rich amine goes with LPG to amine flash drum before amine regenerator. So the pressure of amine flash drum sometimes rise to almost drum design pressure. Finally we replace the activated carbon filer in rich amine side, but there is nothing wrong in amine quality. After that, Inlet and outlet amine flow is same and the delta P of amine absorber increase to normal condition We wonder why LPG absorber goes back to the normal condition after replacement of rich amine filter. Q1. Could you explain the reason for this phenomenon? Q2. If amine quality is main cause, could you recommend the new guide of amine or other countermeasure? Brief LPG Sulfrex unit description : LPG feed from R2R GAS Recovery unit is sent to the Amine absorber(T-20701). Hydrogen sulfide is removed by counter current of amine solution and the LPG leaves the top of the column and flows into the amine settler D-20701 and rich amine is leaves the bottom of the absorber to amine regenerator. LPG flows into the caustic prewash drum D-20702 for removal the last traces of H2S not removed in the amine absorber. D-20703 is Caustic Settler. The settler drum allows to separate and return the entrained caustic to the oxidizer T-20703	(1)
18/11/2011	Q:	We are looking for information about cyclic catalytic reforming units and the conversion of semiregeneratives units into cyclic units. Would be useful to know what refineries in the world have revamped a SR UNIT to cyclic unit. Capital cost are prohibited? What would have to be the size of the new fourth reactor?	(1)
17/11/2011	Q:	On distillation unit, we have crude surge drum at the beginning of the unit. This surge drum has PZV open to the crude column flash zone. What is the effect if the PZV open for releasing high pressure to the flash zone? And how about transfer this PZV to open on the manifold of the crude tanks?	(2)
17/11/2011	Q:	How to calculate the SOx and NOx emission rate in a heater stack?	(2)
11/11/2011	Q:	We find the crude heater tubes started slightly bowing towards the burner inside the radiation zone. The investigation drives my mind over the below written questions... 1. What can be the maximum height of the Fired heater's radiation zone (or) the maximum tube height allowed inside the radiation zone (vertical coil type) as per standard? 2. What is the efficient ratio which can be achieved between the radiation:convectional zone heat transfer(in percentage)? Its a balanced type heater and we could heat the combustion air up to 275 C max? 3. We use P9 material tubes inside the furnace (cylindrical-twin zone). We are puzzled as to why the bowing is towards the burner side? Why not towards the side and backwards? 4. What is the maximum pressure drop across the burners allowed? As we go increasing the throughput in varying the Fuel oil and Fuel gas burning, the skin temperature response in all the section of the heater is not uniform. So the heat flux variance is also expected. I would like to know the methods available to find the heat flux variance inside the radiation zone. 5. The burners (Low NOx/SOx) used are stretching over the design sometimes due to the lower inlet temperatures. Flue gas recirculation is also included in the design. What can be the problem when a burner is running over the design limits? We have oxygen, CO, NOx/SOx analysers but they don't seem to be reliable most of the time.	(3)
09/11/2011	Q:	I am have two diesel hydrotreaters in my refinery. One (35bar) is producing Euro III diesel with a sulfur specification of 350 ppm maximum and other (100bar) producing Euro IV diesel with a specification of 50 ppm sulfur. Now I would like to know what type of catalyst to be used. Co-Mo catalyst or Ni-Mo? Moreover kindly explain the basis for choosing the Catalyst-type.	(3)
30/10/2011	Q:	With regard to application of catalysts in Isomerisation process, I would like to know about the overall comparison between tradition catalyst i.e. Aluminium Chloride and novel catalysts based on platinium element. In point of view of economical criteria which case has been suggested?	(3)
29/10/2011	Q:	In a fixed bed platforming unit employing bimetallic platinum rhenium UOP R-56 catalyst operating at 12 kg/cm2 pressure, what is the average catalyst life expected (in m3 naphtha per Kg of catalyst) provided the cycle runs ideally with no sulphur water, metal etc.upsets at average rundown severity of 90 RONC with end of run temperature of 510C?	(4)
28/10/2011	Q:	How do we maintain the purity of Recycle hydrogen in a Diesel Hydrotreating unit?	(5)
27/10/2011	Q:	I am a student of the energy operations class st Lake Area Tech. Our goal is to improve the purity of our ethanol from 95% to a much higher purity. We are using a 2in x 60in copper pipe instead of the 5in x 17in steel pipe for our distillation column, and trying to pack it with Raschig rings instead of the marbles the last class used. 1. I am having trouble determining the packing height needed, or the amount of Raschig rings that need to be used. (The volume of the tower is roughly 4 Liters) 2. Does there need to be empty space in between the rings or should they be just dumped in randomly? 3. Where in the column should the reflux outlet be placed for maximum return to the base of the still? Any answer to any question would be GREATLY appreciated! Keep in mind I am not a chemical engineer, but I am familiar with most of the theories and some of the math such as HETP, plates vs packing, random vs structured and so on.	(1)
26/10/2011	Q:	The following query is regarding the MEG solution circulation system in Propylene Recovery Unit (PRU). PRU unit has a vent condenser at the downstream of DeEthaniser. Vent condenser typically operates at 3 ~5 degC. 30% MEG solution in DM water is used as a refrigerant. Metallurgy followed in this MEG solution circulation system is carbon steel. During start-up, if DM water is received in the circulation system (which is having a surge drum - with nitrogen blanketed), is there a possibility of corrosion due to DM water contacting directly with carbon steel? Is it a good idea to maintain slight nitrogen atmosphere (may be around 50 mmWC of nitrogen pressure) in the surge vessel before making up DM water? How best this MEG solution system can be commissioned avoiding corrosion?	(2)
22/10/2011	Q:	I am currently working in the Hydrotreater. My question is if recycle gas compressor trips and our feed pumps remain running due to faulty logic, what will happen to reactor? And can we run the feed pump for cooling of reactor without recycle gas?	(5)
21/10/2011	Q:	Remote Isolation Valve (RIV) Fire-Protection Requirement We use pneumatic RIVs in our system for shut-off operation during emergency condition (for example, fire). Two valve types selected used in these services, one is Ball valve, and the other is Triple Eccentric Butterfly valve. All air failure to close (AFC) design. Since AFC design, we didn’t make specific fire protection requirement for actuators of RIVs. There is a revamp project, licenser request actuators and instruments of RIVs shall be protected by thermal insulated boxes. According to information from vendors, the box is heavy and difficult to maintain. Do we need fire-proof actuator even AFC design?	(1)
21/10/2011	Q:	Valve Type Selected Used in Emergency Depressurization (EDP) System We use ball type valves for EDP system in our existing hydro-treating and hydro-cracking units. And they work well. Now, we want to select Triple Eccentric Butterfly valve for EDP system in our new project. Please advise.	(2)
12/10/2011	Q:	In our Butadiene plant we are using ACN+Ethanol+Water(tertiary) solvent. IN WASTE GAS RECOVERY EXCHANGER we observed there is a formation of ammonia salt.Tube side is HC(EA+VA+BD+small trces of ACN). Due to corrosion regularly the exchanger is leaking. Shell side is Brine (water+MEG). The exchanger is operated at around 10-15 degree celsius. Even bottom pump casing is damaged because of that material. Please suggest a solution.	(1)
12/10/2011	Q:	Are there any rules of thumb for the upper limit for basic nitrogen content and/or feed density in the VGO before hydrotreating is recommended/necessary when the VGO is going to be used as FCC feed ?	(1)
22/09/2011	Q:	Could someone explain the significance of the H2 to hydrocarbon ratio in Naphtha reactors please? What is the effect on reactions when you increase / decrease the ratio and are there any other effects?
19/09/2011	Q:	How can we simulate Hydrotreater in Hysys? Do we have to add reaction for Hydrotreater to simulate? If yes, what are the kinetics of the reaction or where can I find such information?	(1)
16/09/2011	Q:	What is the best way to treat waste water that contains high sulfinol to discharge level?	(2)
16/09/2011	Q:	For the improvement of run length, we would like to replace about 1/3 of total radiation tubes of 9 Cr 1 Mo with SS 347 H. 1) How much % improvement in runlength is feasible between two spalling? 2) How much max TMT is allowed in such combination of radiation tubes? 3) What will be Spalling temp limit? 4) What precaution to be taken care for welding of two dissimilar joints?
16/09/2011	Q:	I have a question about DeSOx Unit of RFCC Our plant has a DeSOx unit that removes SOx and spent Cat’ (=dust) in Regenerator flue gas to meet environment standard. After removing SOx and spent Cat’ by Mg(OH)2 solution, the waste water that includes suspended solid like spent cat’ is removed through filter press. Filter press is dual type. When one is working, the other is stand-by. (Running time :18~30hr) Because operation time of the two filter presses is not fixed and unknown, the cleaning man has to stay on or near the filter press to clean it, when switching. So I want to ask: 1. How do you treat resulting waste water to meet environment regulation? 2. If you use filter press, what is the best way of managing it?	(3)
08/09/2011	Q:	A bitumen tank that has not been cleaned in 20 years required cleaning, our concern is Phosphoric/fire hazard. How can we control that? Will degreasing, organic salt (removal of rust) then KmNo4 final rinse help? During fe removal, it will have h2s; will that be a concern? KmNo4 at 1% solution; is that sufficient to remove all the phosphoric?	(3)
05/09/2011	Q:	Can anyone give me a tip off on how to reduce high COD between 200,000-500,000 from sulfenol/amine waste in the gas plant.	(3)
20/08/2011	Q:	What are the processes of enhancing paraxylene content in naptha?	(2)
17/08/2011	Q:	Recently we have a failure ( leak ) of RCSP (Regenerated catalyst stand pipe) bellow. Following are the details of the bellow: Bellow type : Two ply double elementpurgeless bellow with with pentographic linkage design. Size: Element Length: 646mm(compressed), 7 convolutions each, MOC: Inconel 625LCF, pipe OD: 1982mm, bellow is providede with equalising & leak detection arrangement, packed with cerawool with wore wire mesh&silica cloth. Operating temp: 343deg cent, (510 design) with axial expansion 210mm. Leak detail: leak observed from 2nd crest of the top bellow element (inlet end) at approx 11 'o' clock position looking from outlet end. Opening (crack) was of 3.5" length We are in the process of analysing the failure, kindly let us know various reasons for failure ?	(1)
15/08/2011	Q:	What is the impact on olefins and isobutane production when slurry oil is recycled?	(1)
15/08/2011	Q:	Does someone have experience of all feed pump cavitation and subsequently unit trip while changing over the feed pump from one to another. Or what are the probable reasons of feed pump cavitation while doing pump change over?	(1)
09/08/2011	Q:	What are current views on twisted tube heat exchanger configurations in refineries, particularly in comparison with conventional shell and tube configurations?	(7)
05/08/2011	Q:	In our refinery, we are running 5 no of Air Compressors (of Elliott make) to cater the Plant Air and Instrument Air requirement of the entire refinery. The setup is as follows: 4 nos of Big compressors of capacity 6040 NM3/hr each and 1 no of Small compressor of having 3020 NM3/hr and design pressure of 8.3 kg/cm2 All the compressors' discharge pressures are set at more or less equal pressure of ~7.2 kg/cm2. Instrument Air pressure is maintained at ~5.8 kg/cm2 Of the 4 big compressors, 2 compressors are older by 12--15 years. Now the question is the Suction C/V (IGV) of Old compressors is opening only 50 to 70% even if the demand is more. C/V stroke checked and observed to OK. What could be the reason for less opening of IGV?	(2)
05/08/2011	Q:	A 8m3/hr & 35m H pump is available with us and we are using for pumping organic residues which is the regular operation carried out in day today operation. Now we are planning to use the same pump for recirculation purpose for about 3 to 4 hrs/shift.But the recirculation back to the storage vessel pipe static head is only ~ 6 - 8 meters, but the original design of the pump is 35 m head. I have checked the pump curve & found that by reducing the actual head from 35 m to ~ 8 m , flowrate will increase. So accordingly I have sized the recirculation pipe size to the recommended velocity. Should this solve the problem? What other consequences might it have?	(3)
28/07/2011	Q:	I have some question about R2R(RFCC) VOV (Variable orifice valve) in #2 Regenerator Flue Gas Duct . Recently we experienced the hot spot of VOV Body. Its temperature by thermo vision is 590 ‘C. So we concerned about damage of VOV body Refractory. Could you suggest the possible cause or countermeasure for this problem? (steam jacketing?) P.S. In 2010 TA we plugged 5 orifice hole of total 10 orifice hole. And the half of VOD Disc is eroded. And current VOV opening is 65% and Delta P is 1.2 kg/cm2 G.	(2)
26/07/2011	Q:	I'm getting ahead of work on emission-reducing additives in diesel engines, I want to know experiences about the use of additives based on polyisobutylene, some information reports levels of NOx emissions reduction close to 25% and Reduction of particulate matter of 47%. Does someone have some information about this topic to help me?
25/07/2011	Q:	Lately we have been experienced frequent trip of Furnace in DHDS, we get positive draft and zero oxygen where this causes furnace to trip. Root cause?	(3)
25/07/2011	Q:	We have a crude unit with a double drum overhead system. The first drum collects the HC condensed from the hot section exchangers and returns all condensed HC as reflux to the crude tower. The vapor from the first drum (reflux drum) is sent to the cold section where all the HC and water is condensed and collected in the second drum (distillate drum). Any noncondensible is sent to gas recovery section. From the design conception, water should only condense on the second drum, however, we are seeing condensation (and corrosion) in the reflux drums as well as the overhead vapor exchanges heat from a relatively cold crude. In addition, we have seen signs of salt deposition and eventual corrosion in the other exchangers where water dew point is very unlikely. Given these problems in the hot section exchangers, what can we do to address and prolong the life of our overhead condensers? Please take note that the water wash, filming inhibitor and organic neutralizers are only added in the cold section exchangers going to the distillate drum.	(3)
21/07/2011	Q:	In our Vacuum Distillation Unit we have a vacuum system consisting of overhead water coolers, two ejectors with condensers and a liquid ring vacuum pump. During the summer time when the cooling water to overhead coolers and ejector’s condensers increase above 23C we observe increased pressure on the top of the vacuum column to approx 5-6 Kpa (from 3 Kpa) which is of course logical. In this situation when we want to increase the temp to the vacuum column in order to maximize yields , the pressure will increase too and the result is quite opposite. The significant fluctuation of temp of cooling water (sometimes during the day it is about 5C) makes it also impossible to optimize yields from the vacuum column. Please advise what to do in this situation in respect to our plant, how we can keep pressure steady and low , how to improve yields in this circumstances from the vacuum column. Maybe you have similar problems and please write how you deal with that. Some recommended literature/web sites on this subject would be very helpful too.	(4)
16/07/2011	Q:	Currently the slop wax from the our vacuum distillation unit is directed outside the plant. Do you know some solutions regarding recycling this low-margin product back to the process? I have read about directing it to the feed of CDU or with the long residue to the vacuum furnace or directly from the vacuum column to the evaporation section of the vacuum column (is it safe and not coke the bed?) . Our plant is combined CDU and VDU , internals of the vacuum columns are structured packings Mellapack. I wonder what your recommendations are on this subject, maybe some advantages and disadvantages of specific solutions.	(4)
11/07/2011	Q:	What are the basic differences, advantages and disadvantages, between controller using 4ma-20ma system and 0-10v system.	(1)
07/07/2011	Q:	We have a CDU with (a preflash tower), the top product in which naphtha vapors are cooled down using a series of horizontal air coolers (vertical air flow). A corrosion problem was noted days ago in some tubes, knowing that this air cooler is only 6 years old in service while another series of air coolers used for the same object but with another CDU with (a preflash drum) for 23 years now and they work well, at least better than the stated one. We use Ammonia as demulsifiers int desalter in both units.	(3)
06/07/2011	Q:	In template Hydrocracker, Aspen Hysys Refining (formerly RefSYS), what must I modify because that template does not accept the naphtha feed? It always says error "One or more feeds not solved". If I put 0.3% wt for a heavy component, Hysys will adjust it to 48% and change the feed character. How can I fix that error?	(1)
30/06/2011	Q:	Has anyone had trouble with "one or more feed not solved" on RefSys, template Hydrocracker? I need to simulate a HDS unit for cat cracked naphtha, but I always have problem with the feed. The default feed type in Library (Feed Data tab) is too heavy for naphtha, and it not contains C4, C5. What should I do to solve that problem? How can I create another Feed Type instead of that default? I made a chromatography for my feed, but when I modified lump weight percents conform my chromatography, it didn't work.
27/06/2011	Q:	Can somebody tell me what is the shelf life of carbon disulphide CS2 chemical?
26/06/2011	Q:	While working as an inspection engineer I faced some questions which answers are not clear to me. Please help me in this regard: 1. We are taking thickness record as per previous locations. I want to know how the locations are selected to record thickness on the pipe lines. 2. Sometimes we found higher thickness from the previous record. In this condition we recheck the thickness. Is there any alternative or tolerance limit? 3. How the retiring thickness of the pipe line is calculated? 4. Is there any suggestion while inspection of pipe line commenced?	(3)
22/06/2011	Q:	This is my NHT unit: 1 reactor with 1 fixed bed, volum 27m3, catalyst S-120 from UOP. 3 stage compressor: 4bar--> 10.5 bar--> 25 bar--> 43 bar. Splitter 52 trays Stripper 25 sieves trays. If I change the feed for NHT unit from the SR naphtha with 100ppm wtS to the SR naphtha with 1230 ppm wt S ( because I changed the crude oil for DAV), what should I do to maintain the specification product for Platforming CCR (0.5 ppm S, 0.5 ppm N). And if I would like to revamp this unit for a product with 0.1 ppm wt S, what should I do?	(2)
22/06/2011	Q:	Recently it was observed that the some of the radiation tubes of our atmospheric distillation heater were deformed. The tubes have been in operation for almost 30 years. Some of the tubes (specially at the middle section) deformed to the center of the furnace. Some deformed laterally to the adjacent tube. I want to know the possible reasons behind the phenomenon. Also please advise me what is the standard of replacement of the tubes in this mentioned condition.	(3)
20/06/2011	Q:	We need to revamp our NHT. Before revamp: 23500 bpd SR Naphtha 100ppm S, Naphtha product for CCR feed has 0.5 wt ppm. After revamp: 30 000 bpd (90% vol SR Naphtha, 10 % coker Naphtha) with 0.1 wt ppm in product for our new regulation. We have 1 reactor (R1) with 1 bed of catalyst (18m3 catalyst in 27m3 reactor). I think we should install one more reactor. But I don't know which case is better between: Case 1: Feed-R1-R2-Stripper-splitter and Case 2: Feed-R1-Stripper-Splitter-R2 (recycle bottom product from splitter to R2)-R1. May you have any advice for our revamp? Additional info: Of course that Case 1 is traditional process revamp. But I have just read an article from Chevron, about their process revamp as Case 2. It called SSRS Isocraking (single stage reverse sequencing), licensed by Chevron Lummus Global. In that article, they said that the revamped unit can run at 133% of original design capacity with the existing recycle gas compressor. I think in case 2, R2 is existent reactor and R1 is new one (because R1's volume needs to be bigger than R2) This article named "Hydroprocessing upgrades to meet changing fuels requirement", Jay Parekh and Harjeet Virdi. Unfortunately, It's not for NHT, It's Hydrocracking. Is it O.K if I use Case 2 for my NHT revamp?	(9)
14/06/2011	Q:	What are the effects of decreasing the coke drum cycle time from 24 hrs to 20 or 18Hrs on WGC capacity?	(4)
11/06/2011	Q:	How can we separate catalyst fines (up to 74 micron size) from RFCCU slurry oil at around 90 - 100 Deg C temperature? Can it be done through filtration and what will be the type of filters, type of backwash required etc?	(7)
04/06/2011	Q:	CDU overhead system To provide a CDU with top reflux there are several configurations. The two main ones are as follows Configuration 1: Double condensation Configuration 2: Top pumparound In configuration 1, total overhead vapors are condensed in two condensers in series. In the first condenser part of vapor equal to the required top reflux is condensed, water is separated and hydrocarbon liquid is returned to column as top reflux. The remained vapors (this includes the top product plus non condensable vapors) is routed to the second condenser. In configuration 2, the top reflux is provided by a top pumparound and the overhead vapors ( (this includes ONLY the top product plus non condensable vapors) are condensed in a condenser and no liquid is returned to the CDU. For a refinery with capacity above 100,000 bpd what configuration is recommended? Considering in both case energy is used in top/feed exchangers network. Can Heat Integration cause to use one of these configurations? We know in configuration 2 some more stages are needed as we have added one more pumparound! Additional: Thank you for the answers! Don't you think, the double condensation configuration results in lower flowrate in top section? When I can remove water in the first condenser, why not to return the reflux in lower temperature! furthermore I think thermodynamically, configuration 1 is better than configuration 2. As Ralph stated, the latter also needs at least two/three more trays for top pumparound! What I am not sure is energy saving! it is believed that configuration 2 results in a better heat integration.	(2)
30/05/2011	Q:	Some steam Jet ejectors are designed with a nozzle extension. What is the role of this extension in the ejector performance? During the last shutdown of our VDU, we noticed that the first (and largest) ejector steam nozzle was mounted without such an extension. How could this impact on the ejector performance?	(1)
29/05/2011	Q:	We are facing frequent fouling in our falling film evaporators because of tar content in our feed. Currently we down our plant once in 3 months for cleaning these evaporators. Can anyone suggest the best method in reducing this fouling?? how about tube inserts ?? or do we have any advance technology in heat transfer for reducing fouling?? I know twisted tubes can reduce fouling but can we use for falling film evaporator??	(4)
26/05/2011	Q:	We are looking for a simple static bed packed with some adsorbants to remove minor impurities of Mercaptons and Ammonia from an LPG stream. We can use a water trickling Absorber for NH3 removal as suggested by Eric. But we need a similar simple solution like a Sulphur Trap for Mercaptons. One Chinese company claims to have a packed Adsorber.	(1)
25/05/2011	Q:	One of our clients using LPG as feedstock for Isobutylene extraction is having problems with impurities such as NH3 and RSH though in pppm levels in Feed. How can these be removed?	(2)
24/05/2011	Q:	In the double wall refrigerated storage tank (both tanks are steel tanks) a) Does Fire case of liquid boling is applicable due to process vapor acts as insulation (in the annulus)? b) Is it required to protect the outer tank by water curtain since its integrity will be lost due to fire?
