Q & A > Instrumentation, Automation and Process Control
Date  Replies
10/04/2021 Q: Which is a better option to control firing in the furnace: connected temperature controller with fuel gas controller; or connected temperature controller with low selector?  
18/02/2020 Q: A boiler to produce low pressure steam
• Boiler has a rudimentary design. • Total volume is 1 m3
. • Check valve, pressure and level indicators are present. The check valve opens when the required pressure is achieved. It
can also be manually operated. • Mode of operation of boiler is unchanged- Half of the boiler volume filled with water, then fired. Steam builds up to the
required pressure. When the required pressure is achieved, check valve opens letting out steam. Once steam generation
begins, level of the water in boiler is maintained and continuous operation is achieved. • A flow measuring device is installed upstream to measure steam flow rate. • The start-up requires 352 seconds. • Due to severe clogging, boiler is swapped with a temporary one. The new boiler is double the size of the previous one.
The heat input rate and the check valve characteristics remain unchanged. • 400 seconds after firing the new boiler, it is observed that the pressure indicator is faulty. The level in the tank has shown
little deviation and the check valve has not opened. • What would be the most safe and efficient course of action? The boiler has emergency PRV, and is functioning at one
fourth of the pressure it is built to handle, and the maintenance of the clogged boiler will take 6 hours. If the issue with
the pressure indicator was diagnosed 1200 seconds after firing, with the check valve still being closed, would your
course of action have deviated from the previous one? If so, how? 		(1)
05/02/2020 Q: Hello,

In a CDU/VDU unit a Desalter is provided downstream of the crude charge pump. What should be the design pressure of this vessel?
Should it be crude charge pump-shutoff pressure or should it have a maximum operating pressure of vessel + 2 kg/cm2g, similar to the design pressure of the other pressure vessel?

It may be noted that this vessel is protected with a PSV. The conservative approach is to design this vessel for pump shut-off however this will lead downstream piping and equipment to be higher class which has cost impact.

Please suggest what is the practical approach and why?


