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30/03/2021
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Q:
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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?
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(5)
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24/03/2021
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Q:
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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?
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12/01/2021
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Q:
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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?
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10/01/2021
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Q:
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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?
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(1)
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13/12/2020
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Q:
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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?
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(7)
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23/11/2020
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Q:
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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?
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(4)
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06/11/2020
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Q:
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Can we route stripped sour water to a cooling water circuit?
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(5)
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19/09/2020
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Q:
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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?
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(10)
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15/08/2020
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Q:
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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.
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(3)
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15/08/2020
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Q:
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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 ?
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(3)
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30/07/2020
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Q:
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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)?
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(1)
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02/07/2020
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Q:
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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.
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(2)
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15/05/2020
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Q:
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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?
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(4)
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09/03/2020
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Q:
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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?
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(1)
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26/02/2020
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Q:
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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
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(4)
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19/02/2020
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Q:
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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?
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(5)
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18/02/2020
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Q:
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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.
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(8)
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30/01/2020
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Q:
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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?
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(2)
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05/01/2020
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Q:
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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?
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(3)
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07/10/2019
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Q:
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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?
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05/10/2019
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Q:
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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?
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(1)
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01/10/2019
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Q:
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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.
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(2)
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26/09/2019
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Q:
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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
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(6)
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14/08/2019
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Q:
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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.
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(1)
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15/07/2019
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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?"
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(1)
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13/07/2019
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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)?
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17/06/2019
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Q:
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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?
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(2)
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24/05/2019
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Q:
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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?
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(7)
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07/05/2019
|
Q:
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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.
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14/03/2019
|
Q:
|
what is the role of DMDS in adding to the platformer unit feed?
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(4)
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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 ?
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(2)
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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?
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(3)
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28/12/2018
|
Q:
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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.
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(2)
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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.
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(3)
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|
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?
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(3)
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|
31/10/2018
|
Q:
|
In VDU we are facing problem in HVGO SECTION, that HVGO pump suction strainer periodically choking?
What’s the causes?
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(6)
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|
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?
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(2)
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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?
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(3)
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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?
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(4)
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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?
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|
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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
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(6)
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16/07/2018
|
Q:
|
What are the materials that can corrode 321s stainless steel in an aromatics plant producing paraxylene?
|
(2)
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16/07/2018
|
Q:
|
How do we improve the efficiency of a fired heater running on fuel gas and an fd fan?
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(8)
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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?
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(1)
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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?
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(4)
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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?
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(1)
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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?
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|
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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 .
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(6)
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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?
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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)
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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?
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(2)
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24/07/2017
|
Q:
|
Is a microbiological assay for storage tanks necessary?
|
(3)
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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?
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(2)
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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?
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(4)
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18/04/2017
|
Q:
|
Are there analytical techniques to quantify hydrocarbon content in amine solutions ? These cause serious foaming problems.
|
(1)
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|
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....
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(7)
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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.
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(3)
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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).
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(5)
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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?
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(3)
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11/03/2017
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Q:
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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.
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(3)
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01/03/2017
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Q:
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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?
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(4)
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16/02/2017
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Q:
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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.
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(3)
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14/02/2017
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Q:
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What is industrial practice of caustic dosing in desalted crude? And what should be optimum dosing in ppm?
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(4)
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07/02/2017
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Q:
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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?
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(7)
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04/01/2017
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Q:
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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?
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(2)
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27/12/2016
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Q:
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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?
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(6)
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01/12/2016
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Q:
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Any practical solution for polythionic acid corrosion in furnaces? We are finding difficult to implement NACE RP0170 standard.
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21/11/2016
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Q:
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What are the industrial practices being followed in refineries to mitigate polythionic acid corrosion in furnaces?
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(3)
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20/09/2016
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Q:
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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.
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(7)
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05/09/2016
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Q:
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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
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(6)
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12/08/2016
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Q:
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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.
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(2)
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27/07/2016
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Q:
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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)
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(3)
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06/07/2016
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Q:
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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?
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(6)
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26/06/2016
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Q:
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How do we calculate the weight percent for NH4CL in the stream?
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(1)
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30/05/2016
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Q:
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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?
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(2)
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17/05/2016
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Q:
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Why does Chloride stress corrosion cracking and PASCC only happens in Austenitic SS?
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(1)
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11/05/2016
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Q:
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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?
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(6)
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11/05/2016
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Q:
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Can someone share experiences of corrosion in alkylation units ? How do you control it ? Do you add chemicals for the same?
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(3)
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03/05/2016
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Q:
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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?
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(4)
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16/04/2016
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Q:
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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?
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(7)
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16/04/2016
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Q:
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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?
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(2)
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13/04/2016
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Q:
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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.
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(2)
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05/04/2016
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Q:
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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?
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(5)
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15/03/2016
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Q:
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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?
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(3)
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10/03/2016
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Q:
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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.
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(1)
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03/03/2016
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Q:
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Does increasing CDU load have an effect on overhead corrosion?
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(1)
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26/11/2015
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Q:
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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?
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(1)
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13/11/2015
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Q:
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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?
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(1)
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22/10/2015
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Q:
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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.
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(1)
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02/10/2015
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Q:
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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?
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(2)
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28/08/2015
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Q:
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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?
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(5)
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30/05/2015
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Q:
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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.
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(2)
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05/05/2015
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Q:
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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?
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(6)
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05/04/2015
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Q:
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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?