23/05/2011	Q:	Is there any conversion factor between Nm3/hr anf m3/hr? I am confused because gas flowrate are measured in KNm3/hr while liquified gas flowrate are measured in m3/hr.	(3)
23/05/2011	Q:	We are producing about 3m3/hr of lpg to storage. the temperature and pressure in the overhead drum are 31C and 8.5 kg respectively. at same time consuming about 2.94KNm3/hr of lpg in our heater. the pressure of the lpg going to heater is about 1.02kg. What is my net loss or gain of lpg?	(1)
23/05/2011	Q:	Recently we are facing a severe problem of frequent RGC trip in our Hydrocraker plant. Till now RGC tripped 10 times in last 3months. Now the problem is that in all these trips not a single trip logic actuated, but only the alarm received as compressor trip from governor. So we are clueless. We have HP steam driven RGC. At present we are bypassing trip lever &mechanical overspeed suspecting problem in that part.It was also observed that most of the trip occured at when governor speed incresed to 11,500 rpm.In last few occasion of trip it was also observed that turbine outboard bearing Outlet Lube oil temperature suddenly started shoot up just before RGC trip. After byassing the trip lever assembly RGC was not tripped till now,but as trubine outlet bearing lube oil temperature increased at speed 11,500,we have reduce the rpm to 11,00 and thus we are not able to run Hydrocraker unit in full capacity.From process point of view, all parameters are within normal operational range like previous normal RGC running condition.Can any one give any idea what may be the basic problem of frequent RGC trip? Also,will it be safe to run RGC by bypassing trip lever assembly & Mechanical overspeed?	(5)
21/05/2011	Q:	Can someone guide me on how to carry out the sizing of Liquid separator (vessel size calculation when a coalescing media/screen/mesh pad is used) when there is a coalescing media present in the separator ?	(1)
18/05/2011	Q:	Following is a brief overview of the problem we are currently facing at our Diesel Max Unit (Mild Hydrocracking Unit), Incident: Our Diesel Max unit reactor having four beds, is equipped with three Quenches. MV for the 3rd Quench Gas Flow Valve started to increase and reached to a maximum value of 100% within 08 hrs. With increase in the MV opening of this Quench valve, flow across the valve remained consistent initially at around 4700 - 5000 Nm³/hr and then gradually started to decrease to a much lower value of 3,100 Nm³/hr at 100% opening at DCS at 70% Unit load. Observations: Field observation was taken for the Quench valve and maximum opening found was 85% from field. Field observation for any abnormal sound across the NRV was checked and found normal. Similarly, Pressure drop across the reactor in the field on local PIs and across DPT,Delta T and Radial Spread across the reactor beds is observed and found no abnormality. Actions Taken: FT installed at the Quench valve was also drained and purged and found no error. Unit load reduced to turn down ratio. 2nd Quench Gas flow at bed#3 increased to compensate for the reduction at Bed#4 Quench (3rd Quench). Your expert opinion and guidance is requested on the Issue.	(4)
17/05/2011	Q:	In case of flue gas power recovery turbine small amount of seal air is always leaking. The temperature of this air is about 200 deg C. Does this create any hot unsafe atmosphere around FGPRT?	(1)
17/05/2011	Q:	In flue gas power recovery turbine there is small amount of seal air is continuously leaking into atmosphere. Is this condition is acceptable operation wise?
14/05/2011	Q:	Does anyone have experiences of leakage of sea cooling water exchangers? What is best metallurgy for sea cooling water exchangers in a refinery? What are the important quality parameters of sea cooling water? How does one prevent corrosion of sea water exchangers?	(3)
11/05/2011	Q:	What is the standard value of sox/nox in atmosphere if emitting from hydrogen generation unit reformer for fg/naphtha/off gas firing?	(1)
11/05/2011	Q:	Our de-aerator conductivity is running high while de-aeration pressure is 0.3 kg/cm2g and temperature is 107 to 110 degree centigrade. Any thoughts on reasons and solutions?	(3)
10/05/2011	Q:	We are working on a project to eliminate ammonia from sour gas stream to SRU in one of our refineries in order to improve SRU operation and beside to produce ammonium sulphate to be used as fertilizer. Instead double stage SWS, we are thinking in absortion with sulfuric acid in a tower and neutralization of acid excess etc. One way is to develop the process by own but we´d like to know first if someone know who is licensing this process or who is using this technology.	(4)
03/05/2011	Q:	In our refinery, there is a proposal to utilize treated water from Effluent Treatment Plant in our Delayed Coking Unit as Coke Cutting Water. Can somebody throw some light on the suitability of ETP water for coke cutting purpose and the problems expected, if any?	(3)
02/05/2011	Q:	We have a thermosyphon reboiler for Light kerosene stripper with LGO pump around as heating media. We have seen a significant reduction in the reboiler performance observed by reduced delta T across LGO Pump around. This has resulted problems in light kerosene flash point. We introduced stripping steam and somehow overcome the problems. We observed that there was gradual increase in delta T over a period of time across light kerosene side in the reboiler. Can anyone help us to explain this unusual phenomenon in LK reboiler? Can the dryness across light kerosene in the reboiler results higher delta T? Gamma scanning of the column was done and found normal. How can we predict the Thermosyphon Circulation rates? Can the high temperature of LGO pump around inlet to reboiler cause fouling on kerosene side? If it is fouling on the tubes, then there should be reduction in delta T across LK side. In fact we are seeing an increase in delta T across LK side of the reboiler.	(4)
30/04/2011	Q:	Recently a new DHDS Unit was successfully commissioned. At Unit Feed we have 25 micro meter Gas Oil SS cartridge filters. Since start of Unit the filter choke again and again. Some times Unit thruput is reduced as these filter elements have to be manually cleaned and the cleaning interval reduces to less than a day. Our crude composition changes with change in crude tank and sometimes residue is there in Gas Oil. The filter elements are chemically cleaned and the interval increased but problem remained. What are other refiner's experience? What may be other causes of Filter elements chocking? What is the allowable limit of water in diesel Feed to DHDS Unit. Can high amount of residual water can choke filter elements?	(2)
24/04/2011	Q:	We are using 100% Visbreaker bottom as Refinery Fuel Oil in our heaters. Hard scale is observed externally on Heater Tubes. What is the usual normal receipe of fuel oil for Refinery Heaters. Is there any limit on fuel oil sulfur content to minimize fouling by adding diesel. Is there any treatment , by adding additives, to reduce external fouling of heater tubes?	(3)
22/04/2011	Q:	We have a SR type CRU. During recent shut down, catalyst regeneration was carried out. During reduction, welding leak was observed at air cooler outlet, upstream of caustic injection. Caustic injection point is at downstream of air fan cooler. Would caustic injection upstream of air fan cooler help where temperature used to be 100 deg C?	(1)
22/04/2011	Q:	There is a chilling water package that chilled water by use of propane refrigerant cycle. unfortunately propane cycle is polluted by caustic and we decided to wash the lines and equipment. I want to know, is washing with water or low pressure steam is harmful for this?	(5)
21/04/2011	Q:	During vapor heating of the idle chamber the bottom temperature of Main Fractionator goes as low as to 350 degC which is below the specified limit of 370 degC which in turn increases the fuel burning in the furnace leading to high skin temperature and less operating days. We maintain COT at around 495 degC and Chamber pressure of 1.8kg/Cm2. Can someone suggest better operating condition to avoid such a problem.	(2)
08/04/2011	Q:	In our wet gas centrifugal Compressor (capacity-130TPH), dry gas seal system (nitrogen) is given as primary, secondary and separation gas. The N2 header pressure is 7.5 kg/cm2g. Is any back-up facility (N2 bottles, booster etc.) required for safe and smooth operation of WGC in case of header pressure low or failure of supply?	(2)
07/04/2011	Q:	We are facing problems with the main fractionator reflux drum bootwater high chlorides(120 ppm) There is prefractionator ahead of main fractionator but we are getting zero chlorides in overhead boot water. does the inorganic chlorides dissociate more at temperatures greater than 250 degC which is prefractionator temperature?	(3)
04/04/2011	Q:	Our overhead wash water which is demineralised water addition is not continuous at CDU plant. Water is added to 2 bundles in 4 hrs. Then water is added to the next 2 bundles and so on. This implies that the 1st bundle in which water is added receives wash water after a gap of about 1.5 days. We use neutralising amine and keep ph between 5.5-6.5 while having almost no corrosion on overhead lines (monel cladded). Caustic is also added at the downstream of the desalter. The contractor who provides services and chemicals is claiming that addition of more wash water to have continuous wash will decrease the consumption of neutralising amine. In our opinion this will not work since the amount of wash water will have no impact on the mass of chlorides available in overhead stream. Would you please comment.	(4)
04/04/2011	Q:	For the last couple of weeks, ATF product ex Merox is failing on Silver Strip Corrosion test. What could be the reason?	(3)
29/03/2011	Q:	What is Reverse seal in an FCC Riser? How to maintain it at a certain value?	(1)
24/03/2011	Q:	Does a prereformer require an automated bypass? Some catalyst vendors insist on auto bypass; some say it is not required. What is best practice?	(2)
23/03/2011	Q:	We would like to go for absorber to remove water from methyl acetate. Feed composition: Methyl Acetate: 99% and water 0.75 % and rest are methanol and acetic acid. I would like to know which type of absorbent I have to choose to absorb water from methyl acetate. It will be great help, if someone can throw light on this.	(1)
23/03/2011	Q:	How do you calculate steam-to-carbon ratio in H.G.U.?	(1)
22/03/2011	Q:	I want to know importance of Real Density and Vibrated bulk density for various type of coke? What does it indicate?	(1)
19/03/2011	Q:	Our NHT reactor DP increased when we changed the light feed material, orginal feed case design is 55% paraffins but we change this feed to 72% paraffinic feed. No reactor inlet temp / outlet temp or pressure changed. H2 consumption 100nm3/hr gone up but not too high. DP increased to 1500mmh2o from normal one (5000mmh2o). My question is, is high paraffin in feed is the problem or some another causes, if yes, then how? Additional info: Tank feed bromine was analized and we got 1.1 to 1.2 only and no olefins with new feed case.	(7)
07/03/2011	Q:	Recently we have 6 nos of recycle gas compressor trip incident, but even after 6 nos tripping we are not able to diagnose/analyse the reason for such trip. Tripping alarm in PLC for all occasion found to be same which is trip from compressor governor & trip from LCP (local control panel). Kindly suggest what may the probable reason for such a trip without any prior alarm? Compressor is steam driven.. RGC normal RPM ~11500 RPM. Is the trip incident caused by variations in gas molecular weight? Is it possible that surge conditions occur due to comparative lighter gas handling than design operating which ultimately force the RGC to trip?	(1)
06/03/2011	Q:	I am working in Diesel Hydrodesulfarisation Unit. In our unit after H2S removed in Amine Absober, Diesel will go to Stripper. Where steam (direct steam) used as stripping medium. The purpose of steam stripping is only to removal of lower ends or it will remove H2S also. Presently we are maintaining Stripper I/L and bottom temperatures 230 and 225 deg respectively. If I decrease the temperatures by 5 deg, I will gain that heat in preheat, but it is believed that if we decrease stripper IlL temperature H2S in product Disesel will be more and copper Strip corrosion problem will appear. Is it true , By decreasing stripper I/L temperature and increasing steam Can I balance it.	(4)
05/03/2011	Q:	How can I access daily energy and utility product costs e.g. steam, cooling water, deminaralized water, desalinated water and so on?
01/03/2011	Q:	Next week , we will shutdown some of our units (in crude refinery) due to economic matters. This shutdown will last more than 3-5 months. We are now thinking about how to keep furnaces during this long period. Our furnaces have combined-fuel burners. I would like to have some guidelines about this task.	(3)
01/03/2011	Q:	Our Delayed Coker Unit Fractionator boot water chloride content is ~240ppm, Iron content ~0.22ppm. We have started injection of DM water at the upstream of condenser. What is the desirable range/ its consequence and how to reduce it ? What is the root cause and contributing factors for high chloride? Additional info: Vacuum residue is the feed to DCU and its water content is 1.2-1.4%.	(5)
28/02/2011	Q:	To avoid corrosion in NHT Stripper overhead circuit, what should be range of PH in overhead receiver boot? and what should be the temp of overhead condensing stream to receiver at around 10.5ksc press?	(2)
25/02/2011	Q:	Is there any chances of formation of pyrophoric substances inside naphtha /crude oil tank after long time? if yes, then how to remove from tank?	(4)
25/02/2011	Q:	We are having excessive rate of rise in skin temperatures of our coker heaters. Can somebody tell us the reason for such rise? It is to be noted that the coke formation in the tubes is a very thin layer.	(2)
23/02/2011	Q:	Is there any possibility of an FCC catalyst dust explosion in confined space because of static charge?	(1)
23/02/2011	Q:	What will be the sand filter specification for LPG service?	(1)
22/02/2011	Q:	We have a Kerosene hydrotreater which is processing straight run light kerosene from crude unit to produce ATF. My feed conditions are : Temp at battery limit: 80-100 Deg C, pressure: 6.5 kg/cm2. Density: 0.804 @ 15 Deg C. Kerosene is being filtered by two basket type filter having 100 mesh (one stand by) (Filter temp around: 135-145 Deg C). We are facing a problem of frequent filter chocking, but filter element is clear, no dirt, no scale, no corrosion particles, you can say crystal clear like clean filter element, still having high DP. what may be the reason of higher DP across filter? Is there any chance of gum formation/ polymerisation (Because of additives in crude unit), which u can not see by naked eye, but may create DP? Additional info: Filter is getting chocked frequently. i.e. sometimes in 3-4 hrs (best achieved life 15-20 days). Once filter got chocked 16 times in 2.5 days. Dirty filter baskets are being cleaned by hydrojetting and followed by steaming. Original design was of 25 micron (500 mesh), but because of frequent chocking filter mesh has been changed to 74 micron (200 mesh) temporarily. Filter element is of stainless steel. Till date no adverse effect observed in reactor DP or heat exchanger fouling. LK feed is straight run from crude unit, no feed from tankage. which feed characterization study can be carried out to identify problem.	(5)
21/02/2011	Q:	We are facing high delts temperature rise in coker heater tubes which necessitates heater tube cleaning owing to high coke deposition. We are trying to correlate this with feed VR quality. Currently the parameters which are being closely monitored are SARA (saturates, Asphaltenes, Resins and Aromatics contents of feed), metal contaminants etc. Can anybody suggest what other feed characterization needs to be done to perfectly correlates the high temp rise in heaters? What others test can be carried on so as to limit those values to keep heater functioning for longer time?	(2)
20/02/2011	Q:	Normally Flare KOD bottom is drained to closed blowdown (CBD) which is floating with flare even though flare KOD level is maintained. Why so?	(1)
19/02/2011	Q:	What are the fundamentals to separate hydrogen sulphide and ammonia from two stage sour water stripping unit?	(3)
18/02/2011	Q:	Our HP sour gas header battery limit B/V is passing and leads to shut down other supplying unit to replace passing valve. To face this problem in future, maintenance is going to install 2nd block valve after removing originally installed NRV. Q-1 Will it be successful? Q-2 Why there are NRVs installed in battery limits for incoming lines?	(2)
18/02/2011	Q:	Clarified Oil (CLO) is coming from bottom of fractionator in FCC. Does it relate to catalyst-oil circulation and catalyst properties? How can we reduce the CLO quantity from main fractionator bottom?	(3)
17/02/2011	Q:	We have Power Recovery turbine (PRT) to recover the power from Flue gas coming from regenerator. Because of seal gas failure Flue gas about 600°C coming outside from PRT. We don't have any back-up seal gas on site. How can we tackle the leakaged flue gas from PRT?	(1)
17/02/2011	Q:	Normally VGO feed temp. in FCC reactor is 350°C-390°C. Because of upstream side heater trip temp. goes down to 290°C. What will be the effect on reactor regenerator operation? And using this low temp feed can I run Reactor-Regenerator for some hrs?	(3)
12/02/2011	Q:	In Semi regenerative reformer, before regenerating the catalyst hot stripping of the catalyst in hydrogen atmosphere at 900 deg F is done. Is it necessary to do this hot stripping even if we are dumping and screening the catalyst?	(3)
08/02/2011	Q:	we are facing a problem of hydrate formation in propane BOG (boil off gas) recovery.Th stream is mainly consists of propane ,ethane and low concentration of water (1 ppm volume). How can I determine the solubility of water in propane at low temperature ranging from -40°C to 0°C. i will be than grateful if can I have the reference papers in the subject.
08/02/2011	Q:	I am trying to identify a substitute for caustic soda in a desalter. My client wants to reduce his caustic spend volatility. Is there anything available which serves the same purpose as caustic and is as price competitive?	(1)
03/02/2011	Q:	When should we be using a bypass line for a valve? Is there any rule for this?	(2)
30/01/2011	Q:	we face a big problem. We have a caustic unit to sweetened propane and butane in the gas refinery. For caustic regeneration, after oxidation of rich caustic, it converts to De sulfide oil and lean caustic. Wash oil is used to separate De sulfide oil and caustic because of close density of these two product. Sometimes we don't have any wash oil to use and total sulfur at both products increasing awfully. It means that no mercaptane was separated from propane or butane. Do you have any suggestion to separate De sulfide oil from Caustic without wash oil? Do you know any alternative besides wash oil?	(2)
22/01/2011	Q:	To what extent can we blend fuel oil into gas oil without affecting the viscosity characteristics and maintaining the flash point specifications for gas oil or to keep them within the allowed limits? Additional info: First of all we don't have neither FCC, Hydrocracker nor VDU...we only run a conventional CDU the objective here is to maximize the yield of gas oil...(we call it solar in our national markets) by extra stripping out from fuel oil or residue...the question is; Is there any equations or experimental methods to calculate or estimate the resulting viscosity and flash point of either the gas oil or fuel oil? Thanks a lot.	(4)
18/01/2011	Q:	We are facing a high odor rating in Polypropylene. We have merox unit for sulfur removal from LPG & also PRUs. To further enhance sulfur removal (particularly for heavier mercaptans) we have installed Naphtha wash facility in Merox. Still we have odor issue. COS & heavier mercaptans, I think, are the main culprits. Can somebody advise how to improve Merox performance? Or suggest a new facility to cut down sulfur level further?	(4)
16/01/2011	Q:	Pyrolysis gasoline from Ethylene unit is sent to a recovery unit to recover C7 minus components. These are recovered in two columns under vacuum. Maximum temperature is at the bottom of the second column which is ~ 145 deg C. Unrecovered stuff is sent to Utilities as liquid fuel. Anti-oxidant injection is done in the Ethylene unit as Pygas contains precursors such as dienes which can lead to polymerisation. Recovery unit was operating steady, without any problems, for 8 months. Now for some reason the frequency of choking of the strainer of bottoms pump of the last column has increased dramatically. Also, we are experiencing frequent choking of burner guns. Material found is coffee coloured granules which become powder when subjected to pressure. Trying to understand root cause. Not much has changed in terms of operating conditions. Very few component analyses are done in the whole system and not much information is available. Hope to get some inputs based on experience in similar units.	(2)
12/01/2011	Q:	Is there any commercial FCC process available in downer configuration? Hydrodynamics of Downer favours FCC process but still why there is very little information about downer FCC commercial units.	(3)
11/01/2011	Q:	In Continuous Catalytic Regeneration (CCR) plant we have faced a corrosion problem at the downstream of regeneration section which was caused by chloride ion contained vent gas. What are your suggestions to prevent corrosion?	(4)
03/01/2011	Q:	Which is to be preferred in a cooling water system: Side Stream Filter or Gravity Filter?	(1)
03/01/2011	Q:	What is the difference between PRV and PSV? What will be governing case for sizing a PRV for boiler's de-aerator? Also how to calculate relieving temperature?	(3)
03/01/2011	Q:	What are the key factors for improving efficiency of API gravity oil separator?
01/01/2011	Q:	Most of the time while rating a shell and tube heat exchanger, we are given baffle cut percentage based on the area. Can anybody tell me that how to convert this percentage area to percentage dia baffle cut?	(1)
29/12/2010	Q:	I have heard that Acoustic Meter could be used for testing the healthiness of the PSVs and control Valves. I would like to have some reference of vendors or manufacturers for this tool.
19/12/2010	Q:	Our project has an amine FCCU and amine sweetening and SRU, but sulfur recovery will be in service 1 year after FCCu start up. There is a problem with feedstock of SRU that must be sent to acid flare (with 32 m length). What can we do with this stream with 80%wt h2s witout sending it to flare?	(4)
15/12/2010	Q:	We have semi regeneration plateforming unit and currently it the third cycle. Catalyst is platinium/Rhenium.We are continuesly loosing Reactot Delta T. At SOR it was 129 deg C.while currently after 19 moths it is 90 deg C. MCH and CIS di methyl cyclo hexane in feed is 10.6 vol% while in reformate both are 1.2 vol%.Stab. ovhd gasses production is also very high. Hydrogen purity in previous cycles were above 90 while currently it is in between 87~88%. we have also experienced crude blend change in the current cycle. Naphthenes are currently 32 wt % while previously it was near to 35 wt %. such decrease in delta T was not experienced in previous two cycles. What are the possible causes?and what are the remedial actions to save the catalyst.	(1)
06/12/2010	Q:	We have a methanol-Water stripping column, which uses direct injection of LP steam for stripping. I want to know if it is better to use reboiler instead of steam injection. Is there is any advantage in using direct injection of steam in methanol-Water stripping column?	(3)
04/12/2010	Q:	We are facing problems with one of our reforming unit furnaces. There is a common duct in the three furnaces. The damper of the middle furnace is causing the problem. This damper falls several times after burning. The skin temperature of the tubes remain good but the stack temperature is higher than safe value by almost 150 degree Celsius (around 900 degree Celsius) . The furnace outlet temperature is operated below the design temperature by almost 25 degree Celsius. Our design temperature is 525 degree Celsius. The shaft, plate of damper used of stainless steel grade. We had changed burner tips several times but the problem was not solved. Please suggest me the cause and remedy of this problem.	(3)
01/12/2010	Q:	How do you calculate grid area for vertical grids (plate/tube type) in case of a horizontal Desalter?