 		(2)
12/11/2019 Q: Hello, In our hydrogen production plant we have our own steam generation system that produces 36 bar of steam at 390 degree C temperature. Steam produced in the steam drum has a continuous blow down vessel. We noticed that the conductivity analyzer goes so high that it reaches to NAN sometimes as it automatically reaches to its normal values without any external steps taken by us. We are curious about this automatic adjustment of conductivity in blow down. We have checked the instrument as well, but there is no issue with the analyzer. It is to be noted that the BFW is mixed with condensate separator before pressure swing adsoprtion. The condesate water first goes to degasifier and then mixed with demin water and then pumped to steam drum where steam is made. From couple of days pH of condensate is very low due to low inlet temperature due to dissociation of carbon dioxide, which made pH low. Kindly tell us if there is any reason for high conductivity as per our case. (1)
27/05/2019 Q: How do you calculate actual flow rate of Fuel Gas from the flow meter reading?
In our process plant we have Fuel Gas FTs which gives us reading in Nm3/hr and we want to calculate from this reading actual fuel gas flow taking into account temperature, pressure and density corrections.
Which is the most accurate formula for calculating flow rate? What are the best practices followed by other refineries in order to calculate the fuel gas flow, do they apply temperature and pressure correlations? Pressure or density which is better to take in account? 		(3)
01/05/2019 Q: In our Delayed Coker Unit (DCU), we have a Feed Preheater which is a Balanced Draft Fired Heater. The Draft of heater is continuously hunting whenever the stack damper is fully closed so we are operating the same with stack damper 15% open.
Also the Excess Oxygen & Draft are on the higher side in this condition.
What can be possible cause for the same & possible solutions? 		(5)
01/03/2019 Q: In a naphtha stabilizer, top tray (tray 46) temperature is controlled by the reflux and the bottom tray (tray 3)temperature is cascaded with the hot light gas oil flow (reboiler's hot medium). Top pressure (overhead vapor pressure not the OVHD drum pressure) is controlled by the removal of non-condensed vapors from OVHD accumulator. Here, when I increase the bottom tray temperature, top pressure is getting increased slightly (very minimum) and then OVHD vapor pressure is getting decreased faster. Can anyone explain this phenomenon? Note: Distillation tower - 48 trays column; OVHD product - LPG; Bottom product - Stabilized naphtha. (4)
12/02/2019 Q: What is the deltaP value changing limit(+/-) into the fuel line during the leak test for crude oil furnace burn with natural gas. Is there any calculation method, standarts extc?
NFPA 86 says in a table A.7.4.9, can we use these values? 		 
20/05/2018 Q: We are using born heaters for CRU unit where all heaters inlet lines are covered with ceramic fiber Jacket as air seal purpose but few outlets pipeline from radiation section are not covered. Currently bluish flame is observed coming out from gap/clearance between the outlet pipe and and heater shell casing pipe during night time. What could be the reason for that (from 3rd Heater which has no convection section but has common stack with 1st & 2nd heaters) ?
Another day in the same heater, red hot spot at the inlet of pilot line (pressurized ) was observed and became normal just after the pilot air line had been isolated/closed. But at the pilot inlet found little flame coming out from pilot fuel gas line and disappeared when pilot fuel was isolated. Although pilot should remain close just after the main burner lighted but in our case we keep the pilot in on position all the time. What could be the reason of this red hot spot?
We have VFD operated blower , some time blower noise becomes very high and try to reduce the noise by adjusting the VFD speed . So, what could be the reason for high sound ? 		(3)
28/09/2017 Q: What are the criteria for sizing a restriction orifice?  
10/05/2017 Q: We have platforming heaters tubes of alloy 2.25 Cr-1Mo (vertical tubes) .
The maximum design skin point temperature 595c while the limiting design metal temperature 650c as per API 530.
What is the maximum temperature we can reach it above the maximum design and below the limiting design to avoid the oxidized of the metal? 		(5)
21/04/2017 Q: How can I find the amount of flow passing through a control valve at a given output? (3)
06/04/2017 Q: How to avoid transmitters chock during plant commissioning?  
01/04/2017 Q: In my plant, Vaccum Column LT LP tapping body nozzle is badly choked, all the dechoking options tried but no success found. We have only one LT tappings. As of now we have installed a PI at bottom in place of LT HP tapping, on the basis of this PI value level column is being operated. However this is not the permanent solution unless until we shutdown the column. Is there any other option available to monitor level of column?? (2)
16/01/2017 Q: Why we need to purge the PDI across each bed in DHT reactor with recycle gas? (1)
04/12/2016 Q: We have gland condenser in our unit. Why there are provided PDV in tube side? In tube side flow come from condensate pump and shell side flow come from ejectors.  
24/10/2016 Q: What is the working principle of pressure differential control valve. (2)
04/07/2016 Q: I wish to know whether it is possible to install a H2S analyzer in the FCC gascon section stripper column bottom liquid stream. The composition is C3-C10 hydrocarbons (propylene to naphtha range) and a little H2S and ethane. Also, a bit of RSH and COS are present too.
The requirement is to have an H2S analyser in this stream so that any slippage of H2S from stripper can be detected immediately and appropriate corrective action taken with minimum effect on downstream process. Is there any other indication of H2S slippage which can be used for monitoring purpose.
 		(2)
15/05/2016 Q: How can sulphur in Kerosene and RVP of Naphtha in CDU be optimized using APC?  
03/02/2016 Q: We have LPG caustic wash and water wash systems.Similarly,we have Naptha caustic wash and water wash systems.Frequent caustic carry over in product LPG and Failures in copper corrossion due to exhausted caustic solutions is a operational problem.Is there any continuous monitoring instrumentation available to check circulating caustic strength in caustic wash system? Similarly any instrumentation exists for monitoring recirculating wash water for caustic carry over symptom needing wash water replacement?