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(2)
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20/02/2015
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Q:
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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?
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13/02/2015
|
Q:
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Any refinery experience with mercury contaminated crude oil processing from corrosion point of view?
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(3)
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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?
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(1)
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14/01/2015
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Q:
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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.
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(4)
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23/12/2014
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Q:
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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?
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(1)
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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?
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19/11/2014
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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.
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(1)
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24/09/2014
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Q:
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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.
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(3)
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18/08/2014
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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?
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(2)
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17/07/2014
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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.
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(1)
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23/06/2014
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Q:
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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.
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02/05/2014
|
Q:
|
What are the pros and cons of adding Caustic at the upstream of Desalter?
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(2)
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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?
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(4)
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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)
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|
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)
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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)
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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)
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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?
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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?
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05/02/2014
|
Q:
|
Is there any SO2 production due to decomposition of Sulfolane use as a solvent for aromatics extraction?
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(2)
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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?
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(5)
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25/12/2013
|
Q:
|
What is salt point at crude overhead?
|
(1)
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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.
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(1)
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07/12/2013
|
Q:
|
What the causes of naphtha diluted in water boot of overhead? visually water boot carbonized and foaming.
|
(1)
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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?
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(6)
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05/11/2013
|
Q:
|
What are the main constraints in proper corrosion inhibitor selection for CDU (naphthenic crude oil)?
|
(1)
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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?
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(1)
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11/09/2013
|
Q:
|
We are not using wash recycle system in CDU. Is there any drawback to that?
|
(2)
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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?
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30/07/2013
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Q:
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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?
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27/06/2013
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Q:
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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?
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(2)
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11/06/2013
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Q:
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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?
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(1)
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20/04/2013
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Q:
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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?
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(2)
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12/03/2013
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Q:
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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?
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(2)
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02/01/2013
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Q:
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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?
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(4)
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04/10/2012
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Q:
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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?
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27/09/2012
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Q:
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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?
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26/09/2012
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Q:
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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.
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(7)
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17/09/2012
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Q:
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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?
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(3)
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17/09/2012
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Q:
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What is the expected life of fin tube of overhead air cooler of Atmospheric distillation unit?
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(1)
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17/09/2012
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Q:
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What is the expected life of polyurethane seal of floating roof storage tank?
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16/09/2012
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Q:
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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 ?
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25/07/2012
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Q:
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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?
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(5)
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17/07/2012
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Q:
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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?
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(2)
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30/06/2012
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Q:
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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).
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(1)
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20/04/2012
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Q:
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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.
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(3)
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22/03/2012
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Q:
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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 ??!!
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(1)
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17/03/2012
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Q:
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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?
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(3)
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10/03/2012
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Q:
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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.
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(2)
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13/12/2011
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Q:
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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?
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(5)
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25/11/2011
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Q:
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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?
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(1)
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26/10/2011
|
Q:
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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?
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(2)
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12/10/2011
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Q:
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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.
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(1)
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09/08/2011
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Q:
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What are current views on twisted tube heat exchanger configurations in refineries, particularly in comparison with conventional shell and tube configurations?
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(7)
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25/07/2011
|
Q:
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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.
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(3)
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07/07/2011
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Q:
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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.
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(3)
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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?
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(3)
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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?
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(3)
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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.
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(4)
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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%.
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(5)
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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?
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(2)
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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)
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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?
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(4)
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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.
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(3)
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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)
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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.
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(6)
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25/07/2010
|
Q:
|
Are variable speed drivers ever used in pumps?
If not, why not?
|
(4)
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06/07/2010
|
Q:
|
What is the best way of judging the efficiency of a desalter?
|
(6)
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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)
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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.
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(5)
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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)
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18/05/2010
|
Q:
|
Does injecting wash water ahead of preheat exchangers improve desalter efficiency?
|
(3)
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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)
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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)
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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?
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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.
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(2)
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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?
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(9)
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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?
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(6)
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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)
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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)
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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)
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|
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)
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|
07/12/2009
|
Q:
|
How do you calculate "salt point" of an atmospheric crude distillation tower overhead system containing full boiling range naphtha?
|
(1)
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|
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
|
|
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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)
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|
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?
|
|
|
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)
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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)
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29/07/2009
|
Q:
|
What is the best way to calculate Ammonia injection rate in Crude distillation column?
|
(4)
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|
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)
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|
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)?
|
|
|
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)
|
|
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)
|
|
17/11/2008
|
Q:
|
Can we inject caustic at upstream of De-Salter instead of downstream? What will be the consequences?
|
(7)
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|
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)
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|
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?
|
|
|
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)
|
|
27/03/2008
|
Q:
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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?
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(8)
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17/02/2008
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Q:
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Can anybody tell me the cause of increasing algae and bacteria in a cooling water system?
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(2)
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04/02/2008
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Q:
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What are the problems faced in Overhead of CDU Condenser, and why do such problems occur?
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(3)
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05/01/2008
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Q:
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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?
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(1)
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23/12/2007
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Q:
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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?
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(2)
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04/11/2007
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Q:
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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.
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(2)
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06/09/2007
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Q:
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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?”
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(4)
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06/09/2007
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Q:
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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?
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(1)
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05/09/2007
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Q:
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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?
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(5)
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17/08/2007
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Q:
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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?
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(4)
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31/07/2007
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Q:
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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?
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(6)
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09/07/2007
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Q:
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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?
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(5)
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