30/11/2010	Q:	In one of our furnaces we are facing problems with fuel oil dripping from burner blocks. Atomising steam vs fuel oil dp is 2.5 kg/cm2 and fuel oil temperature is 170 deg C. Is the problem mainly due to improper atomisation or some problem in burners assembly adjustments, or insufficiency in air?	(4)
24/11/2010	Q:	We have SR Catalytic Reforming (Pt-Rh) Unit for 90.0 RONC production. It is our third cycle and the delta T of SR Reactors is decreasing rapidly day by day, but RONC is decreasing slightly or almost constant. However, stablizer overhead gases has also increased extensively. Some opinions arises that there may be the leakage in Combined feed exchangers of Platforming section. But, we are unable to detect this leakage during plant operation. Please mention, how we can detect this leakage (during plant operation) and secondly, please also describe that what may be the other reasons of such decreasing trend of delta T (i.e; from 125 deg c to 88 deg C in 7-8 months), keeping in view that we are running plant at 110% load and our design H2 / HC ratio is 4.5 in first cycle. Is there any need of revision of H2/HC ration in third cycle, if yes then how? Additional info: Its again me who put up the questions. 1-- Yes, it was text fault,, its Platinum - Rhenium. 2-- Please tell, what we have to check in feed and product regarding MCH? means which thing will proof us leakage in F/E? 3-- Their is only excessive increase in OVHD gases of stablizer. 4-- Hydrogen purity decreased from 90 to 85%. 5-- YES, H2 / HC ratio is easy to calculate, but i want to ask that during third cycle or as the cycles progress, is it necessary to revised this H2 /HC? if yes, then on what basis? 6-- We have increased RITs from 4-5 deg C but RON did not increase. 7-- We have decreased H2 / HC to about 3000 NM3/ hr and delta T improves from 89 deg C to 90 deg C. but a slight yellowish appearance of reformate was detected. ( what will be the reason?) But, RONC did not change	(8)
18/11/2010	Q:	There is continuous increase and decrease in our column delta pressure in water methanol column. At the same time we noted that our temperature profile of the bottom and middle bed is also fluctuating. I feel that our column is having vapor cross channeling. There is some variation in feed flow and steam flow, but column is somewhat running at 100 % load. If anybody experienced such problem in your plant, please throw some light to understand what causes this fluctuation in delta pressure and temperature profile in the bed and what action to be taken. Additional information: Steam direct injection for stripping There are three bed made of PP intolox saddels Steam flow is controlled by mid bed temp Reflux is controlled by feed flow More information: This is a packed distillation column to strip methanol from water. We are using steam stripping in our case because there are some traces of Acetic acid in the bottom. To prevent corrosion we have to strip at low temperature, so we are using steam stripping. There is huge variation in temperature profile of the middle bed, at 100 % load First indication of channeling is the change in delta pressure and disturbance in temperature profile. Disturbance in temperature profile is caused by improper distribution of vapor flow in the bed. So thinking this is because of vapor cross channeling. If it is channeling or flooding how can we deal with it? More information: Thanks a lot for all your suggestions, we have opened our tower found that steam deflector plate was installed wrongly, so steam was injecting directly into the packing, which caused packing to expand and that caused channeling in our tower. After rectifying this, now we don't face this problem.	(5)
18/11/2010	Q:	What happens if we do not use steam for streaping and neither the slop lateral cut draw from the tower in our Vacuum tower? I would like to know the consequences for this type or operation.	(3)
09/11/2010	Q:	Can you please advice what type of corrosion inhibitor, biocide, antifoulant and polyelectrolyte polymer can be used in Desalter effluent?	(4)
09/11/2010	Q:	We have a hydrotreater, where I would like to limit my aromatics saturation. Can some one suggest if it is possible and what are the critical parameters for it?	(5)
08/11/2010	Q:	I am working on a flare gas recovery project. We understand purging of flare header is recommended to maintain positive pressure and air ingress. My query is, if I have liquid seal or any other device between knock out drum and flare stack to divert gases from K.O. Drum to flare gas recovey unit (FGRU), and maintain a positive pressure upstream of seal, do I still need to purge flare header, or only flare stack needs to be purged to provide air ingress? If at all purging is required then what is correct reason for purging? Although, as liquid seal/or any device (fast opening valve placed) will result in positive pressure upstream of seal and K.O. Drum and I feel that purging of flare header is not required and only flare stack needs to be purged.	(3)
05/11/2010	Q:	Lately we had a problem on one of our old (33 years) but reliable Desalter Transformers. The Transformer is NWL 150KVA 4.16KV/23KV (3each) on top of our crude oil desalter trap. Two of these transformers experienced failure and we found the high voltage cable was burned and cut. The oil in the entrance housing was discolored (black) and the oil in the third transformer was clear. Later on we found the secondary on the third transformer was disconnected. the floating switch and the grid were OK. What are the possible causes for such failure? We replaced the entrance bushings with the high their high voltage power cables for the damaged bushings. We performed Megger test and Polarization Index (PI) test on the transformers. The PI was 1.4, 1.6 and 1.5 for these transformers. Are these PI readings acceptable to put back the system in service? What are other tests shall we perform on these transformers?
03/11/2010	Q:	What are the likely benefits of processing Methanol in shift reactors of existing NG based hydrogen Plants? What modifications would be required..?
01/11/2010	Q:	I am interested in knowing more about the options of value addition to C4 stream produced in FCC / CDU. C4 produced consists of a mixture of N-Butane, Iso-Butane and Butylenes. Following value addition routes exist: a) Recover Butylenes and convert them to Propylene using OCT (Olefins conversion technology). b) Recover Butylenes, Isobutane and convert them to Alkylate in Alkylation. c) Recover Iso-butane and use as a feed to Alkylation. I would like to know if there are other routes of value addition available or any synergy with a Petrochemical complex. What are the options for N-Butane for value addition?	(4)
01/11/2010	Q:	Can someone advise me of what a multi arm catalyst distributor in the regen looks like? This is with a spent cat riser carrying 100% of air and catalyst. This was a design probably done way back in 1940s (long long before I was born :).. Can someone guide me of how this thing works and even if there are any design guidelines to design one? I have heard of one refinery in California (Martinez) which has this 12 arm distributor, called dodecapus...	(1)
30/10/2010	Q:	What are the advantages of using of a 3-phase centrifuge decanter compared to a 2-phase one for oily sludge dewatering?	(1)
26/10/2010	Q:	We are fixing for choosing a new compressor for VRU; vapors recovery unit; the light hydrocarbon gas mixture has Mw about 42, K{Cp/Cv} =1.12 , Rc {Pd/Ps} =3.2 , Z factor is about 0.97, Inlet temperature is 43 C and flow rate Q is 600 CFM, discharge Pressure, Pd= 72 psia... I'd be more than grateful for any tips, Equations, etc to use...	(1)
22/10/2010	Q:	We have LVGO stream from vacuum column & processing it in VGO hydrotreater. In LVGO stream we encounter chlorides up to 20 ppmw (organic+inorganic) which is posing corrosion issues in VGO hydrotreater. I want to know how to remove these chlorides prior to enter downstream unit.	(6)
15/10/2010	Q:	Reformate (final product of platforming unit in our plant) got colored during last two start-ups. What are the probable reasons behind this? Please mention the rectifying measures of this problem.	(2)
15/10/2010	Q:	What would be a typical product distribution of Coker light gas oil (diesel range) on an FCC Unit when the Coker light gas oil has gone through a VGO Hydrotreater?	(1)
13/10/2010	Q:	Does anybody have any experience of using mixed amines, i.e. DEA+MDEA, for sweetening? I am interested in operational problems like foaming, sludging etc related to mixed amines treatment.	(2)
13/10/2010	Q:	Is it technically viable to inject sweet LPG ex CDU in reformate rundown (from bimetallic fixed bed reforming unit) with the sole purpose to increase reformate's RVP and RONC keeping in view that the reforming catalyst is nearing end of run and cannot meet the target sverity RONC? what are the repercussions?	(6)
10/10/2010	Q:	Our amine system circulation rate is 250 m3/hr. Since commissioning we make up losses by adding fresh amine. 1) Please recommend actions taken to check and monitor health of amine system. 2) What is the typical life of DEA 20 WT % after which whole amine is to be replaced ? 3) Do we have to bleed some amine from reflux drum to reduce system corrosovity?	(1)
09/10/2010	Q:	My company aims at further processing the atm. distillation residue (Mazot); and a hydrocracker unit has been chosen for this task. We need to estimate the cost of the unit and its facilities like the vacuum tower and the vis-breaker. How would you suggest we get a rough initial estimate of the costs involved?	(5)
07/10/2010	Q:	Our Sour water stripper unit is a two stage operation. The first tower operates at 7 KSCg pressure and second tower operates at 0.8 KSCg pressure. Recently we have encountered a strange problem. The color of the stripped water is milky white and also looks hazy. The overhead temperature of the second tower is running high, 100 C (Normal is 90C). Please suggest some solution.	(2)
06/10/2010	Q:	If an Exib certified head mounted TT is installed in Exd RTD head, what independent certification of Tx and RTD head suffices? Does the complete assembly needs certification? What about temperature classification?
05/10/2010	Q:	if an Exia certified tepm. Tx is installed in Exd certified RTD head, do independent certificates of tx and RTD head suffice, or is certificate of complete assembly required?
04/10/2010	Q:	Is there any simple tool for detecting passing among a valve (PSV,PCV,...)? I heard something about some pen type simple detectors for operators. Has anybody more information about this kind of tools?	(3)
18/09/2010	Q:	I am working in a diesel hydrotreater. Can we simulate a hydrotreater in Aspen HYSYS refsys - hydrocracker? While calibrating the factors, what inputs we are supposed to give. What will be general values for HDS, HDN, SAT, Cracking, Ring opening activity for diesel hydrotreater and what does the term "treating bed to cracking bed mean"? Please explain.
10/09/2010	Q:	I am in Diesel Hydrotreater unit. Our feed contains maximum of 20% unsaturates (cycle oils). In the startup procedure, we were told that feed should be cut in at a reactor bed temperature of 260 C. But our current catalyst supplier has suggested that you can cut in feed even at 320 - 330 C. I just want to know what will be process implications if we cut in feed at 220C or 260C or 320C. Our diesel feed API is 33, feed sulfur is 1.2% wt, IBP 147 C and FBP 424 C. One more thing: what will be effect if we run the high pressure separator at lower and higher temperatures. (It happens some times because of Fin-Fan cooler problems and climatic conditions).	(4)
07/09/2010	Q:	Our benzene product tank is internal floating roof tank with N2 blanketing which follow US EPA regulation. However measuring the VOC content at breath out shows as high at 15000 ppm. The internal roof rim seal was replaced and produced only minor improvement. Is there any plant try to install vapor recovery unit to reduce these emissions? Is there any regulation which requires the benzene tank to be equipment with close system?	(1)
07/09/2010	Q:	How do you calculate power density for a crude desalter unit for a given grid area? Also, is there any correlation between the droplet size and electrostatic field strength?	(1)
02/09/2010	Q:	I have a query regarding distillation. How is it decided whether steam should be used or a re-boiler should be used in a distillation column. I am in DHDS unit. The finished diesel stripper uses direct steam injection as stripping media where as the stripper in Pre de-sulfurisation unit of Hydrogen generation unit (steam reforming) contains a reboiler. Both columns intention is to strip out light ends and also some amount of H2S.	(3)
01/09/2010	Q:	I would like to know why there are two feed inlets in a Sour Water Stripping tower, but normally only one will be in use and the other will be blinded. In Sour water strippers why is chimney tray provided?	(4)
31/08/2010	Q:	I am working in a Diesel Hydrotreating unit. I would like to know how much should be the wash water flow. I also look after Sour water stripping unit. Why are the feed valves to SWS stripper located near the tower. Is there any specific reason for it? The same is the case with Amine recovery unit stripper.	(2)
27/08/2010	Q:	I would like to know in a plant that has different coolers that run off one cooling tower is it OK to pinch on cooling water when the cooling needs vary in different parts of the plant? I have worked in several different plants and this is usually an accepted practice but now I'm in a new plant and operators oppose pinching on the cooling water valves. Currently we are running cooling water at 90 degrees which in are second stage chiller I think is too hot and overloads the refrigeration unit but if we pinched cooling water at inlet discharge coolers and used compressors discharge temp to maintain our front in temp it would be a much better way to run the plant.	(3)
15/08/2010	Q:	we have an induced draft double-flow, cross flow cooling tower...using air to cool condensate water. the tower fans has two speeds; low & high...In winter, usually low speed is used as the air temperature is low enough (Egypt), so that it reduces the water temperature by an acceptable manner. However; the water is found to exit from where the air enters -the louvers- while, through high speed operations in summer, this doesn't occur.
11/08/2010	Q:	What is the typical value of Hydrogen content in Coke for Resid FCC?	(2)
11/08/2010	Q:	What are the potential problems if feed remains un-vaporized because of heavy tail end of the feed? I know un-vaporized feed leads to increase in coke, which eventually burns in regenerator. Does anybody have any experience about how much portion of un-vaporized feed ends up in coke? Also in case of operating unit how one can figure it out whether feed is fully vaporized or not?	(1)
09/08/2010	Q:	I work in Hydrocracking plant, where we commonly use turbine pump when running in normal condition, and backed up by motor pump as a spare pump. But, in some equipment, we use turbine pump as primary pump and backed up by turbine pump as a spare pump. This pump transfer the bottom of low pressure separator (liquid hydrocarbon) to debutanizer. I also found a pump configuration where both the primary and spare pump are turbine pump. This pump is diesel pump around (hot wash). Do you know what is the reason behind these configurations?	(2)
07/08/2010	Q:	In a boiler with sootblowers, among all the variables that control the efficiency how we can find out the role of soot blowers in efficiency as percentage? (The steam consumption by sootblowers is unknown)	(2)
03/08/2010	Q:	When we had turn around in amine treating unit, sulfur recovery plant, we found almost outer tube side covered completely by hard scale. We suspected that it came from degraded solvent (amine compound) during regeneration. We had already been cleaning with chemical agent, but it showed unsatisfied result. Does anyone have similar experience? What recommended cleaning technique should be done?	(2)
30/07/2010	Q:	What are the most important aspects taken in to consideration when designing a feed injection system for a FCC reactor?	(4)
29/07/2010	Q:	What are the potential problems in a feed injection system of using feed containing high carbon residues , i.e. more than 10 CCR? If feed injection through feed nozzles are a problem for high carbon residue feeds, how can such feeds be vaporized efficiently in RFCC reactor?	(2)
29/07/2010	Q:	We have one PSV Set pr.:-16.5Kg/cm2, Cold Set Pr:-17Kg/cm2 & back pressure:-1.7 Kg/cm2. However, after dismantling it was observed the bellow is in cracked condition. We have withdrawn the bellow against the psv code but it doesn’t match with original bellow. We have also looked for other matching probability but we have failed to find any matching bellow. we have to install PSV without bellow. What will be new pressure set for the PSV without bellow? Further question: Do we need to raise the CDSP (cold set pressure) of PSV? if not, then why install bellow type PSV?	(2)
29/07/2010	Q:	In one of exchange PSV was set at 16.5 kg/cm2g. Now its rupture disc got damaged. what will be the new set pressure for PSV without rupture disc considering its flare back pressure of 1.7 kg/cm2g?	(2)
25/07/2010	Q:	Are variable speed drivers ever used in pumps? If not, why not?	(4)
19/07/2010	Q:	I work in CDU with a capacity of 70000 barrels \ day I have a problem. when we introduced desalter to work, the amount of feed unit quantity decrease to 85%, especially when the introduction of washing water to work by 17000 kg \ hour DIFFERENTIAL PRESSURE on the mixing valve set to 0.35 kg \ cm2,desalter pressure is 11 kg \ cm 2 When trying to increase the unit capacity, the desalter press. Increased and send a signl to the pressure valve that is installed on the charge pump discharge to derease it’s open to reduce the increasing pressure. Additional information: Crude oil is taken by gravitation flow from storage tanks. The crude oil is fed pump P01 to the first part of one route heat exchanging system, where is preheated in the train of exchangers E01, 02, 03, 04 and 05 to temperature 125-130 °C. The crude oil with this temperature enters the single stage electrostatical desalting. Desalting process operates with pressure 10-12 kg/cm2g and Desalted crude is fed by means of pumps P02 to the second part of one route heat exchanging system (exchangers E06, E07, E08, E09, E10), where is heated to temperature 244-252 °C. Crude oil is dividing into four equal streams. Each of the four streams is controlled by a flow controller and enters the convection section of heater H01. In the heater (convection and radiation section) it is finally heated to temperature 342-348 °C	(4)
18/07/2010	Q:	Recently we found that the valves in the off gas (that comes from Vacuum distillation tower) separator unit line did not last long. After 6-7 months valve seat or body sprung leaks due to off gas. Please help me by suggesting the appropriate valve for this service.	(1)
15/07/2010	Q:	Is there any relation between Velocity steam and Heater Outlet temperature?. Normally Velocity steam is adjusted for heater tubes residence time.	(1)
14/07/2010	Q:	I work in a CDU plant. The plant loads two types of crude oil, one of paraffinic type API 48 and other one of naftenico type API 25. When crude oil naftenico is loaded high instability is had in the vacuum system (Loss Vacuum in the Column), situation that does not happen when paraffinic crude oil is loaded. Can it be something related to the ejectores? or to major production of non condensibles when crude oil naftenico loads? . The furnace-outlet temperature is 725°F with crude oil naftenico and 650°F with crude oil paraffinic.	(1)
11/07/2010	Q:	There are 3 hydrogen plants in our refinery. All of them are steam reforming process. We use OG, LPG and naphtha as feed to produce high purity hydrogen. The raw hydrogen stream comes from steam reformer, after cooling down then sent to PSA to recover high purity hydrogen. The design recovery efficiency of PSA is 89%, we found the actual efficiency at high throughput condition is 85% or less only. This is a bottleneck for hydrogen plants. There are some comments from outsources. Someone said the operation life of molecular sieve used in PSA is very long, 10 years or more, we don’t need to replace it. But another had opposite comments. Would you please advise.	(6)
09/07/2010	Q:	What is odorless kerosene? And how is it processed?	(2)
09/07/2010	Q:	Could anyone please tell me how to calculate dew point of instrument air with a pressure of 10 bar?	(2)
08/07/2010	Q:	We have a very strange problem, it's that the desalter outlet crude has greater salt content than that of the inlet... the lab examinations proved that more than once...this always happens when the injection water is cut off-while switching from a tank to another. What could explain this? Additional info/response: 1. We cut off water while switching between tanks because of the existing water accompanied with the crude from the new tank; I mean the first 30 minutes after switching to a tank, the crude has too much water to inject more. 2. How could the NaOH type could affect this situation?	(10)
07/07/2010	Q:	Recently we carried out liquid phase sulfiding instead of gas phase sulfiding of freshly loaded hydrotreating & hydrocracker catalyst in the hydrocracker unit. Liquid phase sulfiding done with DMDS in light diesel oil & 50: 50 hydrogen/nitrogen pressure. After sulfiding phase over & unit feed cut-in with vacuum gas oil ex. vacuum distillation unit we encountered severe problem with sulfur in H2S form detected in light naphtha product (C5-135 deg C range) coming out from stabilizer column. Pl note fractionator column ovhd goes to D-ethanizer & stabilizer column after ovhd gas compression in three stg compressor to separate out fuel gas, LPG fraction & Light naphtha product.What may be the probable reason for H2S sulfur in high concentration (> 700 ppm) in light naphtha product? Is there any possibility of sulfur stripped out from liquid phase sufided catalyst?	(2)
06/07/2010	Q:	What is the best way of judging the efficiency of a desalter?	(6)
05/07/2010	Q:	What will be the steam dew point at 93 degC and 1.1 kg/cm2g? Pl let me know whether dew point of stripping steam used in distillation column depends upon partial pressure of steam in the total vapour mass flow going out in the distillation overhead. Pl note total vapour mass flow in our distillation column ovhd is 274000 kg/hr and stripping steam flow (at 14 kg/cm2g & 220 degC) to column is 8490kg/hr. Overhead vapour is mixture of gaseous hydrocarbon (C1 to C5 range components) & stripping steam. Pl let me know if you need more data to answer my question. Our distillation column top operates at 1.1 kg/cm2g & 93 degC.	(3)
05/07/2010	Q:	What makes outside shapes of distillation columns differ from one another? i.e. shape of pre-flash differs from CDU, CDU differs from VDU?	(3)
03/07/2010	Q:	What are the benefits of adding process steam in pre reformer inlet and reformer inlet separately? In some hydrogen plant it is mixed only in reformer inlet. What is the advantage of that?	(2)
01/07/2010	Q:	What is the maximum allowable figure of own use fuel and losses (OUL) in terms of percentage (vol%) of crude charge processed for a hydro skimming refinery?	(4)
01/07/2010	Q:	We wish to install strainer on instrument air injection line to be used during regeneration of bi metallic pt Re reforming catalyst to avoid carry over of line material/scale on catalyst surface. Can anyone recommend what mesh size should be installed in strainer?	(1)
24/06/2010	Q:	Is a pressure instrument really required at inlet cone of transfer line exchanger? if yes, then what is the best arrangement? Will the nozzle for pr instrument pierce through the refractory lining?
24/06/2010	Q:	We are interested in purchasing used KHU catalyst (HR354), CRU catalyst (R32, R134) and FCC cat (Octasiv). Does anybody know were I can obtain it and if is so what is the price?	(2)
23/06/2010	Q:	What is the purpose of the weep hole in the chimney tray?	(3)
17/06/2010	Q:	how can we see the astm and tbp curves for outlet streams in distillation units in hysys?	(2)
09/06/2010	Q:	In our atmospheric distillation unit , reduced crude recovery was constantly coming 10-16% @ 360 deg C. We increased the bottom stripping steam but we are unable to decrease beyond 10%. Are there any other ways to improve the efficiency?	(6)
08/06/2010	Q:	What is the purpose of a flood nipple in a nozzle of a Column which goes to reboiler?
04/06/2010	Q:	we offloaded our CCR catalyst for reactor checks/repairs. we want to reload and I don't know the maximum permissible coke allowed on the used catalyst. Should we load catalyst with coke level of 6%wt?	(4)
26/05/2010	Q:	In our Once Through Hydrocracker, the Fractionator Feed Furnace has options for both Fuel Oil and Fuel Gas Firing. Currently due to some problem in the electrical heater in the Fuel Oil Circuit we are using only fuel gas. Some days back inspection department reported a much higher skin temperature in the radiation section of the Furnace. The same report was also upheld during various cross-checks by other departments. Could this be due to the reason as we are not using Fuel Oil? If so, then could somebody explain? Another thing to consider, we are running at 70% T'Put and design conversion so in general the burners are supposed to operate at the given Heat Duty.	(4)
25/05/2010	Q:	Is it possible to use the waste gas, exhausted from Cold Box (Nitrogen process), for combustion purposes in, for instance, fire heaters? Now, the oxygen supply in fire heaters is the atmospheric air while the waste gas, as oxygen rich gas, can be used during the revamp procedure.	(4)
21/05/2010	Q:	What are the likely effects of water carry over from desalter on Crude heater and distillation column? What steps should be taken if this happens?	(11)
21/05/2010	Q:	I am working on CDU as a field operator. I want to know why NH3 or NH3H2O is injected in overhead line of distillation column? Why dont we use NAOH for nutralization there? Even NAOH is cheaper then Ammonical water.	(5)
21/05/2010	Q:	We are planning to procure a new airpreheater for furnace with two cells K1 and K2 cell one for prefractionator reboiler and the other crude heater for fractionator. I am just filling the process data sheet. On what basis should I fix the pressure drop across the air side and flue gas side?	(2)
19/05/2010	Q:	Does installaton of static inline mixer in place of conventional mix type globe valve for mixing the wash water and crude before desalter help in improving desalter efficiency?	(4)
18/05/2010	Q:	In our Crude Unit we have LGO pump around heated Light kersosene stripper. The reboiler is no longer giving heat duty and hence Kero flash became limiting. We put stripping steam also in kero stripper, but no gain in kero flash. Is anybody using antifoulant for correction?	(2)
18/05/2010	Q:	Does injecting wash water ahead of preheat exchangers improve desalter efficiency?	(3)
18/05/2010	Q:	I am currently using KBC Profimatics model to simulate hydrotreater reactors. Are there any other models available in the market? Are there any tools which can be helpful in daily monitoring of the hydrotreating reactors?