If so advise/share 		(4)
11/12/2015 Q: I am trying to find out the bore dia of restriction orifice plate to be placed in flushing oil line of 3/4" S80 going to a flow instrument handling Clarified oil. To calculate bore dia and thickness of restriction orifice plate, I need either pressure drop or flow across the plate which are not available. Flushing oil pressure is 14 kg/cm2 g and the flow instrument is operating at a pressure of 10.7 kg/cm2 g. How can I calculate bore dia with these details?
 		(2)
01/09/2015 Q: Currently I'm doing pump test with water, I want to know what is the best way to compare the flow from the FT and the flow in the pump curve, the Flow Transmitters are set for hydrocarbon with SG of 0.65 but I'm doing the test with water which SG is 1. Do I have to correct the flow to HC flow at conditions or standard conditions in order to compare the flows with the curve?. How can I do that?
 		(2)
03/08/2015 Q: Why is the Pitot tube placed at a 45 degree angle during installation in cooling water supply? What is the reason for placing at this angle?  
30/07/2015 Q: I am measuring the level of the catalyst in regen with d/p transmitter,the distance between taps is 498 " the density of lower section 25#/ft^3 and upper 3#/ft^3
What is the cal range " WC? It's continuous purge. 		(1)
30/07/2015 Q: Please advise as to how catalysis bed levels are measured in FCC REGEN using differential pressure also how density is calculated from d/p.
Are dip tubes used similar to bubble system? 		(2)
12/03/2015 Q: What is the significance of installation of Oxygen analyser to analyser oxygen in ejector off gas line?
And what is impact of oxygen in ejector off gas line? 		(2)
21/01/2015 Q: What are criteria for providing the bypass line in the control valve? In NG fuel line from 32 ksc to 5 ksc pressure drop at 70 deg C, can we provide the control valve bypass? (2)
07/11/2014 Q: I'm going to implement APC in a FCCU soon. What's the best source of information to learn the complete (even the minute) details of FCCU so as to complete it successfully? (1)
22/09/2014 Q: What is valve TRIM? (1)
18/05/2014 Q: In our vacuum column the column top pressure 75 mmHga and the flash zone pressure is showing 50 mmHga. The gauge near the ejector system is showing 40 mmHga. The PD of flash zone and the ejector system matches with the design value.
We have tried changing the gauge and the transmitter on overhead vapor also. The impulse line to the transmitter is clear.
what can be the reasons for this erratic reading in the vapor line. 		(3)
06/05/2014 Q: I would like your comments on use of Coriolis meter vs Positive Displacement meter from accuracy, proving, maintenance, operation point of view for custody transfer of petroleum products to be loaded in tank trucks  
29/03/2014 Q: We are having Feed Surge Drum in Diesel Hydrotreating Unit, for maintaining pressure of FSD we provided Blanketing Hydrogen and relief to LP Flare. Fail safe positions for the Control Valves in Hydrogen is Fail Open, LP Flare is Fail Close (Where as it was reverse in previous company where I worked last). If in case of Air failure Hydrogen to FSD CV gets open and may get pressurise as there will be no any relief
What may be the basis of selecting the fail safe position of both CVs? 		(6)
04/02/2014 Q: We are trying to figure out how to improve the feed control to our new Hydrocracking and Hydrotreater Units, since one of the feeds comes from the Coker Unit, we want to know how variable are the quality and flow of the HCGO, Naphtha and LCGO, because we are aware it would be changing while coker cycles are taking place. We don't have tanks to store LCGO and Naphtha as feed to the units, so these streams go to the hydrocracker and hydrotreater directly from the coker stripper, and if there is a sudden change in composition or flow, it could lead on a runaway. (3)
03/10/2013 Q: - I have seen most of the cases Control valve( CV) with 1or 2 sizes less than the pipe size and with Reducer and expander u/s and d/s of CV.
- Is there any reason to select lower size CV?
- What are advantages of Reducer and Expander of piping u/s and d/s of CV
- If i need to select CV size is same with the pipe based on Valve coefficient,what is the the impact Of "no reducer and expander"on CV performance. 		(2)
12/05/2013 Q: My question is on Acetylene Selective Hydrogenation Catalyst (Palladium –Pd based with promoters):
Ethane gas gets cracked in the Cracking Furnaces and the effluent goes through series of processes that includes quenching, heavy contaminants / heavy hydrocarbons removals, Multi-stage Compression, Caustic Scrubbing with Drying leading to De-Ethaniser (DeC2), and DeC2 Column Overhead vapour to the Two-stage Acetylene Hydrogenation Reactors. Main feed Ethane gas has a spec. of CO2: 200 to 1000 ppm; Total Sulfur: 500 ppm; Moisture content: 100ppm and it is directly cracked in the Furnaces. There are other feed streams having Sulfur ppm in the range upto 50 or so, with metal traces at lower ppb levels. The Reactors are operated with Carbon Monoxide level of 1000 ppm to 3000 ppm Max or so, at the upset conditions. Outlet Acetylene ppm levels are stringent in the range of 0.2 to 0.3 to produce Ethylene with 1 ppm Max Acetylene impurity.
a) Pl. let me know what all process parameters have direct impact on Catalyst deactivation and thereby short run-time requiring ex-situ Regeneration.
b) How will you control the parameters effectively to have much longer Catalyst run-time?
c) What is normal catalyst run-time for such Catalysts irrespective of any Catalyst vendors?
d) Whether going for Regeneration, would it be recommended to revive activity and selectivity to that of fresh material? Any risk involved in taking decision in favour of Regeneration?
e) Vendors confuse often with jargons, Reactivation and Regeneration. Are they one and the same or the process of reviving the spent material to the active phase to prolong the operation with recycle not only due to downtime of plant but also, expensive nature of catalyst with precious metals?
f) Pl. suggest suitable catalyst vendors with whom development activity can be collaborated with the company’s R&D Centre.
g) Any other important points in relation to specific Catalyst poisons, improving run-time atleast upto 4-5 years if not 10 years+