18/05/2010	Q:	Problem: You have two reciprocating compressors in a NHT system, one service, the other on standby. When the duty trips the standby must be barred and then put into service. To bar it, it must be depressurised, barred, pressured up and then started, this could take up to 15mins, so this makes it very tedious and labourious. How long can a compressor be static until it needs to be barred? Some say it must be barred at least 1 hour before starting to ensure all liquid is displaced from the cylinders. Some say the compressor must be barred every 3-4 days. Are there any systems that can eliminate the need for barring via reducing the chance of hydrocarbon condensation or otherwise.	(3)
13/05/2010	Q:	Why is the range of electrical conductivity (unit:pico siemens/m) given as 50-450 for processing jet-A1(kerosene fuels)? what happen if range exceeds (i.e >520picosiemen/m) due to more chemical dosing during plant maloperations? what does effects does it have on mechanical parts of aviation fuel?	(4)
13/05/2010	Q:	What are the benefits of a top fired reformer versus a sided fired one?	(5)
11/05/2010	Q:	We have a thermosyphon reboiler for our stripper column. Before shutdown we were circulating more hot oil in this reboiler, but after shutdown we cannot increase the hot oil at the same feed rate. How can we rectify?	(2)
04/05/2010	Q:	We are hydro-skimming crude refinery with cracking units, from last few months we are having higher Phenolic Compounds Contents in our waste water effluents. Also we do not have any waste water treatment unit in our refinery. Could anyone tell us main sources of Phenols in waste water of a hydro-skimming refinery? Also why higher phenols are avoided in waste water effluents?	(2)
04/05/2010	Q:	My question is regarding Heat Ex. When I was simulating an Exchanger in HTRI which was of BHU type, I came to know that it is not providing any TUBE pass arrangement for 6 Tube pass and 10 Tube pass. The same thing is happening when I use the U-Tube combination with H or G type shells. Can anyone explain me what is the reason it is not accepting (providing Tube pass arrangements) 6, 10, 14 Tube passes with H-U (shell-Rear end) and G-U (shell-Rear end) combination?
30/04/2010	Q:	I know butt welding is much stronger than lap welding. But I found that the bottom and roof of storage tanks are welded as lap welding. What is the reason behind this?	(1)
20/04/2010	Q:	We want to install a Diesel generator near an already operational Gas generator located inside a gas installation for emergency power supply. As per OISD standards or other regulations is there any minimum inter-distance required?
20/04/2010	Q:	What will happen with FCC products if visbreaking gasoline and HDS wild gasoline (H2S content up to 10%) are sent to FCC riser? Will these gasoline crack? Will the olefins be saturated? What will happen with sulphur content in FCC gasoline and could Merox of gasoline cope with that? It is important especially in the case of low sulphur feed at FCC.	(3)
18/04/2010	Q:	We are using 20% DEA for removing H2S from gases in our refinery. How much 1% DEA will remove H2S if Rich amine loading is kept 0.33 mole H2S/Mole DEA for total circulation rate of 220 m3/hr as want to increase DEA Concentration. How can a relationship between Rich Amine Loading & Concentration be established?	(1)
16/04/2010	Q:	We want to recover the energy from high temperature flue gas from our four process heaters. The heaters main design condition is shown below. Please advise. The design information of these heaters Heater-1, Vertical Cylindrical Design Duty 4.48 Gcal/hr Fuel type – Fuel Gas only Flue gas from convection section 359 oC, mass velocity 1.959 kg/sec m2 Stack OD 1.2m Heater-2/3, Vertical Cylindrical Design Duty 6.91 Gcal/hr, each Fuel type – Fuel Gas only Flue gas from convection section 389 oC, mass velocity 2.315 kg/sec m2 Stack OD 1.378m Heater-4, Vertical Cylindrical Design Duty 6.57 Gcal/hr Fuel type – Fuel Gas only Flue gas from convection section 348 oC, mass velocity 2.482 kg/sec m2 Stack OD 1.4m	(4)
09/04/2010	Q:	We want to purchase some process equipment like distillation column, heat exchanger, pressure vessel, reactor etc. To make a budgetary proposal we need some information regarding costing of those equipment. Can anyone help me how the costings can be made? Is there any reference for this issue?
07/04/2010	Q:	For any industrial compressor why do we assign the interlock like this: Low pressure trip for lube oil and low flow trip for cooling water and why not vice versa ?	(2)
07/04/2010	Q:	What is the effect of increased or decreased reflux flow on RVP of gasoline in a gasoline stabilization column? what is the effect on RVP in case column is operating on total reflux and what is the effect in case of no reflux flow?	(3)
06/04/2010	Q:	What is the solution for water carry-over from the feed tank to the desalters?	(3)
06/04/2010	Q:	What is bone dry naphtha?
06/04/2010	Q:	What is the relationship between RONC and ASTM D-86 of light naphtha boiling in the range 40C-120C? what increases its RONC? Does an increase/decrease in IBP increase the RONC or is it the increase/decrease in final boiling point that increases the RONC?	(2)
06/04/2010	Q:	We are injecting Gaseous ammonia in crude column overhead line, also circulating the wash water in overhead line. We are also injecting caustic in desalted crude. Corrosion is mostly due to desublimation of salt. Can someone recommend how we can avoid corrosion in overhead line?	(5)
03/04/2010	Q:	What are the possible reasons for increase in COD value of Brine. Is there any relationship with crude property?	(2)
03/04/2010	Q:	In our refinery Crude column overhead liquid is condensed in Fin fan coolers. Condensed liquid then collected in receiver. Recently we had problem of severe fouling in fin fan coolers inlet line. Can you explain the possible cause for that? Also suggest some recommendation to avoid such kind of fouling in fin fan inlet header.	(4)
03/04/2010	Q:	In Our Hydro Cracker we face the problem in Naphtha circuit. The product naphtha fails due to colouring. But the other products are passing all the required test and parameters. Has anyone faced such problem; if so what could be the reason for naphtha product alone getting coloured?	(4)
03/04/2010	Q:	Kindly throw some light on catalyst loading in Reformer tubes by Spiral loading technique. Does this technique provide much stable distribution of catalyst and improvement in any process performance like uniform tube temperature, pressure drop across each tube constant, and reduced loading time?	(2)
02/04/2010	Q:	Sometimes it is seen that the leaky tube of heat exchanger is used by plugging both sides. I want to know the percentage of tubes that can be used in plugged condition in running condition and also the standard for this plugging.	(5)
30/03/2010	Q:	In flare header line, we keep positive pressure by water seal in water seal drum upstream of flare stack. During steam out operation in turn-around period, we plan to steam out the hydrocarbon in the process system to the flare system for reduced VOC emission to atmosphere. Since the condensation of steam may cause negative pressure in flare header line, this operation is safety concerned. Please advise.	(4)
22/03/2010	Q:	What are the possible reason for column pressure (1-2 KSC pressure) fluctuation. if the column pressure increases, will the separation increase, and vice versa?	(3)
19/03/2010	Q:	Centrifugal pump (say A) is designed for suction pressure 2.6kgf/cm2 with plan 11. Now if in suction we route some material @10kgf/cm2 with a 1/3 of flow of the said A pump by keeping discharge OPEN, what will happen? Is there any chance of seal leak?	(1)
19/03/2010	Q:	I am working in DHDS unit. Recently our unit tripped because of some strange problem. I request all to suggest a reason for the problem explained below. We have one centrifugal Recycle gas compressor (RGC) and two reciprocating make up gas compressors (MGC) one running and the other stand-by. As per the regular change over of MGC we tried to take the other one in line and spare the running one. The discharge of MGC (40 KSC) goes to suction of RGC (39.4 KSC). After starting the spare compressor and once it got 50% loaded, the make up gas rose from 25 Tons per day to 35 tons per days, simultaneously RGC amperage came down from 210 to 176 amps and discharge pressure of RGC came down from 61 KSC to 53 KSC and this dropping of amps and discharge pressure continued and unit tripped on low hydrogen pass flows. As the discharge pressure of RGC reduced the discharge flow also reduced. I didn't understand why the discharge pressure of RGC came down. Additional Information: Separator pressure is constant and when the RGC tripped, it started raising. The suction flow was 265 Tons per day and when the RGC discharge pressure dropped, the suction flow also dropped to 255 Tons per day.	(6)
18/03/2010	Q:	We are about to install 2 PSVs on a new vessel designated for hydrogen storage. The vessel is horizontal and is placed on ground level in close proximity of hydrogen production unit. In case of pressure buildup the PSVs will vent excessive pressure to atmosphere. I want to know what should be the optimum/safe height of the PSV vent?	(2)
15/03/2010	Q:	Since FCC feed quality is varying from refinery to refinery due to their own refinery configuration, like some one is using hydrocracker bottom, hydrotreated VGO, RCO, reside, or fresh VGO. Therefore, cost of the FCC feed or VGO is different for all refineries and it may the based on the quality of VGO . What are the parameters which may decide the cost of VGO which may charged to FCC?	(2)
13/03/2010	Q:	The purpose of Caustic injection in Crude is maximization of conversion of MgCl and CalCl into NaCl. Can anyone explain how this happens?	(3)
13/03/2010	Q:	Please highlight procedures for removal of iron deposited on Zeolite Resin of conventional water softeners. Any vendor who could suggest chemical for this purpose?
11/03/2010	Q:	In a semi regen. fixed bed platforming unit for HOBC production, what is the impact of operating the unit at an increased Hydrogen to hydrocarbon mole ratio or increased H2 partial pressure than recommended? I have noticed that whenever the mole ratio is increased by virtue of increase in recycle gas flow, sum of delta Ts across reactors drop, especially across Rx 1. I want to know is there any positive or negative impact of this practice on reformate RONC, RVP and yield?	(5)
10/03/2010	Q:	We want to install the roof cover on our waste water tanks and off gas treating system to reduce the VOC emission and odours. The diameter of our waste water tanks are from 14 m to 32 m. Since the corrosion consideration and strength of existing steel tanks, vendor suggests us to choice the aluminium dome cover. Would you please advise.	(1)
09/03/2010	Q:	What is the typical phenol content in FCC waste water?	(2)
08/03/2010	Q:	In our Once Through Hydrocracker Unit, the Recycle Gas Compressor is surging from 100% opening of the anti-surge valve to 0% without any change in process parameters. It was also observed that just prior to surging the total flow at the inlet of the RGC was also increasing. We have got an amine column at the inlet of RGC suction after HP separator to reduce sulphur loading. But now due to some constraints the amine flow had to be reduced. Can anybody explain the phenomenon?	(3)
06/03/2010	Q:	Can we pinch cooling water return valve in trim cooler? If not, why not?	(5)
06/03/2010	Q:	Can you tell me about the application of pilot operated PSVs? Where or why are these type of PSVs used?	(2)
03/03/2010	Q:	What are the implications of shell side fouling on the pulling of a VCFE/Texas Tower (Platformer) bundle for cleaning? Our client is looking to pull a VCFE which has been in-situ for 16 years and I would like to find out if others have carried out a similar exercise and any impacts fouling may have had on the activity.	(2)
23/02/2010	Q:	What is the use of heat release curve of any heat exchanger?	(1)
22/02/2010	Q:	In a two stage hydrocracker how can the selectivity for middle distillates can be improved at constant overall conversion?	(2)
21/02/2010	Q:	why is sulfiding of naphtha hydrotreater (NHT) catalyst necessary after carbon burning (regeneration) before normalization of NHT operation, when the main purpose of the catalyst itself is removal of sulfur from sour naphtha?	(8)
19/02/2010	Q:	I am working in DHDS. I would like to know the purpose of Carbon filter in Amine Recovery Unit. We use stripped water from Sour water stripping unit as wash water in DHDS over head coolers for dissolving ammonium salts. My query is if there are little amounts of ammonia and H2S in stripped water, and if we use the same stripped water in DHDS, will there be any problem in amine quality or will there be any effect in the quality of acid gas generated from ARU? We are facing the problem of increase in differential pressure across Carbon filter when we take stripped water in DHDS.	(6)
14/02/2010	Q:	We have a SR type reformer. The HDT catalyst (HR 306) was replaced by HR 506 after operating for 12 years and still getting DSN sulphur at about 0.1-0.2 ppm as reformer feed. After replacement of catalyst in April, 2009, the pressure drop was found to be increasing alarmingly and needed opening the reactors in Feb, 2010. On opening the reactor, a thick layer of about 1 ft of Fe dust was observed at the top of the reactor. We are planning to install a magnetic filter now to trap the Fe dust. My query is with the same kind of feed and same type of loading (Sock) why the Fe dust deposition rate has increased to such an extent which was never experienced in the 12 years of operation from 1997 to 2009. The only process is that we are continuously dosing DMDS at the HDT to keep H2S at about 150-200ppm at HDT separator off gas as our Naphtha is very sweet in nature. 1. Can DMDS be the culprit for enhanced Fe deposit at the NHDT reactor? 2. In the latest catalyst loading, grading material was used which was not done in the previous loading. Has the new grading material caused the entire Fe-dust to be trapped at the reactor top. 3. What is the best location for installing a Magnetic filter? 4. Has the Fe-dust has increased due to the ageing Unit which was also observed during the last reformer section catalyst unloading in 2009.	(4)
11/02/2010	Q:	Crude circuit from wharf to Tank and Tank to Units is not insulated. I found seasonal feed temperature change affects on charge heater inlet temperature especially preheat train has been fouled after turnaround. its cost seems a lot. Is the crude line insulation usual practice? Or do you think we'd better add one more exchanger with pinch study?	(5)
10/02/2010	Q:	We have a Sour Water drum (Operating Pressure = 46 kg/cm2(g)). We have installed an angle control valve to kill the pressure from 46 kg/cm2(g) to 6 kg/cm2(g) and because of some slurry particles. System upstream of the Angle valve is designed for 50 kg/cm2(g) and downstream of the valve is designed for 20.5 kg/cm2(g). In case there is an auto control failure of this Angle control valve, what is pressure can be seen by the system downstream of the valve? Is it recommended to increase the Design pressure of the downstream system or provide any protection ( safety valve) downstream of this Angle control valve?	(2)
09/02/2010	Q:	We want to by-pass our de-salters in order to check the consequences with and without desalters on CDU. Moreover we have stopped de-emusifier dosing prior to desalters. What impacts are anticipated in your opinion and what parameters to be monitored in case when there is no desalter in crude preheat trains?	(9)
07/02/2010	Q:	For years, poor quality or hardprocess gasoline boiling range streams such as visbreaker has been a problem for refiners. These materials contain such high quantities of di-olefins, in addition to sulfur and nitrogen compounds, that they are extremely difficult to process in conventional refinery units. The large di-olefin content of such streams renders them extremely reactive or unstable. If an attempt is made to simply hydrotreat these streams in a conventional hydrotreater, the reactive di-olefins form gum which plugs the conventional hydrotreating bed, or less frequently plugs the heat exchanger or heater upstream of the hydrotreating unit. Based on above what are the options refiners have taken to solve this problem. In one refinery Naphtha is routed to Gas Concentration Unit before sending to Naphtha Hydrotreator Unit. GCU debutanizer reboiler tube bundle failed and heavy coke deposition observed. Can Naphtha be routed directly to Naphtha Hydrotreator Unit ? If yes what will be demerits? What are the other options?	(5)
06/02/2010	Q:	Recently we are facing topping unit furnace inlet becomes lower than expected. The normal temperature is 215-220 degree centigrade. But now we are getting only 200-205 degree centigrade. What are the probable reasons behind this? And what measures should be taken to overcome the problem?	(6)
06/02/2010	Q:	When calculating heat exchanger shell thickness according to pressure vessel formula it is found that the required thickness always much less than the original existing exchanger. I want to know the reason behind it.	(2)
06/02/2010	Q:	In our Topping unit generally each heat exchanger has one shell inlet and one shell outlet except reboiler exchanger. We have two such exchangers. My question is why those reboilers have two shell inlets and two shell outlets?	(2)
02/02/2010	Q:	What is the relationship between smoke point and ASTM D-86 of kerosene? Does an increase in IBP increase the smoke point or is it the increase in final boiling that increases the smoke point?	(5)
01/02/2010	Q:	We are observing very high water content in the diesel storage tanks in our refinery. The rundown diesel from the diesel hydrotreater unit has a low water content of 0.05vol% which is within specification. Paraflow additive is injected downstream the DHT unit to improve the cold flow properties in winter and this is the only stream which mixes with the rundown diesel before being routed to tanks. Tanks are also observed to have longer than normal settling time to displace water. Has any refiner experienced emulsification properties or increased water content in the diesel product due to addition of paraflow?	(1)
29/01/2010	Q:	I am engineer in a CDU. The lube vacuum column used stripping steam of 25 psig to 750F, the superheater will go to maintenance. Is it possible during the maintenance to use stripping steam of 50 psig to 750°C in this tower? This tower produce distillates for lube naphthenic and paraffinic.	(3)
25/01/2010	Q:	In a fixed bed semi regen. bimetallic Pt Re reformer catalyst with a target severity 90 RONC for HOBC production, as the cycle proceeds and catalyst ages, what is impact of catalyst ageing on GC of platformer stabilizer column (Debutanizer) off gases?	(2)
21/01/2010	Q:	In a sulfur recovery unit incinerator (where calus process in front end followed by CBA process), presently incinerator control temperature is 605 Deg C. Can I bring down to 550 DegC? What will be the consequences? What will be the ground level SO2 content?	(3)
17/01/2010	Q:	We store the Light Hydrocarbon and LPG in ECTs (Earth Covered Tank). These ECTs are pressure vessels, and storage capacity range from 500 to 4,000 cubic meters. We vent and purge the materials in these tanks to flare before turnaround operation or equipment repair. Is there any package can recover the valued materials? Please advise.
14/01/2010	Q:	There are four SRU units in our refinery. During start up period, we face the SOx emission problem since bypass TGU (Tail Gas treating Unit) operation. We use MDEA as absorbent to H2S recovery in TGU, and bypass this unit during pre-sulfidation stage of start up. On the other hand, we face the SOx emission problem too because sulfur burning out before turn around. Please advise.
13/01/2010	Q:	What is the optimum time for switchover between standby rotating equipment?	(4)
08/01/2010	Q:	In our refinery we are going to replace our Vacuum Distillation Column. Please suggest some designer/manufacturers' names who work in this field.	(1)
08/01/2010	Q:	I want to know the temperature profile of post weld heat treatment for alloy steel like P5, P9. We have some procedures that was used from a long time. I want to know the source or reference of the temperature range. Please suggest the maximum temperature, holding time, temperature raising rate, cooling rate.	(1)
05/01/2010	Q:	In our refinery we are going to change our crude reception line by 36" diameter pipe. The previous line is of 16". The flow rate will be three times higher than the present condition. Our tank has 69 m diameter and 12.5 m height. My question is: will it cause problem in the floating roof tank during reception? Is any modification required? Is there a standard procedure?	(2)
31/12/2009	Q:	In C5/C6 isomerization, we want to process low benzene (3%) and high C7+ (up to 15mol%). Our plant is designed to handle high benzene (up to 5.5%) and 7% of C7+ in the feed naphtha. We are expecting more severity on reactors and hence more cracking. If any one have experience on this, please share especially on yield and cracking. (what %age of isomerization yield will be lowered? and how much cracking will increase)
26/12/2009	Q:	We have our Hydrogen generation unit installed. Compared to all other unit furnaces/heaters, the reformer of HGU is top fired. Why it is so?	(2)
24/12/2009	Q:	Does the top naphtha section of the crude column perform distillation as the other sections do? The Del.P across this section does not seem to be a normal one to me. Top three trays functions at nearly 200mmH2O. I see this section as a condensing/absorption section more than a distiller. Am I correct?	(2)
24/12/2009	Q:	What is the general magnitude of pressure drop across the diffusion type molecular seal in flare stack? How do you calculate the pressure drop across the same?
22/12/2009	Q:	Is there any simple equation for estimating furnace efficiency only by excess air (oxygen) and flue gas temperature?	(1)
20/12/2009	Q:	I'm new to the refining field. We have eletrostatic desalter with three transformers (each of 22KV). and I have questions about this: 1. Why is a single heavier transformer is not used instead of three? 2. We have 2 PSVs on desalter. What is the reason for two PSVs? 3. Why the water injection before desalter is maintained 4.5% of crude charging? 4. What is the function of grills (grids) inside the desalter?	(3)
19/12/2009	Q:	What is meant by vapor and liquid loading? What is its significance?	(2)
14/12/2009	Q:	Our furnace has 4 pass flow. Crude enters the furnace by 4" tube in the convection section. Then it changes its size by 5" X 4" reducer in the radiation section. It again changes its size outside the furnace and now this time by 8" X 5" reducer to a common header of 12" pipe line. This pipe line by a 16" X 12" reducer connected to the 16" pipe line that goes to column. My question is why we are using so many reducers in the process line?	(3)
10/12/2009	Q:	What will be the effect of metal content (P, Na, Ca, Mg, Fe, Cu) in diesel feed on deactivation of DHDS or DHDT catalyst ? Whether demetallation catalyst used in hydrotreaters will be able to absorb these metals also?
08/12/2009	Q:	We have a catpoly hydrotreater that converts olefins to paraffins to produce petrol diesel and jet fuel. I just want to know the reaction/chemistry that should take place in the poly hydrotreater and the kinetics associated?	(1)
07/12/2009	Q:	What is the retiring thickness that leads to the replacement of the process pipes of various schedules? Is there any standard? Or it is based on experience?	(1)
07/12/2009	Q:	How do you calculate "salt point" of an atmospheric crude distillation tower overhead system containing full boiling range naphtha?	(1)
01/12/2009	Q:	For reducing SOx contents in exhaust of Gas Turbine (power plant operations), what could be suitable process? I was thinking about scrubbers, but not sure if it is practical to handle a flow of 30MMSCFD flue gases for scrubbing?	(1)
29/11/2009	Q:	What is the difference between the Eductor and Ejectors?	(3)
29/11/2009	Q:	I am a Shift supeintendent of the CDU unit. We could not stabilize the Brine treatment package - Hydrocyclones to separate the oil and sludge from the Brine of the Desalter outlet. If anybody have the experience regarding the operations of Hydrocyclones (Brine treatment package) in the Brine system, please share with me. If I can get the optimum dela pressure across, it will be helpful; I could not follow the vendor operational guidelines as it is not performing good.	(3)
25/11/2009	Q:	Do anyboby experience fouling in the preheat trains while processing Doba crude in CDU/VDU? I heard that doba crude by nature is a solvency crude which won't foul the exchangers. Is it true? Now we process the Doba crude with minimum of 4% and we want to increase the percentage. What are the constraints while processing Doba and what pecentage can be added with some allowable constraints in hand?	(2)
24/11/2009	Q:	I am working as a superintendent in CDU/VDU unit. We experience increase in the VDU off gasses due to cracking. We inject the Turbulising steam in the inlet and also before exit of the Vacuum heater pass flows. We never adjust the steam flows to see the reduction of cracking. We set high flow in the first tube pass and low flow in the last before tube of the exit. Please share your operational experience in reduction of cracked off gasses from the VDU unit.	(3)
24/11/2009	Q:	I am shift superintendent working in a CDU/VDU unit. We face a problem of maintaining the flow rate of Heater recycle oil (Overflash in Vacuum column which normally contains 50-50 of HVGo-VR). We process the API of 24 and 29. We take LVGO, HVGO and VR products and the HRCO is being recycled back to the vacuum column through heater. The HRCO generation suddenly drops down and increases due to some problem. We raise the HVGO IR and alter the coil outlet temp (COT) of the vacuum column to maintain the HRCO generation fearing that we could end up in coking up the packing bed. Furthermore we experience the packing bed Delta Pressure high across it. Hence we could not raise the temp of COT and reach the deep cut HVGO. Please explain any of your experience into this particular subject.	(5)
23/11/2009	Q:	Cumene is known as isopropylbenzene, it is a flammable, colorless liquid that serves as a component to high octane fuels. Can any body tell me the best practices followed for storing? In the hydrogenation section, if the isopropylbenzene had to be routed to storage what additional safeguards need to be required other than the coolers and N2 blanketed tank?	(1)
23/11/2009	Q:	The needs are: to know the methods used to study corrosion rate in seabed sediment so far I got to know 2 methods but I don't have the details of them: method 1 weight loss method method 2 transplanting and burying method. any information on the above issue could help greatly
21/11/2009	Q:	In our refinery we want to introduce an inspection software for data and history keeping purpose. Can anyone give me suggestion which software will be useful to serve the requirement?
19/11/2009	Q:	We are experiencing corrosion of a side stream in coker fractionator. Earlier used CS pipe was replaced with SS-321 pipes which failed due to pitting corrosion. Does anybody have similar experience? What is the probable reason of the failure?	(3)
16/11/2009	Q:	What are the reasons that are responsible for back fire or reverse flow of flame in the furnace? What measures should be taken to prevent these incidents?	(4)
16/11/2009	Q:	Is there any safety procedure for damper operation in the furnace? Specially in case of failure of damper wire. Is it necessary to keep provision 100% opening in case of damper wire failure?	(2)
16/11/2009	Q:	For FCCU Fractionator bottoms to slurry circulating pumps, is there a preference of side inlet/bottom outlet coke strainers over side inlet/side outlet coke strainers?
15/11/2009	Q:	What is PRD mode in automatic process control?	(5)
15/11/2009	Q:	For the FCCU Fractionator Column bottoms to the slurry circulating pumps, what are the preferred coke strainer types between side inlet/ bottom outlet coke strainer and side inlet /side outlet coke strainer? Are there any precautions to be taken for use of side inlet/side outlet coke strainers?
01/11/2009	Q:	What is main purpose of putting sealing steam in a turbine?	(1)
01/11/2009	Q:	In our DHDT recycle gas compressor primary seal vent flow at non driver end side has reduced to zero while it was previously 5 Nm3/hour. Driver end side flow is running between 30 Nm3/hour. What is the possible reason behind flow reduction?	(1)
31/10/2009	Q:	Refineries processing Crack Naphtha often face Naphtha Hydrotreating Reactor high pressure drop problems. At our refinery we do not have NHT Feed filtration. What are the major steps taken by refiners to prolong NHT operation?	(7)
31/10/2009	Q:	Please advise Heaters Convection Zone finned Coils cleaning techniques or recommend cleaning tools especially for Heaters without soot blowers during turnaround. Which contractors have successfully carried out Heaters convection zone finned oils repair & cleaning? What is the experience/requirement with reference to convection zone coils cleaning for Heaters with soot blowers? When should a refiner plan to clean Heaters convection zone finned coils cleaning?	(1)
31/10/2009	Q:	Is there a heat transfer fluid that can withstand a temperature of up to 600 deg C plus?	(2)
23/10/2009	Q:	We have 4 hydrogen gas cigars (reservoirs). On the inlet and delivery line there are valves which stock is limited. Now we want to buy some new valves that match the following service: operating pressure: 70 to 80 bar design pressure: 130 bar operating temperature: 41 degree Celsius design temperature: 80 degree Celsius The valve will be used for both sides operation. Can anyone help me by informing what kind of valve should be used in this service and preferably the name of valve manufacturer?
21/10/2009	Q:	Is it safe to consider back pressure of 50-70 kg/cm2g when my PSV set pressure is at 229 kg/cm2g? Why are we limited to 3-5 kg/cm2g back pressure maximum when we are designing the HP flare? API 520 part 1 says that I can consider up to 50% of set pressure of balanced PSV, so can I consider up to 100 kg/cm2 g when my PSV is set at 220 kg/cm2g? If not, then what is the reason?	(4)
21/10/2009	Q:	With Increased pressure, Increased COT, Increased Temperature, & low Residence Time in the Coke Drum, we are facing high gas make with increased Methane in the Gas. High Coking is also seen. The API of the Coker Feed is 3.544. Can anyone explain the reasons why we are achieving high amount of Methane make in the process?	(1)
21/10/2009	Q:	How can one predict the composition of off gases from Coker? What are feed characteristics used to get a better prediction of olefins in Coker off gases and LPG?
21/10/2009	Q:	We operate one of the largest cokers in the world and are keen to increase the distillate yield. There is lots of information currently floating around wrt concepts like 'zero recycle', use of additives to reduce coke yield, recycling of LCGO to recover distillates, etc. As zero recycle is promising, our questions are:- 1. Yield improvement obtained with zero recycle? 2. Quality of HCGO post implementation of zero recycle wrt Metals, CCR, particulates, etc. 3. Destination of any extra heavier HCGO stream (from main fractionator bottom) along with quality of this stream. 4. Any issue wrt reliability of the plant post zero recycle option.	(1)
20/10/2009	Q:	VDU off-gases are being routed to LP flare header through a water seal drum (VDU ISBL). It has H2S content around 2 mol%. Is it possible to burn it in VDU furnace? Constraint is higher H2S content. Can we use water seal as amine seal to absorbe H2S? Any other destination of these gases?	(4)
18/10/2009	Q:	We are going to install anchors in our furnace. We get all the required spacing of anchors for cylindrical radiation shell, overhead arch, convection breeching (roof) and stack, but we have no proper data relating to anchor spacing of conical part of the furnace. Can anybody help me in this issue?
15/10/2009	Q:	I have a PSV with a set pressure of 229kg/cm2g. What could be the back pressure I consider while designing the flare header so that it would be cost effective as well as safe?	(4)
06/10/2009	Q:	I would like to know the commercial success rate of the following technologies for recovery of LPG and Natural Gas Liquids (NGLs) from Natural Gas: 1. Absortive Process - AET or similar 2. Supersonic Gas Conditioning Process- TWISTER	(1)
05/10/2009	Q:	I'm researching about paraffin wax oxidation. We're experiencing a phenomenon of lost of colour in the hydrotreated waxes. What kind of oxidation phenomena can I have in a hydrotreated paraffin wax? Has anyone experienced this problem with paraffin waxes?	(2)
28/09/2009	Q:	What is meant by a 'double fired box-type heater'?	(1)
24/09/2009	Q:	What will be the consequence if in a reactor we sock load a catalyst instead of dense load or vice-versa?	(6)
23/09/2009	Q:	We are stress-modelling existing coker drum piping for major piping upgrades, eventually for both static and dynamic modes. We came across the "banana effect" phenomena which is thermal bowing of the drums at quench cycle, and asked that such lateral movements be included with our upper-level piping analysis. We were told to model as much as 1 foot or more of movement, but very difficult to satisfy this. To date, we can only input as much as 4" and above that, results show failure or large overstress. The field says historically there is not much movement at the drum top for years now, which we are quite reluctant to accept. Can anyone share their experiences with delayed cokers in other facilities, in particular, this banana effect? Any related input, especially with piping movements, thermal cycling, etc. should greatly help with our analysis dilemma.
23/09/2009	Q:	There are a lots of air finned coolers and condensers in our refinery. The size of air finned H/X is around 10M*12M, 5-7 layers. We had tried water jet cleaning, chemical foam cleaning, liquid nitrogen cleaning method to clean the air fins, but not satisfied to operation teams. Could you please advise?	(2)
18/09/2009	Q:	As a load bearing member which one is better: H beam or I beam? Is there any design criteria to select the appropriate beam?
18/09/2009	Q:	In catalytic reforming unit what is the significance of N+2A, N+3.5A, and N+A in feed? What will be the minimum value to be required of N+2A for catalytic reforming unit either it is continuous catalytic reformer or semi regenerative reformer?	(6)
18/09/2009	Q:	We have naptha hydrotreater unit. At present unit is under construction phase and unit is being commissioned. We are going to be processing full range naphtha (C5 to 160 deg c) in our naphtha hydrotreater. What would be the recommended reactor inlet temperature and operating pressure for fresh feed cut in to reactor during normal start up?	(6)
13/09/2009	Q:	What is the effect of phenols in desalting operation? We have a stripped sour water having a phenol content of 600 ppm which is to be used as wash water in the upstream of desalter.	(4)
11/09/2009	Q:	What are the typical benefit one could expect from APC implementation in Alky (sulphuric acid based) unit? Also, has anyone used early event system to forewarn operator on reaction section operation?	(1)
11/09/2009	Q:	We have a butamer unit for isomerisation of nC4 into iC4. As our feed has over 2000ppm of olefins, there is an apprehension that u/s dryer beds will get fouled up and will call for early / premature replacements owing to potential polymerisation of olefins. Our questions are:- 1. Is there any refinery that processes with high olefins in the feed stock like ours, if yes, how they are managing the dryer life. 2. Did any refinery use hydroteatment for olefins saturation at such low level?	(4)
09/09/2009	Q:	At the moment I am in the commissioning team of a Hydro cracking construction. We are still in the engineering phase of the project but soon we will start with on site field erection. As I am not familiar with Hydro crackers what is forum advice on inspection matters of this kind of units? What we should look closer in the disciplines of rotating, static and piping equipment. I know the main corrosion mechanisms in hydro crackers is ABS (ammonium bisulphide corrosion) and high temperature corrosion related with hydrogen but I would like to know from forum experience inspection point of view at what matters the commissioning inspectors must take more attention.	(1)
09/09/2009	Q:	Our refinery is an old one. It already spent almost 41 yrs in operation. In this time frame we have changed our distillation column after 30 yrs and revamped topping furnace after 40 yrs. We have changed our exchangers, pressure vessels, tanks and other equipments as per inspection record and suggestion. Is there any rule of thumb regarding how often different types of refinery equipment should be renewed, e.g. after a definite period or number of operating hours?	(3)
01/09/2009	Q:	We are facing the problem of higher crude column top pressure in one of the our crude distillers. The problem gets worsened during hot ambient conditions and when bundles are in fouled condition and the same results in flaring/th'put reduction. The crude tower O/H is equipped with 06 banks of fin-fan condensers with each bank having 04 bundles (Total 24 bundles). The condensing duty is ~ 50 MMKcal/hr at design throughput and crude blend. Now, we want to expand the fin-fan capacity by adding one more bank of 04 bundles to reduce the column top pressure from ~ 1.2 to 0.8 kg/cm2g. However, we doubt that, this may aggravate the process side fouling as the velocity for each bundle will reduce. Also, the piping for new bank will not be symmetric and it may cause new bank to run cold & dirty. The present fouling pattern or performance of banks support this with extreme end bundles (last 8 bundles) taking less load and running colder than other 16 bundles. At the current load the inlet velocity is in the range of 24 m/sec. What should be the min recommended velocity in crude column O/H condnesers? What is the best strategy for expanding the capacity of crude column overhead condensers?	(3)
31/08/2009	Q:	Do any companies use platinum nanoparticles (on zeonites or Al2O3) as a catalyst? If so, what's the yield in comparision with commercial platinum catalysts?	(1)
30/08/2009	Q:	we have hot oil system for heat load to all reboiler, this system running smoothly for long as more than 3 years. The problem now is the level reducing continuously and very very slowly from the system, but there is no leak in the reboiler. What could be the changes? How do we tackle the problem?
25/08/2009	Q:	Does anyone have experience with reactor overhead sampling and analyses? Is this technique in use at all?
21/08/2009	Q:	Before maintenance of crude tank it is necessary to remove the sludge inside tank. We do it by opening the clean out door and facilitate it by water jet, but it takes huge time to clean. is there any easy/quick method to perform the cleaning?	(3)
21/08/2009	Q:	In recent days we have found that in our refinery the bottom/lowest course of the crude tank is severely corroded, especially the lowest one metre. We intend to replace the bottom course without replacing other courses. the course height is 1829 mm. the diameter of the tank is 69 m. the thickness of the bottom course is 20.0 mm and the immediate above course thickness is 17.0 mm. The height of the tank is 12 m. We will also replace the annular plate and bottom plate. Can anyone help me which will be the right procedure to replace the course?	(2)
18/08/2009	Q:	Is there an an agreed percentage of sulphur that determines whether a crude is classed as low or high sulphur?	(3)
15/08/2009	Q:	In Our Recycle Gas compressor turbine seal steam pressure having too much fluctuation. Some time its pressure increase and some time decreases. What are the possible causes?	(1)
12/08/2009	Q:	In DHDT unit suppose benzene converted to cyclohexane and then cyclohexane converted to normal hexane. What is the mechanism of this reaction? How is aromatic converted to cyclohexane then how cyclohexane ring broken and converted to n-hexane?	(3)
11/08/2009	Q:	My question concerns narrow or "light" naphtha. As a broker and trader, most of the product I see has an IBP (initial boiling point) low range of 40 degrees Celsius. I have a client seeking to purchase product with specs stating 35 degrees. I believe this to be highly unusual, or is this a common specification? Please advise.	(2)
03/08/2009	Q:	What is the feed-to-reflux ratio recommended in a naphtha hydrotreater stripper for efficient H2S stripping?	(1)
31/07/2009	Q:	I am doing some research on the Cameron acquisition of Natco and was interested in learning if desalters are sold in the United States. My understanding is that they are installed in refineries when the refinery is built and inasmuch as there is no new refinery construction there are no desalter sales in the USA. Is that correct?	(3)
31/07/2009	Q:	What are the changes required when a hydrogen generation plant feed which is originally designed for naphtha is to be run on natural gas (as a feed)?	(4)
29/07/2009	Q:	What is the best way to calculate Ammonia injection rate in Crude distillation column?	(4)
24/07/2009	Q:	The Delayed Coker Unit (DCU) and the FCC GasCon Dry Gas is treated in an Amine Unit (with MDEA), in order to eliminate H2S, prior to injection into the refinery fuel gas system. However, operational problems have been experienced at the Amine Unit, due to MDEA degradation and the presence of heat stable salts (HSS), among other factors. We know that HSS formation is due to an irreversible reaction between some contaminants (strong acids anions such as formate, acetate, thiosulfate, thiocyanate and chloride) and the amines molecules. Furthermore, we know that the DCU Gas contains anions such as acetate, formate and cyanide. However, we have no available information about the contaminant concentration in the DCU Gas or FCC GasCon Dry Gas. Do you have any information related to a typical contaminant concentration (e.g. strong acids anions) for a DCU and/or FCC GasCon Dry Gas? Moreover, any additional information would be appreciated (E.g. What kind of process do you think would be appropriate for reducing contaminants concentration? We have heard that a water wash stage previous the amine treating could be useful).	(3)
23/07/2009	Q:	Where do hairpin (u-tube) heat exchangers go to die? We are looking for a scrap heat exchanger to use for trials in our workshop in Essex, UK. Can you suggest anyone in the UK who deals in redundant hairpin heat exchangers?
23/07/2009	Q:	How should we size a PSV outlet line when we are considering liquid relief as the determining factor? Our understanding is that if vapor is relieved then for PSV inlet line size, pressure drop is the design criteria and for outlet line size sonic velocity is the design criteria.	(2)
21/07/2009	Q:	For Euro-III diesel why must we maintain density 820 to 845 Kg/cube metre? How will performance be affected if this value is not maintained?	(2)
21/07/2009	Q:	Why must we maintain distillation of diesel 95% at 360 degrees centigrade for Euro-III ? If less or more what is the effect on engine performance?	(2)
20/07/2009	Q:	How can we simulate a flare gas recovery system for a refinery?	(1)
18/07/2009	Q:	What is the minimum safe distance between flare stacks and electric high line? Please specify the related code and standard.	(2)
18/07/2009	Q:	What is the basic difference between a thermal and pressure safety valve?	(5)
17/07/2009	Q:	Is straight run heavy naphtha treated in a merox unit fit to be used as feed in fixed bed bi metallic i.e. platinum rhenium based catalyst, platformer unit for octane improvement?	(3)
16/07/2009	Q:	How can one fix minimum circulation flow and scheme for a pump which is undergoing in revamp, specially when flow is going to reduce after revamp?	(3)
12/07/2009	Q:	What is the limitation of sulfur in a crude classified as a 'sweet crude' or what's the maximum amount of sulfur in a sweet sulfur beyond which it falls in the class of "sour crudes"?	(2)
09/07/2009	Q:	How do you calculate weight hour space velocity (WHSV)?	(3)
07/07/2009	Q:	My company generates regular truckloads of quite pure benzene with under one percent of acetaldehyde and under one percent of a low molecular weight unsaturated ether. We are currently burning it but it should be useful to someone for production of benzene derivatives, such as nitrobenzene or a chlorobenzene. Does anyone know of another company in the southeast US that could make use of it?	(1)
07/07/2009	Q:	How is commercial hexane i.e. hexane with n-hexane content of 40 to 60 %, produced ?
03/07/2009	Q:	One of the observations pertaining to 2 stage desalters is that 2nd stage efficiency remains poor as compare to 1st stage (50 to 60 % in 2nd stage as compare to 91 % in 1st stage) despite trying all necessary parameter adjustments such as Delta P, Fresh water flow, interface level, emulsion checking etc. Is there a means of remedying this discrepancy?	(3)
02/07/2009	Q:	What are the demerits of sending unstabilized reformate from fixed bed catalytic reformer unit directly to a storage tank?	(7)
22/06/2009	Q:	How can we establish the impact of high temperature water vapour on the compressor valve sealing element and its possible contribution to the melting of the element?	(1)
15/06/2009	Q:	In technically evaluating any crude prior to its processing at a hydroskimming refinery, what is the significance of following properties of the crude: Its Reid vapor pressure (RVP) Total acid number (TAN) Mercaptans sulfur H2S Pour point Calorific value (Gross) Copper strip corrosion Conradson carbon residue Kinematic viscosity @ 40C	(2)
13/06/2009	Q:	Our problem relates to treated gas from Amine absorber. Our plant has SPONGE ABSORBER and water wash for heat stable salt. The treated gas H2S varies from 0 to 600 ppm at same amine flow/ temperature and plat throughput. What are the reasons for H2S variation and how do we bring H2S below 100 ppm?	(2)
11/06/2009	Q:	What is the advantage of heavy atmospheric gas oil draw in a crude column? Is it possible to provide a new heavy atmospheric gas oil draw for our crude column operating with 24 trays, diesel draw is between 11th and 12th tray, flash zone between 6th and 7th tray? Column operating pressure is 1.6kg/cm2 top. diesel draw temp is 300 degC.	(1)
09/06/2009	Q:	Which on line process analzyers including NIR and gas chromatograph are installed in DCU, VDU and VGo HDT units?
05/06/2009	Q:	What is the meaning of SOR (Start of Run ) and EOR (End of run) condition? Particularly in naphtha hydrotreating and c5/c6 isomerisation unit when we can say catalyst EOR condition is started?	(1)
05/06/2009	Q:	we are going to set up 1 MMTPA Naphtha hydrotreater in our refinery. Naphtha hydrotrater consist of vertical cylindrical Naphtha charge heater. The charge heater has two pass and each pass contain 32 nos of vertical tube. Our charge heater is in construction stage. For checking mechanical integrity of weld joints in tubes we are going to carry out hydrotest of tubes after placing tubes inside firebox. Also charge heater is part of reactor circuit. Any lumps of water will damage hydrotreater catalyst. 1) How should we remove water and debris from tubes after hydrotest as our tubes are vertical? 2) Are there any alternative methods to check weld integrity instead of hydrotest? I know one option is pigging but we are not going to do it because of cost.	(5)
04/06/2009	Q:	In what situation is a pneumatic test at one kg/cm2 to be preferred to a hydro test at the design pressure of a vessel?	(2)
03/06/2009	Q:	What is the reaction chemistry behind the formation of Ammonium Bisulfide salt and how does the deposition take place with respect to temperature?	(4)
31/05/2009	Q:	what is the purpose of a chimney tray in a hydroskimming refinery's crude distillation column operating at atmospheric pressure?	(1)
31/05/2009	Q:	What are the different causes of pressure drop increment (gradually to maximum allowable limit) in a naphtha hydrotreater?	(2)
24/05/2009	Q:	In order to achieve higher gas oil recovery, we are working on a conceptual project of installing a vacuum flasher on the D/S of VDU. VR from VDU column bottom will be heated and flashed in a separate column having flsha zone pressure lower and temperature higher than that of VDU column flash zone. Preliminary simulations suggests the technical feasibility. We want to confirm that whether such a set-up has been installed anywhere and what may be the foreseen challenges?	(2)
20/05/2009	Q:	We are planning to carry out new Aux. HP steam Boiler hydrostatic test. Currently we do not have any demineralised or soften water available on site except with portable water via water tanker from desalination unit supply by contractor. (New Plant) 1) What type of chemical should be added to this water and in what concentration? 2) How do we dispose of the used water after hydro test? 3) After draining the boiler, how do we dry up the superheater tubes? Is using dry instrument (tool) air acceptable (no N2 easily available on site)?
12/05/2009	Q:	Flow measurement into cokers is traditionally done with DP meters (orifice, wedges , venturi etc). I am trying to get an idea about the maintenance costs associated with DP devices (pressure line purging, purging liquids etc)
12/05/2009	Q:	I read that most of the existing alkylation units use HF in their process and the newer ones sulfuric acid. How is the flow of HF measured - and the H2SO4?
10/05/2009	Q:	In India layout of terminals are guided by OISD-118. Please suggest if Storage tanks for petroleum products class A and B can be kept in the same dyke area. Capacity of tankage is 22,000KL.	(1)
05/05/2009	Q:	The context is the following: - The system is: inlet pipe + control valve + outlet pipe. - The fluid is natural gas - The outlet pipeline is buried. - No outlet pipe insulation. - The minimum allowable temperature in the outlet pipe is -20°C. - The minimum temperature at the control valve outlet flange is about -15°C (worst scenario) The problem is that I need to calculate the length of outlet pipe so that the fluid temperature increase to 0°C. My data are: - Outlet pipe material: carbon steel (L360) - Outlet pipe internal diameter: 570 mm - Outlet pipe thickness: 20 mm - Outlet pipe is buried 1 m deep. - Average air temperature: 11°C - Wind velocity: 10 m/s My questions are: 1. Do you know where can find thermal conductivity data for ground? I know it strongly depends on the ground composition but I don't have anything... 2. Could you please share any Excel spreadsheet to perform that calculations?
19/04/2009	Q:	To avoid surging anti surge controller is provided, while for reciprocating compressor spill-back controller is provided. What is the purpose of a spill-back in reciprocating compressor?	(2)
18/04/2009	Q:	What special earthing is normally provided in the LPG sphere for the elimination of electrostatic charges?	(1)
15/04/2009	Q:	This question is about heated and heatless instrument air dehydration packages. While heated dehydration systems rely on blower/heater combination for regeneration, heatless systems require a dry instrument air stream for regeneration (up to 15%) which leads to a larger compressor to ensure a steady supply of IA. Which of these heated/heatless systems is better and why? Are there significant lifecycle cost and availability/reliability issues to differentiate?
11/04/2009	Q:	Our FCC has a throughput of 1900 Ton per Day. The total gas make of the plant is 24 wt %. The Gasoline make of the Unit is 52 wt %. There is a recycle stream of 8 % from the main column bottom. The Reactor design is having a T type disengager with Rough cut Cyclones. The Riser Outlet Temperature is 496 deg C. We would like to process 5% Atmospheric Residue (AR) in the FCC. Please give a possible implications for processing AR and steps to be taken for processing the same.	(5)
10/04/2009	Q:	If off gases contain nitrogen and they fired in fired heaters how will it affect NOx levels?	(2)
28/03/2009	Q:	What is lube oil supply temperature for any pump or compressor? Like feed pump, makeup gas and recycle gas compressor.	(2)
25/03/2009	Q:	Why do we need to maintain gas oil ratio in our diesel hydrotreater?	(5)
22/03/2009	Q:	Recently there was a case of loss of gas oil cracking unit feed resulting in unit shutdown. During troubleshooting analysis, it was observed that the centrifugal pump feeding the gas oil feed suddenly experienced a drop in the motor amperage a few seconds before the total gas oil flow to the pump started to drop below the minimum circulation flow. The minimum circulation control valve fortunately worked when it started to open to allow the circulation flow back to the pump suction. Everything was checked, from NPSHa of the pump, basket strainer and y-type pump suction strainer, total gas oil and high-pressure reactor feed controllers` transmitters, as well as the pump motor voltage, among others. But none seemed to be identified as the root cause of the unit trip. Is there any other aspects of the centrifugal pump that needs to be evaluated? Any possibilities of internal circulation inside the pump cavity that could cause the sudden pump cavitation? Test runs on the pump's spillback have been conducted, and based on the observation, all including the pump vibration and behaviour of the minimum circulation control valve opening, were considered normal. Could the pump motor amperage drop result in lower suction feed to the pump?	(1)
19/03/2009	Q:	With some experts projecting crude prices to creep back up to $75/bbl by mid-summer 2009, should we expect to see a higher level of refinery intermediates (e.g., heavy gas oil, "lifted" DAO, etc.) being exchanged among "networked" refining facilities?
17/03/2009	Q:	How will impending changes in marine diesel specifications affect bunker and residual fuels? Is there a long-term shift away from bunkers and residuals? Will this result in some niche opportunities for refiners?	(1)
17/03/2009	Q:	Are the declining costs of metallurgy providing an incentive for construction of 2000+ ton heavy-walled hydrocracking reactors? Is the application of advanced manufacturing techniques, such as Cr-Mo vanadium welding, becoming the 'norm' for fabrication of heavy walled hydrocracking reactors? What other developments coincide with new hydrocrackers designed to operate in a highly corrosive environment?	(1)
13/03/2009	Q:	In a particular complex onshore gas plant, flare network purge is via continuous flow of N2 controlled through flow orifices, purge points being located at the ends of all major headers. There are also a few fuel gas purge connections but these are located close to the flare stack. Under normal operation fuel gas purge points are closed, ie no flow. I would like to know what would be the risk of stopping all N2 purge gas and starting fuel gas purge. This would lead to the flare network being purged only close to the flare stack. Rest of the network will have to depend on control valves / other vents for a positive gas flow towards the stack. We can assume for the sake of this discussion that the fuel gas rate is sufficient to safeguard the seal function of preventing air ingress through stack.	(3)
12/03/2009	Q:	In one of our new projects, we have a shell and tube heat exchanger for crude heating from about 15 C to some 70 C using hot water as heating medium. This crude exchanger is located downstream of 1st stage production separator in the stabilization train. The crude is specified to be on shell side, whilst the hot water to be on tube side. (Please note we also have an existing installation where crude is on the shell side and water on tube side, operating for last 15 years without any issues). However, EPC contractor is now proposing to swap the fluid i.e. crude in tubes and water on shell side. Any feedback on the subject will be useful, so as to make a right selection of design with respect to both engineering and operating /maintenance considerations.	(6)
12/03/2009	Q:	We are experiencing excessive backwash frequency on our auto backwash filters (25 micron size) on the feed to the diesel hydrotreater unit.The hot feed is a blend of straight run kero, LDO and HDO which is fed directly from the crude unit with no makeup from intermediate storage. The feed when analyzed indicates a particulate level of about 6 ppm which in my opinion is low to cause such a problem. Has anyone experienced similar phenomena when the moisture levels in the feed are high? Moisture when analyzed was observed to be about 750 ppm in the feed.	(3)
10/03/2009	Q:	Is it possible to efficiently clean asphalt tank cars without excessive tank entry?	(3)
09/03/2009	Q:	Why is a minimum circulation line not provided in some centrifugal pumps? For instance, in our stripper reflux pump it is provided, while in our diesel hydrotreater stripper it is not.	(2)
07/03/2009	Q:	Is there an international specification for LPG especially with respect to ratio of Propane to Butane. Is there any limitation in using 100% Propane as LPG?	(1)
04/03/2009	Q:	What is the exact meaning high/low severity in case of refinery catalytic unit?	(5)
02/03/2009	Q:	In my DHDT (Diesel hydro treater unit), anti surge of recycle gas compressor remain open 20-25% always. Could anyone explain whether it is instrument fault or process problem? How can I rectify it?	(3)
25/02/2009	Q:	What are the merits and demerits of re-using spent caustic from Meroxes back into crude at the upstream of CDU?	(1)
24/02/2009	Q:	Does any one know how to simulate the cylindrical vacuum heater with velocity steam injection at radiation zone, using HTRI? What is the procedure for generating the heat curve and other transport properties for vacuum heater whose process side is (RCO+Slop Wax+ Steam) Reduced crude oil?
23/02/2009	Q:	What are the methods to estimate cracked gas production in Vacuum Column (or Heater)? Are there any correlations in the form of other process parameters? Can anybody suggest the literature regarding this?	(2)
19/02/2009	Q:	We have two sets of desalters and each set has 2 stages i.e., 2 desalters in series. Our crude oil props input to desalter mainly BS&W, API, Salt Content, Filterable solids, Viscosity and Residence time are within (or equal to, in case of R.Time) the design conditions. But we are unable to obtain the desired outlet parameters even though these are within the design parameters. For Ex: Salt ptb (o/l) - Design:1, Desired: <0.4, but actual is 0.6-0.8, like that there are variations in all parameters viz., BS&W, Filterable solids & Oil in water etc. How can we improve these parameters in the existing train so that we can reduce the severe pre heat train fouling that is very frequently happening and overhead corrosion. Would effective demulsifying and anti foulant agents will be helpful in this regard? If so, please recommend?	(2)
15/02/2009	Q:	Why is the cetane index of diesel higher for high sulfur than low sulfur crude?	(6)
15/02/2009	Q:	What is the mechanism of aromatic saturation reaction in diesel hydrotreater reactor (i.e. step by step conversion from aromatic to paraffins)?	(2)
12/02/2009	Q:	A coalescer is required to be installed in straight run kero line of the CDU. What are the requirements under OISD (Oil Industry Safety Directive ) for this? Are there any other safety directive norms that need to be considered?	(1)
07/02/2009	Q:	What is the standard value of SOX & NOX in furnace stack outlet? Are the Values different in case of fuel oil firing and fuel gas firing?	(3)
07/02/2009	Q:	Where can I obtain information about Vacuum distillation unit overhead sourgas minimization? What are the parameters that effect the sour gas generation rate? Are there any correlations available to relate those parameters to sourgas rate? What are the methods and ways to minimize the cracking of reduced crude oil in vacuum unit charge heater? what are the main effecting parameters of fouling the vacuum charge heater?	(4)
06/02/2009	Q:	What are the best preventative measures for avoiding coking in wash bed section of vacuum tower and corrosion of top section of CDU?	(3)
05/02/2009	Q:	In a catalytic reforming unit the fines collection system may contain up to 30% catalyst pills, I would like to know what methods for fines/pills separation exists, along the lines of Density Grading to aid of optimum pills recovery. Also, is there is a better method? What equipment is required and what are the physics involved?	(3)
03/02/2009	Q:	Can anyone reference an article or research that comments on the effect lubricating oil from the makeup or recycle H2 compressors can have on catalyst life?	(5)
01/02/2009	Q:	What are the possible reasons for failure of silver corrosion test during ATF run in hydrotreater unit?	(3)
01/02/2009	Q:	We have a plate heat exchanger as a reactor feed/effluent heat exchanger in DHT unit. this exchanger is very sensitive to debris/catalyst fine/ceramic ball chips.., accordingly a fine mesh (cone shape) is installed upstream the exchanger on the reactor effluent line. This filter is doing great by catching all scales and preventing them getting into the exchanger. However, when the Dp increases across the filter, we have to shutdown the unit and clean it. I'm looking for online cleaning, such as a dust collector, cyclone or whatever thing appropriate. the filter is installed in a piece that is same size as the piping and with no spare to avoid block valves in the reactor circuit.	(3)
31/01/2009	Q:	We have calculated EII for a long period and we have observed it was very clear that capacity and EII directly related to each other. If you go on details to decrease bad effect of low on EII the best way to use VSD for every system. (One pump or fan for each system.) But at this point we have two main doubts: 1. Reliability of the VSDs 2. VSD effect on control system. Are we correct to have these concerns?	(1)
27/01/2009	Q:	What are the chemical reactions taking place in diesel hydrotreater reactors that boost the cetane number, and how can these reactions be maintained?	(3)
24/01/2009	Q:	Are there any methods/systems that can utilize/recover for re-usage gases released into refinery flare system during non emergency periods?	(2)
17/01/2009	Q:	Can we reduce MPT time during startup of hdt unit? (In our case it is usually taken 28-30 hrs after M & I shutdown)	(3)
17/01/2009	Q:	We are facing a lot of back wash filter problems after 3-4 months in hydrotreater unit due to dirty or contaminated material carried along with feed so Is there any possibility of cleaning Backwash Filters during running without taking partial shutdown of unit? In other words I want to know is there any online method of cleaning filter?	(8)
16/01/2009	Q:	If we process High TAN crude, what will be the consequences in ATF Merox Unit? Is there any effect on the ATF specifications?	(1)
15/01/2009	Q:	Which parameter - temperature or pressure - has more impact in a diesel hydrotreating unit in producing higher quality in terms of cetane no and product sulfur?	(4)
18/12/2008	Q:	What is the common kinematic viscosity value for slurry from residue processing in FCC plant?	(1)
18/12/2008	Q:	What is the best distributor for water feed to a atmospheric condensate drum to avoid steam losses to ambient?
16/12/2008	Q:	What reliability issues can the use of high pressure unit charge pumps (multistage centrifugal pumps) in parallel pose to distillate hydrocracking processing ?	(1)
09/12/2008	Q:	antioxidant additives are used for aviation fuel with a maximum permitted dosage is 24 mg/l. What is the reason for this maximum value ? what would be the consequences of adding more than 24 mg/l of antioxidant to jet fuel ?	(1)
06/12/2008	Q:	Why do we have only exchangers with even number of tube passes? Can we use exchangers with odd tube passes like 1-3/1-5/1-7 exchangers?
18/11/2008	Q:	What are the maximum allowable limits for following? 1- Jet Flooding % 2- Downcomer Flooding % 3- Downcomer Froth Backup % 4- Downcomer clear liquid (inch) 5- Weir Loading (gpm/in) 6- Pressure Drop across MV trays (psi)	(2)
17/11/2008	Q:	Can we inject caustic at upstream of De-Salter instead of downstream? What will be the consequences?	(7)
17/11/2008	Q:	What is the procedure to be followed for plate heat exchanger (packinox) pressure test in Continuous catalytic reforming unit.	(1)
02/11/2008	Q:	Sample Probes: How are the vibration calculations done (vibration calculations to ensure that the probe cannot fail to resonance effects / harsh process conditions)? Are there any software packages available to check that the sample probe selected can withstand the process parameters (pressure, temperature, flow, fluid density, etc.)?
16/10/2008	Q:	On the LPG (Liquefied Petroleum Gas) outlet line from the bottom of the storage vessel (Horton sphere or mounded bullet), remote operated isolation valve (ROV) is provided for isolation of the facility in the case of emergency. This remote operated valve shall be fire-safe type conforming to API 607 or equivalent in order to protect the valve from external fire situation. In case of pneumatic operated ROVs, we would like to know whether the actuator system comprising of diaphragm & spring requires fire protection? If it is required, how the protection can be given? Is there any mechanical design requirement for the diaphragm/spring to protect the actuator from external fire case? What is the standard practice?
16/10/2008	Q:	Why is the non return valve fitted on the horizontal pipe line rather than the vertical one?	(2)
23/09/2008	Q:	I am working a project where I am trying detect phase changes. The project consist of detecting phase changes from water to butane by using flow meter density detectors. This idea is only for ideal case, but the reality is that, caustic may be present. Here is where the issue comes. The question that I have is this: what method should I use to detect different phases. For example, mixed water and caustic? mixed Butane and Caustic? Again, the point is to detect phase density changes from water to butane.
08/09/2008	Q:	Generally DMDS is used for hydrotreater catalyst sulfiding during the start up with new or regenerated catalyst. DBPS ( Di-t-butyle polysulfide) is known to be safer than DMDS due to its lower flash point than DMDS and other benefits as compared to DMDS. We like to know the prices of DBPS and DMDS. Which is costlier?	(2)
08/09/2008	Q:	Modernization, expansion or product quality improvement projects in refinery or petrochemical Industry may require additional secondary processing plants and facilities. In such cases, the existing size of main Flare header and also main Flare stack along with the stack height may be limiting requiring revamp of both of them. Based on acceptable radiation levels from the Flare stack, it is required to have a minimum separating distance from Refinery Flare to other facilities (like process units or tankage etc) at refinery & petrochemicals. Is it, from safety point of view, possible to locate the new Flare stack closer to the old flare stack? If so, what should be minimum separation distance between the two stacks? What are the criteria for such case?	(3)
08/08/2008	Q:	Are recent improvements to FCC cyclone technology adequate enough to lower solids concentration in slurry oil down to a level (e.g., < 250 ppm) that the slurry oil can be sold without need for filtering?	(1)
07/08/2008	Q:	In addressing refinery CO2 management, can you comment on CO2 curtailment from on-purpose hydrogen plants through "minimised" involuntary'steam, internal heat recycle and captive integration?
06/08/2008	Q:	Non Edible Vegetable oils contains metals like Ca, Mg, Si, Fe , P etc. and these vary from oil to oil and in ranges from 100 to 500 ppm. We are looking for a process which can remove these metals to a level of <10 ppm. In addition the process should also work towards degumming of the oil.	(2)
04/08/2008	Q:	How effective have membrane separation systems integrated into recent clean fuel strategies been in reducing sulphur levels, octane upgrading, etc.?	(1)
02/08/2008	Q:	What are the different types of high pressure exchangers and which ones among these are better than "Breech-lock" in terms of withstanding thermal shocks arising out of general power failure?
01/08/2008	Q:	How can I design sizing of a jet mixer? what are the factors that determine its efficiency? Can a jet mixer also operate with Nitrogen? And how to calculate the consumption of Nitrogen? Is it better than conventional mechanical agitators for highly viscous fluids with congealing nature?	(1)
01/08/2008	Q:	Can I use a jet mixer instead of conventional mechanical agitator in a tank stored at 55 deg C?	(1)
26/07/2008	Q:	In a hydrogen plant is it possible to use wash water instead of Amin guard to control PH of reflux system?	(1)
24/07/2008	Q:	We are building a grassroots refinery. In refinery we have catalytic reforming unit and light paraffin isomerisation unit for gasoline pool. During startup of isomerisation unit it will require initial dryout and Acid cleaning to remove water and iron rust. Has anyone experience of initial dry out and acid cleaning of isomerisation unit? How long it will take for initial dry out and acid cleaning?
19/07/2008	Q:	How one can derive Minimum Allowable Pressurization Temperature for a typical reactor? What is the procedure to work-out maximum allowable heat-up and cool-down rates for hydrocracking/treating reactor vessels?	(2)
17/07/2008	Q:	Why aren't nano-scale dispersed catalysts for upgrading heavy crude gaining traction in the industry considering that their yields are reported to be >90%?	(2)
16/07/2008	Q:	Is there any commercial process where the reactant is selectively scrubbed to enhance the forward reaction? Is it possible to dehydrogenate propane / butane to respective olefins without having catalyst deactivation problem?
14/07/2008	Q:	In a vacuum system for drying HSD, how safe is using a top pump around to reduce the size of barometric legs and hot well? Considering pyrophoric iron fires since no steam is being used in the process.
14/07/2008	Q:	What is the right feed to an old generation CAPOL unit? Is FCC LPG OK? Or Coker LPG? Is a mix of all LPGs from VBU / Coker / FCC the ideal feed to the CAT POL unit. What is the MS as a weight 5 of feed in a CAT POL unit?
14/07/2008	Q:	What is the typical analysis of a FCC product gas going for Propylene recovery? Please assume an old unit (15 years old). Lower reactor temp. Very less cracked VGO in feed. Lighter VGO with lower CCR. Compare this with modern resid FCC gas analysis for propylene recovery. High reactor temp. High VGO CCR . Larger % of cracked VGO in feed.
13/07/2008	Q:	Can we process Heavy Aromatic Naphtha called "Reformate" Having aromatic concentration about 60 vol % into Hydrocracker unit to saturate aromatics ? Have anyone having experience of the same?
11/07/2008	Q:	How effective are the latest automation & control systems for ULSD hydrotreaters? Are they making a significant contribution in producing on-specification distillate product (< 8-10 ppm sulphur)? What is the feasibility of "extending" these control systems to upstream feed-stream distillation systems (i.e., tighter control of hard-to-remove refractory compounds entering hydrotreater)?
11/07/2008	Q:	How safe is giving a top pumparound in case of a vacuum column considering pyrophoric iron fires etc. The vacuum maintained is approximately 5 kg/cm2 (g). Is there any particular temperature limit for pyrophoric fires as the top temperature of the system is around 80 deg C?
10/07/2008	Q:	are there any aromatic saturation happening in a Hydrocracker unit? What is the favourable condition for aromatic saturation? We have high aromatic naphtha (60 vol %). can we process it through hydrocracker for satration of aromatics?	(1)
07/07/2008	Q:	In general, where has the influence of good fractionation allowed for significant improvements in meeting stringent petrochemical product specifications (e.g., propylene, styrene, etc.) at higher charge rates? Besides the recent improvements to fractionation column internals, what is the extent to which automation & control systems can be leveraged to deliver higher efficiency, run-lengths and resistance to corrosion in product recovery trains?
07/07/2008	Q:	Under what circumstances is it cost effective to revamp the FCC main fractionator so that the amount of heavy FCC naphtha feed to ULSD hydrotreaters can be increased while still meeting finished ULSD product flash and distillation requirements? Are most ULSD hydrotreaters designed with a three-product stripper using a fired heater, or is a simple steam stripper adequate?	(1)
03/07/2008	Q:	This question is related with capacity estimation for safety relief valve for external fire case for heavy oil services. Typical VDU bottoms stream which is sent to delayed coker plant as feed stream is received in a surge drum inside coker plant. Being a heavy stream, the boiling point is high say 550 Deg.C plus. For external fire case, the heavy oil will start cracking and will release the lighter gases. Being a carbon steel vessel, the vessel will start approaching to rupture conditions after temp reaches 400 Deg.C but the material has still not started boiling or not started cracking. How do we protect such equipment from external fire and can anyone guide on arriving/estimating cracked gas quantity? How does one estimate cracking temperature? Please help on sizing PSV for such cases.	(2)
01/07/2008	Q:	We have sulphur guard bed in heavy naphtha stream which is going to catalytic reformer. The guard bed works on Chimisorbtion and is loaded with Nickel and aluminaosilicate based adsorbent. It reduces sulphur content to 0.1 wt ppm from incoming 0.5 wt ppm stream. If Incoming naphtha stream sulphur content increased to 500 ppm, what is the expected life of sulphur guard bed? Also, to what extent can it remove sulphur from stream? Are there special types of adsorbent available to cater for high amount of sulphur in incoming stream? What is the average life of sulphur guard bed?
22/06/2008	Q:	We have a crude preflash column where crude after being heated is flashed. the column has three streams. One is the top which is light naphtha which is taken from the reflux drum via reflux pump as one stream. The other is sent as reflux on temp control The column has a fired reboiler. A side cut is Heavy Naphtha below Hnaphtha cut is a pump around. Bottom is kerosene plus which is separated in another tower. We wanted to reduce the EP of lt naphtha. We carried simulation on hysis and were getting the desired EP using HEPT OF 2 FT for CMR 1 as there is packed bed of 10 ft between LT and H naphtha we were getting five theoretical trays on the plant we adjusted all perimeter as per simulation but we could not get even close to it the ep remained high. Increasing reflux severalfold could not achieve the end point. We took delta p across the bed. It is low and pct flood predicted by Hysis is 16pct far from flood. We reduced capacity but no avail. Could it be low flood which is responsible? We want to check all angles before we open it up. There are no gamma scan facilities available so we can't do a scan. Can someone suggest what angle to look for?	(1)
22/06/2008	Q:	How do you determine the cracking temperature for unknown heavy crudes in Atmospheric heater and vacuum heater? For vacuum heater does this cracking temperature depends on the vacuum and coil steam? Are there any lab methods or correlation methods to determine this?	(1)
21/06/2008	Q:	Is there a noticeable increase in blending clarified FCC slurry oil into No. 6 fuel oil? Since this obviously circumvents the need for blending lighter, higher-value products into the No. 6 fuel oil, how much of an impact on total refinery profitability can be expected? Are some refiners instead opting to use higher percentages of slurry oil as feedstock to a coker unit or a hydrocracker?	(1)
18/06/2008	Q:	Our crude vacuum distillation column bottom pump suction strainer gets full of coke. How can we prevent this?	(4)
16/06/2008	Q:	What is typical heat of reaction (in kcal/kmol of H2 consumed) for hydrodemetallization of vacuum gas oil?	(1)
16/06/2008	Q:	In a hydrotreater plant, water carry over in diesel is giving a problem. Is there any possibility that oxygenates are forming water in reaction?	(4)
12/06/2008	Q:	When processing highly aromatic (>650 deg F material) bitumen derived feedstocks through a refinery, they become saturated to various extents due to the primary upgrading and secondary hydrotreating of these heavy aromatics. Therefore, the refinery's FCCU will need to crack a significant amount of naphtheno aromatic ring structures. In order to crack these ring structures to gasoline and distillate, what catalyst functionalities are required to perform these ring-opening reactions? How do these catalyst functionalities differ from those used in processing more conventional VGO feeds, which involve more paraffinic chain (rather than ring) cracking?	(1)
12/06/2008	Q:	How are existing distillate hydrotreaters revamped to process higher volumes of feedstocks performing? What are some of the latest reactor and catalyst improvements that permit processing higher volumes of FCC LCO, coker naphtha or light coker gas oil through the distillate hydrotreater, and what are the corresponding benefits to downstream naphtha hydrotreater performance?	(1)
11/06/2008	Q:	Is there a rule of thumb for calculating the fuel requirement for a furnace refractory dry out?
05/06/2008	Q:	What is the amount to which oxygen enrichment in a fired furnace helps to improve capacity and efficiency of a plant?
02/06/2008	Q:	For certain standards pertaining to control valves used in hydrogen services, why is it recommended that installation of a bypass (and blockvalve) be avoided?	(1)
28/05/2008	Q:	We've been quoted a revamp time for our FCC unit of 120 days, which is prohibitive. Has any refinery got experience of FCC revamp involving shutdown duration of 35-45 days?	(7)
28/05/2008	Q:	Can someone provide guidelines on the design of a vacuum column for light waxy atmos bottoms? Will it be any different than designing a vacuum column for heavy crude oils with high metals etc> The atmos bottom that we are considering is waxy with no metals and very low sulphur but we have to limit wax in the lvgo so that it is used as diesel.
23/05/2008	Q:	We have local crudes which are very waxy in nature. The reduced crude from these crudes has a wax content of 40 pct wax and 1 pct asphaltene. The pour point is very high requiring cutter and depressant. We were thinking of a thermal process like visbreaking or thermal cracking, but this resid is very light and quite a lot of it vaporises at common visbreaking condition unless pressure is increased substantially. We are trying some pilot runs using makeshift arrangement. Has anyone tried this for light waxy feed and what were the results and operating condition used?
20/05/2008	Q:	Does anyone have experience of, or know how to set up a repair testing point for transportation of LPG by rail within the CIS?
19/05/2008	Q:	What happens if a steam reformer heater (hydrogen unit) is only fed by steam for a long time in stand by mode? Is this action harmful for catalysts?
19/05/2008	Q:	Is it possible to run a terrace wall reformer heater only with one cell? (Heater has two separate cells in west side and east side and feed, steam and fuel gas is split for both cells)
19/05/2008	Q:	We need some info about drying of hydrocracker catalyst by long period recycle gas circulation in case of start up and shut down of hydrocracker unit and problems caused by this phenomenon. Can anybody help us? Is it very harmful for catalysts?	(1)
17/05/2008	Q:	We have two TIC in reformer heater outlet manifolds for temperature control which act on fuel gas of heater. Low limit of these TIC,s are 700°C, but in some cases (i.e start up) we need to control temp. lower than 700°C. One of our operators suggested we change the lower limit of TICs to less than 700°C. Is this possible without any safety and design problems?	(1)
12/05/2008	Q:	How much is the Min. and Max. allowable amount of Hydrazine in the demineralized water closed loops as an oxygen scavenger?
01/05/2008	Q:	What are the conditions leading to brine production in a Catalyst cooler?
29/04/2008	Q:	How does the quality of wash water affect the desalting of crude? what are the parameters based on which quality of wash water is decided for desalting?	(2)
27/04/2008	Q:	How does presence of ammonia in the wash water or crude effects the desalting process? Does ammonia acts as an emulsifier that tends to cause lower desalting?	(1)
26/04/2008	Q:	Just a query about chloride levels reported for produced water (formation water) from different sources. Source-1: 1700 mg/L Source-2: 80,000 mg/L Source-3: 1,17,000 mg/L 1. There is order of magnitude in difference in chloride levels in the various sources above. Can someone from comment/advise on wide difference in the values reported? Is it something to do with method of analysis / units? 2. Any guess value for chloride levels in separator gas. As you are aware process simulations does not help to provide such information? 3. In some cases, it is reported in terms formation water and the values reported are much higher than produced water. Question is whether produced or formation water are not same?
26/04/2008	Q:	What is the industry experience in handling coker gas oil in hydrocracker feed stock? How much absorption of HCGO ( as a wt% in total feed) has been achieved / being designed in existing units / revamps / new units ? Is there an optimum on HCGO portion in Hydrocracker feed mix ? Additional information on experience in critical equipment like Feed Filter / charge pump / Reactors/ RGC / Make Up Compressors / Fired Heaters/ Low pressure section / product treatment etc. would be appreciated.	(1)
25/04/2008	Q:	Is there any non-manual method for cleaning tanks used for asphalt storage? We dilute as much as possible with recirculating hot HVGO, but we have to finish the job removing a several inches layer of sticky asphalt.	(4)
25/04/2008	Q:	I have read in analyzer vendor literature that NOx formation is the indication for best combustion in boilers (than Oxygen in flue gas). But we have to limit it. How far is it correct? can anybody give technical reference?	(1)
24/04/2008	Q:	We have a sour water stripper which is used for stripping produced water coming with crude. There is a filter ahead of the stripper. Both the stripper and filter suffer from sticky asphaltene creating operating problems. We are talking to chemical vendors who claim they can inhibit asphaltenes from depositing on the filters and the packing. The filter is actually a strainer with .0.99 mm mesh to keep out particles greater than about 1mm. Are there any other methods which can solve this problem?	(2)
23/04/2008	Q:	We have dual fired furnace. The FG generated in the process is used to run the furnace. Of course we switch over to fuel oil when such gas is not available, say, during start up. However of late, we have faced frequent burner blockage by carbon particles and sometimes a fireball coming out of the furnace. Due to this we are unable to run the furnace in fuel gas. However we have not noticed any carbon particle accumulation in the FG filters. Can anyone help us from similar kind of experience?	(3)
18/04/2008	Q:	what is selectivity and conversion in catalyst bed reactor and can anybody explain me about LHSV in reactor?	(3)
11/04/2008	Q:	What is the governing case for dispersion whether it is high flow and low wind velocity or less flow and low wind velocity?	(2)
11/04/2008	Q:	Kindly confirm what will be man hours required (all discipline viz, process, mechanical, electrical, piping, structural, instrumentation, safety and pipelines ) for carrying out CONCEPT stage of engineering (approximate number)
11/04/2008	Q:	As per OISD-STD-118, petroleum storage tank shall be located in dyked enclosure with roads all around the enclosure. Now our products are Class C i.e. excluded petroleum products and some of them are stored in atmospheric tank and some of them in Vessels, so do we need dyked enclosure for products stored in "VESSELS" ? or any other sort of protection is required in event of spill over scenario. Thanks in advance.	(2)
08/04/2008	Q:	How significant is the increase in hydrogen consumption in facilities where higher amounts of heavy VGO and heavy coker gas oil feeds are being treated in the gas oil hydrotreater? To what extent can catalyst selectivity help mitigate hydrogen consumption while treating these feeds?	(1)
06/04/2008	Q:	Certain refiners are feeding vacuum residue and FCC slurry oil to the coker unit as part of their strategy for reducing (or eliminating) fuel oil production. To this end, what operational and hardware changes should be made to the vacuum tower and FCC main fractionator?	(2)
02/04/2008	Q:	We are facing a problem in the plant of piping noise and vibration exceeding the design limit. Can anybody tell me which software is used during the project inception stage for calculating the same. Whose responsibility is it: process or piping department?
01/04/2008	Q:	In what type of situations can we use 2 solenoid valves in series and when do we use 2 solenoid valves in parallel ?	(2)
01/04/2008	Q:	What is the problem in providing PSVs only on the feed line in a distillation column and not providing any PSV on the overhead line, given the fact that the PSVs on the feed line have been designed for reflux failure case?	(1)
31/03/2008	Q:	We have a conventional Thermal Hydrodealkylation plant (THDA) in our Petrochemicals complex, designed to primarily produce benzene for LAB production. The feed is taken from the refinery reformate stock. Our sister petrochemical company approached us to inquire about our capacity to produce cyclohexane fron our THDA. We are writing to find out if such a proposal can be accommodated in the THDA unit and the required modifications to the existing facilities.A quick guide to anticipated changes to process operating parameters will be highly appreciated.
27/03/2008	Q:	We have a corrosion problem in our hydrocracker unit high pressure fans (reactor effluent air coolers). There are three water pumps in the unit and by using one pump, water injection rate is 20m3/hr (by design). Recently, we encountered corrosion in the fan tubes and shut down unit five times in one year for repair. Sulfur and Nitrogen content of fresh feed is a little above design. Can anybody help us? Might it help if we increased water injection, using two pumps simultaneously? Has anybody experience in of this?	(8)
25/03/2008	Q:	We are relocating a refinery which has a lot of control valves missing Are there companies which can supply old but fully refurbished valves meeting quality standards?	(1)
24/03/2008	Q:	We are experiencing falling of coke particles from the refinery hydrocarbon flare stack of late during sudden increase of gas flow subsequent to operation of dump valve of hydrocracker. We would like to know whether such incidents have occurred elsewhere ? If yes, what are the probable reasons and how can they be mitigated ? It may be noted that flare gas velocity during dump valve operation is well below 0.5 Mach.	(1)
20/03/2008	Q:	dP across Gasoline merox reactor is shooting up. Considering the financial year targets, Outage of the reactor in the near future is of remote chance. Is there any chemical which can be used online for washing of Gasoline Merox reactors?	(1)
13/03/2008	Q:	In our hydrocracker the reaction takes place only in the first bed. We're running on a reduced load. Is it possible to bring down the reaction to the next 3 beds and also to get a correct profile in the reactor?	(1)
11/03/2008	Q:	We don't have any clear procedure in our operating manual about degassing procedure for hydrocracker reactors. Can anyone help us?
07/03/2008	Q:	What is Best Practice for showing the Isolation Valves for PGs, PTs,FTs, PDTs, LTs and Level Standpipes/Bridles in detailed engineering P&IDs?
06/03/2008	Q:	We are looking for a new method and equipment for steam reformer heater catalyst loading, along the lines of Spiraload. Can anybody help us?	(2)
04/03/2008	Q:	How do you calculate the efficiency of a centrifugal compressor driven by a variable speed steam turbine? What equations are to be used and what input data are required from the running unit? How do you correlate this with performance curve given by the equipment manufacturer?
04/03/2008	Q:	We have a problem with our Hydrocracker VGO feed filters resulting in frequent backwash operations due to high Del P. Can you please ascertain the reason for the same as we do not get any FeS or suspended solids in the backwash stream analysis. Is it because of the asphaltenes as we process deep cut VGO (360-580+ degC) along with Heavy gas oil?	(8)
03/03/2008	Q:	The US EPA now permits blending of RFG gasoline without oxygen. Has any refiner or blender reported the ability to meet RFG gasoline emissions constraints without the use of ethanol or other oxygenated component?
03/03/2008	Q:	Can we eliminate reactor outgasing step in a hydrocracker unit during shut down procedure? Is this action depend on reactor metallurgy? In new units, is this procedure necessary?	(1)
28/02/2008	Q:	While processing heavier and cracked feeds in Diesel Desulfurisation units the decativation could not take place due to metals poisoning or coke deposition. What are the views on predominant factor? If it is because of coke, is the only solution to make the feed lighter and process less of cracked stuff? However, if poisoning is due to metals, could a small bed of demet catalyst in the first bed prolong the life of the catalyst?	(2)
27/02/2008	Q:	It is a primary requirement of instrument change-over philosophy that all existing field control systems, safety systems and associated field instruments should remain fully operational and functional in their current configuration until new systems are fully installed, tested and and commissioned successfully. The existing field instruments and associated plant control and safety systems will be operating in parallel with the newly expanded facilities until commissioning is successfully completed. My question is that how parallel operation is possible and how the old system is decommissioned.
25/02/2008	Q:	We have an occurrence where a small topsides ESD is reported to be "passing". Leakage rate has not been quantified. Our performance standard requires topsides ESDVs to provide effective isolation of hydrocarbon inventory on demand. Our assurance routine is to ensure valves close within specification time through system wide ESD test or crediting of unplanned ESD. Valve passing is only picked up through operational experience (eg preparing for intrusive work). Typically, we treat performance standard deviations as safety critical corrective work and ensure mitigating measures are in place until work is completed. Question that has been raised is what leakage rate on topsides SDVs should be considered an unacceptable leakage rate? How do other operators treat incidents like these? What standards are there to check the leakage rate?	(1)
20/02/2008	Q:	In the query below, gas also contains CO2 which can help to maintain an acidic environment. This query is regarding an upstream processing facility. In a Sour Water stripper, maintaining pH of the water phase is essential for stripping. H2S tends to ionize in a basic environment, an acid environment is most conducive to keep H2S as an un-ionized form good for stripping. Published literature suggests maintaining a pH of 5 to 6 for H2S stripping. Please note refinery sour gas generally also contains NH3 along with H2S and a desirable pH for stripping H2S and NH3 is 8 and is therefore different from the sour water above which does not come from a refinery and does not contain any NH3. I have the following questions in this regards, a) For sour water containing only H2S and no NH3, what chemical is added prior to stripper for maintaining pH for good stripping? Also, is the chemical injection system similar to other chemical injection systems, eg Corrosion Inhibitor, i.e tank and pump? b) Does partly ionized H2S not maintain its own pH without addition of chemical? c) What is the typical column top operating pressure and is it maintained by a PCV? Are higher operating pressures any good for stripping considering the fact that they will reduce the column diameter?	(1)
17/02/2008	Q:	What are the factors influencing the NHT catalyst performance towards nitrogen removal? And what is the most severe poison metal?	(3)
17/02/2008	Q:	Can anybody tell me the cause of increasing algae and bacteria in a cooling water system?	(2)
13/02/2008	Q:	I am looking for a heat exchanger specialist or a manufacturing company who would be able to help with tube bundle failures which are very regularly occurring on a horizontal thermosyphon reboiler on a sour water stripper. We are suspecting a mechanical problem like vibration or something else. The tubes are failing in six month to a year even if they are upgraded to stainless steel. The problem does not seem to be related to corrosion from the process fluid.	(2)
12/02/2008	Q:	What developments are taking place for catalytic photosynthesis of Carbondioxide to Oxygen and carbohydrate or useful products which can be used to reduce CO2 emissions from Furnace stacks?	(2)
12/02/2008	Q:	Quite a large amount of Hydrogen is consumed in desulphurisation of fuels and hydrotreatments for product quality improvement which generate Hydrogen sulphide. A more economic process is required like catalytic decomposition of hydrogen sulphide into hydrogen and sulphur and the separation of the products of said decomposition to H2 and Elemental Sulphur. This would enable recovery of costly hydrogen and same can be re-utilised in the process of treatment. Are there any catalyst development taking place for such purposes?	(1)
11/02/2008	Q:	Recently we have started using refinery slop oil as reactor overhead quench. Due to presence of some water (free as well as emulsified) in slop oil the fractionator operation is getting disturbed. What is the most efficient way of separation of water from slop oil (along with proper tank preparation)? Would putting a coalescer in slop oil service (density varies from 0.8 to 0.9) be effective?
07/02/2008	Q:	Have hydraulic power recovery turbines (HPRTs) been included in any of the most recently completed or planned projects where core hydrocracking and amine regeneration is required? Besides energy savings incurred with the installation of an HPRT, how significant a role with HPRTs play in reducing CO2 emissions?
07/02/2008	Q:	What are some of the most successful turbomachinery management systems in use today? What documentation is available to show where turbomachinery/compressor expected life has been extended?
06/02/2008	Q:	In a cross country gas pipeline, is any passive fire protection system like fire water storage / pumps / hydrant network or fire water spray system etc are required to be installed at compressors stations and delivery stations? If, so what cooling rate should be considered for fire fighting system?
06/02/2008	Q:	In a multi product cross country pipeline pumping petroleum products like Motor Spirit & Diesel etc it is required to trip the running booster pump in case of accidental closure of the motor operated valve on the pump discharge line to prevent no flow condition of the pump. Due to difference in density between Motor Spirit (0.73) and Diesel (0.825), is it required that the trip setting pressure to be reduced during Motor Spirit pumping & increased during Diesel pumping? What is the standard practice w.r.t discharge pressure trip setting in such multi product pumping?
05/02/2008	Q:	Heavy crude oil desalting in electrostatic desalter designed for normal crude creates interface level problem and results in more oil in desalter effluent. What best operating and design practices should be followed to overcome this problem?	(8)
05/02/2008	Q:	In a Refinery, huge quantum of low level energy is wasted in cooling water. Other than exchanging heat of Crude overhead column vapour with cold crude oil feed, what are the technological developments to minimise such energy loss?	(3)
05/02/2008	Q:	Shutdown Control valves are required to isolate the process in case of emergency. What are the testing parameters and acceptance values of such control valves testing? Details of time of closures, time of openings, tightness criteria, fire rating etc would be helpful.
05/02/2008	Q:	As one of the layer of protection, we find that in normal Hydrocarbon process furnaces, explosion doors are provided to minimise the effect of furnace pressurisation from explosion inside specially during startups. But the same are not considered in Gas/Naptha cracker furnaces. Why?
05/02/2008	Q:	In Sulphur Recovery Unit, provision for Nitrogen purging exists in the Reactors to prevent temperature runway. In certain cases it has been found that manually operated isolation valves are provided on Nitrogen injection line instead of remote operated isolation valve. This makes it difficult to take immediate action and control the temperature excursion. What is the design practice by process licensors?
04/02/2008	Q:	What are the problems faced in Overhead of CDU Condenser, and why do such problems occur?	(3)
04/02/2008	Q:	Thermal safety valves (TSVs) are used in hydrocarbon lines and are supposed to take care of pressure generated from increase in line temperature. However, problems like passing and also joint leaks creates problems. Any experience to improve reliability of TSVs would be useful.
01/02/2008	Q:	How can I use prefractionation treatment to improve the quality of kerosene?	(1)
27/01/2008	Q:	What are the basic differences, advantages and disadvantages, between controller using ordinary 4ma-20ma system and Foundation fieldbus?	(1)
24/01/2008	Q:	Is there a process to make Carbon Black Feedstock (CBFS) from natural Gas?	(2)
22/01/2008	Q:	Can anyone tell me the average time it takes to clean a flare line please?	(4)
22/01/2008	Q:	How much does it cost a refinery and/or petrochemical plant to produce 1 (one) tonne of CO2? I have worked out how much CO2 is produced per barrel of oil, for example, but now want to put a monetary value (or indeed an energy value) on to that tonnage of CO2. Thanks.
21/01/2008	Q:	How can I predict HETP for Sulzer's structured packings (BX, Mellapak 250.Y or EX) when reflux is not total, i.e., when some distillate is taken off (e.g., 10, 20, 50 or 75 %)? Does it depend on the mixture to distill or is it an inherent characteristic of the packing?	(2)
19/01/2008	Q:	We have a topping plant with capacity of 40,000B/D. One Desalter is installed before the Flash tower with emulsion breaker injection on the inlet pipe for desalter. We are looking for the suppliers for overhead corrosion control chemicals (NALCO filmer & Neutralizer) for the flash tower and the emulsion breaker	(1)
18/01/2008	Q:	Glycerol is produced as by product in the Transesterification process for Biodiesel. Please give your views on the following: 1. What are the present practices for handling this glycerol? 2. Glycerol can be converted to Hydrogen. Have processes and catalysts been developed? 3. Does the above process for Glycerol to Hydrogen require any treatment of glycerol. 4. Any views/suggestions on the handling of glycerol?	(2)
11/01/2008	Q:	What is temper embrittlement? What are the factors/parameters which affect it?
09/01/2008	Q:	What could be the cause of gas dryer losing efficiency very fast? Our dryer is molecular sieve dryer.
08/01/2008	Q:	We have a butterfly pressure control valve (PV) in hydrogen product line from hydrogen unit to hydrocracker unit without any block valves and bypass line on it. Another PV on this line is fitted in split range arrangement with first PV and connected to flare line. Can anybody explain about the design criteria about installation bypass and block valves on a control valve?	(2)
08/01/2008	Q:	Could the use of a 70 micron Element Filter (Wedge Wire), in place of a 25 micron Filter, for the filtration of hydrocracker unit feed, result in any problems?	(4)
06/01/2008	Q:	Can semi conductor based heating and cooling systems be used to save energy in the refining of crude oil and gas condensates? What are the limitations?
05/01/2008	Q:	Recently we are observing low lubricity in Ex. Merox treated ATF. The merox unit is UOP. The ATF lubricity Ex. CDU unit is 580 to 600 microns whereas after merox reactor and thereafter it remains 710 to 740 microns. Can anyone please advice what will be the possible remedy to improve lubricity Ex. Merox unit?	(1)
05/01/2008	Q:	Do high nitrogenous crudes like plutonio, oman blend, zafiro play a role in deteriorating ATF saybolt color (KMU product), and if yes and if any detail analysis for such color instablity has done in the past, what is the correlation?	(2)
03/01/2008	Q:	How can we redesign a crude preheater for better efficiency? What is the pinch point of the total crude preheater train using simulation package hysys? How can we do pinch analysis in hysys?	(1)
23/12/2007	Q:	Double drum crude fractionator has frequent leaks in the crude/overhead heat exchanger. The water used is recycled water from the second drum boot containing H2S in high concentration. The purge-out is only to the quantity to the steam added to the fractionator. Is this water, rich in H2S, being used for washing the main cause of the leak? Will stripped water make up in good quantities help? If yes, how much stripped water should be used? The vapor entry in the condenser is side entry instead of the usual top entry. Could this change in configuration also be the reason?	(2)
21/12/2007	Q:	Is there any pilot plant scale-up data available WRT conversion of recalcitrant fibrous biomass materials into "reasonable" quality biocrudes? Do FCC or hydrotreating catalysts suppliers have any specific concerns WRT feeding small amounts of biocrudes into FCCUs or hydrotreaters?	(1)
19/12/2007	Q:	What is combined feed ratio? How is it calculated for a two stage hydrocracking process in a hydrocracker?	(1)
09/12/2007	Q:	We have a glycol dehydration unit to dry the wet gas by TEG. During the regeneration of TEG, we use natural gas as stripping gas to reach the purity of 99.9wt% of TEG. Note the process under temperature and pressure of 204C and atm. We have a proposal to substitute the stripping gas with N2 gas. Please could any one tell me if the N2 will adequate for that process or not ?
07/12/2007	Q:	Can someone tell me how a Millisecond Catalytic Cracker works?	(1)
06/12/2007	Q:	What is a cascade system and how does it work? What is the difference between a cascade system and loop operation?
03/12/2007	Q:	Would you please share experiences of C4/C5 alkylation? We are adding C5 alkylation to existing C4 alkylation. It has a SAR (Sulfuric Acid Regeneration) unit. Do they usually feed C4 and C5 mixture? 1. Is there any existing unit which is fed C4 and C5 separately? C5 segregation cause any problem? Licensor says we consume less Sulfuric Acid than mixed feed. 2. With segregated C5 feed, spent acid strength will be 87wt%. Are there any critical reliability issues due to lower spent acid strength? - reactor corrosion - spent acid disposal and regeneration unit (SAR)	(1)
29/11/2007	Q:	What is the present global alkylation capacity? And the largest alkylation unit?	(5)
29/11/2007	Q:	While designing a railway wagon gantry for POL unloading with LPG, how much distance should be kept from POL pipelines with respect to LPG unloading? Any special precautions to be taken ?
27/11/2007	Q:	How many, and what capacity, Gas To Liquid (GTL) plants are currently operational or under construction?	(2)
26/11/2007	Q:	I am still amazed at how few companies are using Inverter Technology on Fans and Pump applications. Is there much demand for European manufactured Inverters within Petrochemical industry?
26/11/2007	Q:	Is there any refiner using variable speed drivers in electrical motors of process units?	(4)
26/11/2007	Q:	During the percolation process, the tower is packed with bauxite, then when saturated, cleaned with naphtha, then unpacked and the bauxite burned in a rotary oven at 550 Centigrades. Then the bauxite is re-activated with sulphuric acid and the tower packed again. Is this correct procedure?	(1)
24/11/2007	Q:	Can anyone tell me about the possibilities for the online cleaning of heat exchangers?	(5)
22/11/2007	Q:	We want to install block valves on subheaders of pilot line in a big terrace wall reformer heater (8 block valves for 8 subheaders) for maintenance. According to safety rules, is this action is safe? Is there any standard or design note for this action?	(1)
09/11/2007	Q:	Please tell me the process for handling slop oil. How much is produced per barrel, what is the process to separate it back to crude, disposal, economics of this issue? What are the problems oil refineries face with this issue?	(1)
09/11/2007	Q:	We are looking for a chemical which can be used for removing Ni and V and also Fe from our hydrocracker unit feed (MVGO+LLC) by injection it to feed. Also we think it is possible to eliminate these metals from crude oil source by adding chemicals to crude oil and removing metals in desalters. Can anyone help us?	(1)
07/11/2007	Q:	We are processing reduced crude oil coming out from CDU bottoms (35 API). The feed to the coker has a typical API of around 15 to 17.5. The chamber is operated at 2.2 to 2.3 kg/cm2g and the furnace coil O/L temp maintained at 498 deg C. The recycle ratio is maintained at around 0.9-1. Now we want to increase Naphtha and c3/c4 yields, which are 8% (95% volatility 110 deg C) and 4% respectively. Please suggest which way to approach.	(2)
06/11/2007	Q:	How do carry out model discrimination in Fortran for hept-2-ene reforming over platinum-alumina catalyst?
05/11/2007	Q:	What are the practices followed at various refineries for hydroprocessing catalyst management. Is fresh catalyst charges or regeneration the preferred option? If regeneration is being followed, then for how many cycles? Are refineries maintaining stocks of different types of catalysts?	(1)
04/11/2007	Q:	What methods are available for the removal or reduction of Phenol from a vacuum heater?	(2)
04/11/2007	Q:	What Catalyst is good to upgrade a small Diesel Hydrotreater rated for 2200 BPSD in 1980, and what charge rate will be OK if available cut is Straight Run 315-371ºC TBP from Cusiana Crude? As per assay at http://portal.ecopetrol.com.co/categoria.aspx?catID=37 This cut shows ºAPI= 29.3, Sulfur= 0.271 %Wt, Total Nitrogen= 0.0202 %Wt, Cetane Index=55, and AROMATICS by SHEL method as follows: 3.52 %Wt for monoARO, 2.95 %Wt for diARO, 4.04 5Wt for TriARO, and 0.58 %Wt for TetraARO. Reactor volume is 4 feet ID x 18 feet T/T rated for 900 psig at 800 ºF. The unit has been hydrotreating 3000 BPSD of a kerosene cut. Hydrogen comes from the reformer (81.5 %H2), but pure hydrogen can be purchased locally if required for makeup.	(1)
04/11/2007	Q:	Neutralizing amines are used in PH control in crude distillation over head systems to minimize corrosion. While studying the possibility of using such amines for Vacuum distillation several contradictory points of view appear some approving and some objecting. What do you suggest? We currently use ammonia in our vacuum distillation.	(2)
01/11/2007	Q:	please tell me some features of hydrocracking of heavy vacuum gas oil.
01/11/2007	Q:	What are the pre-requisites and requirements for a petrochemical plant start-up (e.g., naphtha-based steam cracker complex)? Does the facility’s effluent treatment plant need to be operational before actually feeding hydrocarbon into the complex?	(2)
25/10/2007	Q:	What systems are available for H2S removal from crude oil (39 API gravity crude measuring 50 ppm H2S at the wellhead)? Where can I obtain quotes for pricing the necessary equipment?
24/10/2007	Q:	How do you measure the CO2 emissions from your plant and can you specify the CO2 emissions from individual pieces of equipment?	(2)
24/10/2007	Q:	Do you believe that specialist cleaning of equipment e.g. WHRU, heat exhangers etc can have an impact on the carbon emissions of your plant?
23/10/2007	Q:	With the high capital cost of gasification projects, what combination of incentives are required to expand worldwide gasification capacity? In addition to petcoke and coal-based feedstocks, what are some other feedstocks that are being targeted for gasification?	(3)
14/10/2007	Q:	in our refinery we treat the LPG produced from the FCC unit by extraction merox unit. In the pretreatment to remove the H2S from LPG, the absorber shows low efficiency. What is the problem? (the abs. press. 10.5 bar amine conc. % vol.= 19 regenerator good efficincy H2S in rich Amine = 0.034 WT%)	(2)
13/10/2007	Q:	we have problem in our FCC unit where the temperature of the dilute at regenerator is higher than the temperature of flue gas, and we have abnormal loss in catalyst...can anyone help?	(6)
09/10/2007	Q:	What are the various processes for Recovery of Sulfur from Acid Gas?	(4)
08/10/2007	Q:	What technical steps can be taken to reduce ethanol production costs?	(1)
27/09/2007	Q:	What are the practices followed for the disposal of Hydroprocessing catalysts: 1) Regeneration, 2) Metal recovery, 3) Disposal and replacement with new catalysts. Is there any economic comparison of various options? Who are the potential vendors working in different areas?	(4)
26/09/2007	Q:	On a crude unit we have a fired heater with thermocouples on each pass exit. We have experienced thermowell fractures twice in the past three years. When the thermowell breaks, crude oil starts leaking. It is very unpleasant situation because of the high crude oil temperature and possibility of fire. The possible cause of the fracture is pass vibrations on heater outlet. I find in the literature that if there is the possibility of a thermocouple fracture it is necessary to install a valve on the thermowell end and in case of fracture it is possible to close valve, cut wires and stop leaking. Does anybody know of a manufacturer or solution for this problem?	(2)
19/09/2007	Q:	Please advise on reduction of ammonia emissions from a fertiliser plant. Our emissions from a urea plant stack is about 150 ppm, and we need to reduce them to 50 pp to comply with EPA regulations. I know some plants are provided with an acid washing system. I would be grateful for advice from anyone with experience in this field.	(1)
17/09/2007	Q:	We have a conductivity loss problem in Jet Fuel produced from a Merox Unit. Any experiences about the conductivity lost in Jet Fuel after Stadis 450 addition, will be very precious for the determining and finding the solution.	(2)
16/09/2007	Q:	What is the best method for hydrogen management in the refinery? can you provide a brief description of this method, an example of a refinery using and what they've gained from it.	(2)
16/09/2007	Q:	In the crude coluumn , I want to put one more side draw. To allow for draw tray, how much tray does one have to actually remove from the column to accommodate this modification?	(1)
16/09/2007	Q:	If my gasoline pool is not limited by Rvp, then is it advisable to go for a isomerization unit if I have iso pentane availability. Iso pentane RON is 83.5 and isomerate is 87.5	(2)
16/09/2007	Q:	Is Gasoline RON predicted by volumetric blending of different chemical species like MTBE, FCC gasoline, hydrotreated naphtha, straight run naphtha accurate? Is there any way to quantify the interaction between these chemical species and its effect on RON?
15/09/2007	Q:	What processes are available for 1. the separation of oil from slack wax 2. the separation of wax fom residue wax 3. the hydrogenation of wax?	(1)
13/09/2007	Q:	Where can I find diaeclectrical constant for refinery products (gasoline, kerosene, diesel, raffinate etc.)?
11/09/2007	Q:	Can anybody share experiences of using high efficiency trays in an isostripper column?	(1)
07/09/2007	Q:	Outlet naphtha stream from tower in catalytic reforming unit that inlet in convection furnace can't shut down during catalyst regeneration. How we can solve this problem with least changing and regenerate catalyst and shut down tower at the same time?	(4)
07/09/2007	Q:	What technologies are available to reduce the VOCs from the truck loading? Our truck loading is bottom loading type.	(2)
07/09/2007	Q:	What is the factor of amount of particulate in the flue gas from boiler? The fuel of boiler is fuel gas and fuel oil from the Olefins plant.	(1)
06/09/2007	Q:	We are experiencing an increasing loss of heat exchangers efficiency. Therefore, we would be interested to know if there is any "on-line cleaning technology" that does not require to shutdown the distillation unit.	(4)
06/09/2007	Q:	I am working in a solvent extraction-based unit for benzene production, we opened the unit’s extractive distillation column after a year of operation to troubleshoot the reasons for high pressure drop (2 barg), where we found a thick layer of heavy, coked material on each tray. Feed for the unit is reformate from a CCR unit (4% benzene). What are the possible reasons for this?”	(4)
06/09/2007	Q:	I am looking for a complete wireless control system solution enabling us to have a smooth plant with no, or just a few, signal cables coming from the site to the control room. Are any of the well known DCS vendors offering such a wireless, yet reliable, data acquisitioning system?	(1)
06/09/2007	Q:	How I can calculate the production life of a polyethylene (gas phase) plant and, theoretically, what is the production life in years of Bp polyethylene gas phase technology polymerisation plant annual capacity 225,000 ton. HDPE and LLDPE?
06/09/2007	Q:	Please advise on the design and operating temp and pressure for the cryogenic tank of LPG. The composition of LPG is Propane:Butane is 0:100 and 50:50.
06/09/2007	Q:	In the off gases from our vacuum distillation column hydrogen % has been up to 30-35% by volume.This vacuum unit is mild severity dry distillation with designed VGO end point of 510 deg C. The overhead boot water PH also remains on the lower side (~5) even though the neutraliser is added in large quantities (more than 100 ppm). The same neutraliser has used earlier for the same type of crudes. Has anyone had this type of experience? What may be the reason for the same?	(1)
06/09/2007	Q:	We have a fractionator overhead receiver in the hydrocracker unit without any PSV on it. We want to know why the designer didn't put any PSV on the receiver. Please introduce a good and practical refrence for this matter, if it is possible.	(2)
06/09/2007	Q:	We have experienced frequent leaks and failures of Plate Heat Exchangers in our Sour Gas Treating Units. We have tried varying gasket materials and operating procedures but the maximum MTBF is 6 months. Specs are as follows: Service:Rich/Lean Amine Solvent Heat Exchanged: 24.07 Gcal/h Operating Temp: 86.6/111.3 - 130.8/98.6 (cold - hot side) Operating Pressure: 8.9/8.3 - 1.8/1.2 (cold - hot side) Gasket: EPDM No. Plates: 254 Can anybody suggest alternative approaches or provide advice on type, materials, procedure etc ?	(1)
05/09/2007	Q:	Many concerns are being raised about ethanol and other biofuels because of the high amount of energy required for successful fuels synthesis. Some reports suggest that more energy (from natural gas or electricity) is required than is contained in the product fuel. Can you point to definitive papers on this issue?
05/09/2007	Q:	What is the status of the first commercialization projects using solid alkylation catalysts?	(3)
05/09/2007	Q:	We are trying to add heat to the front end (feed stream) of a vacuum unit (part of a crude unit) and wonder if anyone has done this in recent years by using skid mounted equip of some sort or small "package" units of exchangers/heaters, etc. We only want to do this on a temporary basis, say for 4-6 months	(1)
05/09/2007	Q:	How can we improve fluidizing in a stand pipe regenerator FCC?	(1)
05/09/2007	Q:	my question is related to an Isomerization unit. In a highly moisture sensitive Penex unit, what is the recommended practice to dry out the exchanger/system after the hydrotest of an exchanger in case of Leakage?	(1)
05/09/2007	Q:	We were producing Aviation Turbine Fuel (ATF) by desulphurising 140-240 deg. cut kerosene through a Kerosene Hydro Desulphurisation Unit (KHDS). The electrical conductivity of ATF was maintained around 300 pS/m by injecting antistatic additive (Stadis 450) at a concentration of 1mg./lit in the product. Two years back we started producing ATF through the ATF Merox unit as well and are injecting Stadis 450 at the same rate from Merox Unit. But when the percentage of ATF produced from Merox Unit is going up to around 60% the conductivity of ATF drops down to around 150 pS/m (the marketing company require a minimum of 200 pS/m, even though the specification is 50-450 pS/m in ATF). What could the reasons for the drop in conductivity?	(3)
05/09/2007	Q:	Why do certain FCC Units need to use CO-promoters?	(3)
05/09/2007	Q:	Who is suppling continuous process for Bio-Diesel plant?	(3)
05/09/2007	Q:	What kind of additives are recommended for injecting in crude while processing high TAN crudes to prevent corrosion and fouling of preheat train / exchangers in general. Please provide commercially available additives / supplier details.	(2)
05/09/2007	Q:	In a Crude distillation unit using hot reflux and with a two stage desalter, repeated corrosion has been found in the Crude / Overhead vapor exchanger leading to tube failure. The crude /Overhead vapor exchanger is the first exchanger in the crude preheat train which heats the crude received from storage (at ambient temperature) using hot vapors from crude column. The MOC of subject exchanger is carbon steel and continuous dosing of filming amine, neutralising amine and wash water (stripped sour water used as wash water) is done. The exchanger is a horizontal floating head shell and tube with vapor on shell side and crude on tube side. The crude processed is Middle East. What are the possible causes and remedies to overcome repeated tube failure?	(5)
05/09/2007	Q:	What is the best method for return pure hydrogen from H.P off gas of hydrocracker unit to input of this unit (pure H2 gas)? Do you think the membranes system is the best and economic for this application?	(4)
05/09/2007	Q:	I am working in a Butadien Extraction Unit. Can you tell me the major safety aspects to be considered in a Butadien Plant?	(2)
04/09/2007	Q:	What is the highest cut point (95% ASTM D1160) which can be done with Resid vacuum unit producing a high vacuum gasoil to feed a distillate single stage hydrocracking unit? What can be done in the hydrocracking unit to reduce the impact on the cycle length of such a heavy vacuum gasoil?
04/09/2007	Q:	Our hydrocracking unit is cycle length limited by the pressure drop build up in pretreating reactor. The pressure drop build up is caused by a deposition of iron sulfide at the top of the reactor. I want to know what can be done to solve this problem?	(3)
04/09/2007	Q:	What are the typical steps to follow for the revamp of a hydrocracking unit? What is the typical duration for each step?
04/09/2007	Q:	Is designing wash section critical in vacuum column if my objective is to get only asphalt from vac column bottoms? VGO we will be selling as fuel oil. Now it is a dry vacuum column. Is it possible to convert this into a wet vac column? I am able to match the Flash zone temperature with HTSD data for RCO without assuming entrainment as mentioned by Golden in Deep Cut Vacuum feed characterization article. So can I assume the actual entrainment would be zero?	(2)
23/08/2007	Q:	What instrumentation and related analytical systems are available to ensure that high-volume biofuels production conforms to regulatory specifications in markets such as Europe and North America?	(1)
17/08/2007	Q:	In our naphtha hydrotreating unit, iron contents in stripper overhead boot are being reported on higher side for the last month. So far we have tried the following: 1. Increased corrosion inhibitor injection from 3 wt ppm (design) to 7 wt ppm. 2. Replaced the corrosion inhibitor 3. Cold condensate injection in reactor effluent increased from 3 to 5.5% of feed. But iron contents are still high (2~3 ppm). What could be the possible cause and what is the solution?	(4)
08/08/2007	Q:	What procedure should be employed to ensure that FCC-LPG is on-spec for sulphur and mecaptants (and to meet copper corrosion specs) immediately following startups from turnarounds or outages? Are there any additional best practices for treaters?	(1)
06/08/2007	Q:	In certain gas processing installations, we find that the Pressure Safety Valves (PSVs) on demethaniser, deethaniser and ethylene towers vent directly to the atmosphere. Is this acceptable practice or should PSVs always be connected to flare systems? What is best practice for routing of safety valve discharges of such columns handling lighter hydrocarbons?	(6)
06/08/2007	Q:	In the FCCU, the main fractionator bottoms slurry settler typically has a pressure safety valve (PSV) for over-pressure protection. Is this PSV sized to relieve pressure from water vaporization that might occur during start-up as the system is heating up?	(1)
02/08/2007	Q:	What is the plant downtime requirement for the revamp of typical Hydrocracker (Once through or Two stage)/Hydrotreater units? How can it be estimated during revamp design finalisation/preparation and what are the ways to scale it down to minimum possible?	(1)
31/07/2007	Q:	Who are the catalyst manufacturers for the process of Hydrogenation of Vegetable oils ? What precautions should be taken while handling and processing vegetable oils?	(4)
31/07/2007	Q:	Can you provide a comparison between various types of gasifiers (based on different types of feeds)? Which gasifier is best suited for High Ash Coals? Which gasifier is best suited to the FT process (GTL)?	(2)
31/07/2007	Q:	We have been observing bowings in Radiation coils of a Naphtha Cracker Furnace for ethylene production. What technological improvements in furnace design and coil orientation and coil support system might be available to minimise the bowings? What process and inspection monitoring is needed to minimise bowings in operation? What are the effect of side burners? Generally the Cracker furnaces are not provided with explosion doors? In such case how can box overpressurisation be prevented? Please share best practices in interlocks in Cracker furnace operation.	(1)
31/07/2007	Q:	What are the processes available for removing 1,3 butadiene from Butene-1? Who are the licensors and what points should be considered in process selection?	(1)
31/07/2007	Q:	We are currently reviewing our position regarding the bulk loading and unloading of LPG (Liquefied Petroleum Gas) at tank wagon gantries (rail) in the oil terminal. Our existing provisions specify that LPG rail loading/unloading gantry shall be located on a separate rail spur and shall not be grouped with other petroleum products. In this context, we like to know the following: 1) What are your guidelines for loading/unloading of LPG at a tank wagon gantry ? 2) Can LPG be loaded/unloaded with other petroleum products e.g. Motor Spirit (MS), High Speed Diesel (HSD), Naphtha at the same gantry? 3) Whether loading/unloading of both the products is permitted in the same Gantry with only one product loading/unloading at the same time, i.e When LPG is being loaded other products are not loaded, and vice versa We would appreciate your views on loading/unloading of LPG and POL products in the same rail spur.
31/07/2007	Q:	Due to processing different types of crude oils at a petroleum refinery, the density of ATF (Aviation Turbine Fuel) produced varies wildly resulting in layering in storage tanks. This is not acceptable and there is apprehension that if a jet nozzle is used in the storage tank and is subjected to circulation, the electrostatic charge will accumulate (considering low conductivity of ATF) and would be unsafe. Do you experience such problems? If so, how you prevent or correct the layering problem? What method and precautions are taken? Please confirm whether use of a jet mixer in the tank for ATF circulation would be wise.	(1)
31/07/2007	Q:	Recycle gas compressor of CRU had ammonium chloride salt deposition in its impeller vanes during regeneration activities. Can we wash the rotor with DM water or steam condensate without opening the machine. If yes, can you suggest some guidelines?	(6)
30/07/2007	Q:	What are the best methods for unloading sulphur recovery unit catalyst from a Claus reactor?	(1)
30/07/2007	Q:	Fusel oil is generated in Crude Methanol purification/distillation. It has about 50% water and balance is various alcohols. To use it as a burner fuel is very taxing as the mass flow rate is very high compared to the fuel heat value. The question is - How can this mixture be concentrated in an economic manner such that the water component is removed? This concentrated Fusel oil shall have much higher heat value and it shall improve burner firing efficiency.	(2)
28/07/2007	Q:	What processes are currently available to recover precious metals from spent catalysts?	(1)
28/07/2007	Q:	What role does oxygen availability play in controlling FCC regenerator NOx emissions? What regeneraor design improvements are recommended for minimizing NOx emissions?	(2)
28/07/2007	Q:	What analytical techniques are recommended for predicting FCC regenerator NOx emissions and monitoring NOx additive performance?	(2)
28/07/2007	Q:	How can process reconfigurations and reactor enhancements improve hydroprocessing catalyst performance?	(3)
24/07/2007	Q:	What are some of the most appropriate technologies for upgrading residue?	(3)
24/07/2007	Q:	With several recent refinery incidents resulting in unexpected plant shutdowns and even fatalities, more attention is being focused on safety and reliability programs. In this regard, how often should gas-monitoring instruments be tested and calibrated?	(2)
24/07/2007	Q:	How is pre-burning of spent hydrocarbon process catalysts accomplished?	(1)
24/07/2007	Q:	How does pre-burning influence precious metals returns from spent hydrocarbon process catalysts?	(1)
24/07/2007	Q:	Catalyst vendors differ in their philosophies for catalyst stacking vs homogeneous systems. Which is best?	(1)
24/07/2007	Q:	How is the success of catalyst loading and startup measured?	(1)
24/07/2007	Q:	What is the feasibility of using gas turbines in olefins plants as process compressor drivers?	(1)
24/07/2007	Q:	What processing capabilities should refiners have in place if they plan to process heavy sour Canadian crudes?	(1)
23/07/2007	Q:	How can the capacity and efficiency of an existing deisobutaniser be increased?	(3)
23/07/2007	Q:	What are the more attractive isomerisation configurations and catalysts available to meet the growing demand for light paraffin isomerisation? What can be done to lower the equipment cost, such as the recycle hydrogen compressor?	(4)
23/07/2007	Q:	What are the opportunities for pinch technology in crude distillation units?	(2)
22/07/2007	Q:	What potential opportunities are available for gasification of refinery residues?	(1)
22/07/2007	Q:	Are there any recent alkylation projects that you can comment on where mass transfer efficiency improvements showed significant reductions in required acid consumption? Also, what recent improvements have resulted in reduced water wash or caustic wash requirements?	(5)
22/07/2007	Q:	Can you comment on one or more unit-specific cases where additives reduced NOx emissions by up to 80%? In other cases, what conditions existed where "only" a 20% NOx reduction was observed --- and what (if anything) was done to further reduce NOx emissions?	(3)
22/07/2007	Q:	What role does oxygen availability play in controlling FCC regenerator NOx emissions? What regenerator design improvements are recommended for minimising NOx emissions?	(3)
22/07/2007	Q:	Can you comment on advances in tray and packing design software for modelling mass transfer and heat transfer effects in a fractionation tower? Can you briefly site any recent refinery or petrochemical product-recovery optimisation projects where actual separations were accurately simulated?	(2)
09/07/2007	Q:	What are the most effective SOx reduction technology improvements the refining industry is investing in? What is some of the latest feedback on their performance, particularly with regard to their effect on FCCU maintenance and operations?	(3)
09/07/2007	Q:	What are some of the recent advances in corrosion and fouling control technology that are being applied in the industry? Where in the processing industry are these programmes most effective?	(5)
09/07/2007	Q:	Can you comment on some of the most important aspects of recent orders for compressors and turbines? Also, with a large backlog of orders for new equipment, what are the most effective condition-monitoring and asset reliability programs for maintaining the performance of existing rotating equipment?	(3)
09/07/2007	Q:	What are the most important automation and control components being incorporated into new projects to help operating companies increase capacity and meet higher quality specifications while reducing recycle and energy costs?	(3)

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