Your thoughts on this, in whole or part, greatly appreciated.
 		 
03/04/2013 Q: I'm working on a study to design a new control schematics for Crude Distillation Column Pressure Control. Any ideas for CDU pressure control strategies? (1)
11/02/2013 Q: In one of our FCCUs we have an automatic pneumatic fresh catalyst injector to load the catalyst from the catalyst tank to the regenerator. Some weeks ago we start having problems with the fresh cat injection. After inspection of the pneumatic injector, we could see a very hard deposit on catalyst in the injector valve. We found some other catalyst agglomerates in the tank. We believe it could be formed due to a leak in an steam line in the fresh catalyst vessel.
After several weeks and trials we have not been able to run again with the pneumatic injector and we must load the catalyst manually, straight from the tank, through the by-pass line of the pneumatic injector. After a very exhaustive inspection, everything seems to be OK mechanically in the all the system (vessels, piepes, etc). The catalysts deposits in the tank have disappeared. We are also having several fluidization problems in the loading pipe to the regenerator, both using the pneumatic or the manual loading.
Have anyone experienced similar problems? Could the properties of the fresh catalyst be related to the problem (losses on ignition, humidity, atrition, PSD)? 		(1)
25/01/2013 Q: In case of non-contact temperature measurement of the skin temperature of furnace tube, which instrument is better: infrared thermometer or laser pyrometer? What is the allowable temperature difference between thermocouple or thermowell temperature measurement to non-contact temperature measurement?  
04/02/2012 Q: In case of pressure gauge what is the specific use of Gauge Saver and Snubber? When do we select Gauge Saver and Snubber? Why is Monoflange with Block and Bleed required for pressure gauges? (1)
25/07/2011 Q: Lately we have been experienced frequent trip of Furnace in DHDS, we get positive draft and zero oxygen where this causes furnace to trip. Root cause? (3)
11/07/2011 Q: What are the basic differences, advantages and disadvantages, between controller using 4ma-20ma system and 0-10v system. (1)
06/10/2010 Q: If an Exib certified head mounted TT is installed in Exd RTD head, what independent certification of Tx and RTD head suffices? Does the complete assembly needs certification? What about temperature classification?  
05/10/2010 Q: if an Exia certified tepm. Tx is installed in Exd certified RTD head, do independent certificates of tx and RTD head suffice, or is certificate of complete assembly required?  
09/08/2010 Q: I work in Hydrocracking plant, where we commonly use turbine pump when running in normal condition, and backed up by motor pump as a spare pump.
But, in some equipment, we use turbine pump as primary pump and backed up by turbine pump as a spare pump. This pump transfer the bottom of low pressure separator (liquid hydrocarbon) to debutanizer.
I also found a pump configuration where both the primary and spare pump are turbine pump. This pump is diesel pump around (hot wash).
Do you know what is the reason behind these configurations? 		(2)
19/03/2010 Q: I am working in DHDS unit. Recently our unit tripped because of some strange problem. I request all to suggest a reason for the problem explained below.
We have one centrifugal Recycle gas compressor (RGC) and two reciprocating make up gas compressors (MGC) one running and the other stand-by. As per the regular change over of MGC we tried to take the other one in line and spare the running one. The discharge of MGC (40 KSC) goes to suction of RGC (39.4 KSC). After starting the spare compressor and once it got 50% loaded, the make up gas rose from 25 Tons per day to 35 tons per days, simultaneously RGC amperage came down from 210 to 176 amps and discharge pressure of RGC came down from 61 KSC to 53 KSC and this dropping of amps and discharge pressure continued and unit tripped on low hydrogen pass flows. As the discharge pressure of RGC reduced the discharge flow also reduced. I didn't understand why the discharge pressure of RGC came down.

Additional Information: Separator pressure is constant and when the RGC tripped, it started raising. The suction flow was 265 Tons per day and when the RGC discharge pressure dropped, the suction flow also dropped to 255 Tons per day. 		(6)
10/02/2010 Q: We have a Sour Water drum (Operating Pressure = 46 kg/cm2(g)). We have installed an angle control valve to kill the pressure from 46 kg/cm2(g) to 6 kg/cm2(g) and because of some slurry particles.
System upstream of the Angle valve is designed for 50 kg/cm2(g) and downstream of the valve is designed for 20.5 kg/cm2(g).
In case there is an auto control failure of this Angle control valve, what is pressure can be seen by the system downstream of the valve?
Is it recommended to increase the Design pressure of the downstream system or provide any protection ( safety valve) downstream of this Angle control valve? 		(2)
16/11/2009 Q: What are the reasons that are responsible for back fire or reverse flow of flame in the furnace? What measures should be taken to prevent these incidents? (4)
15/11/2009 Q: What is PRD mode in automatic process control? (5)
21/10/2009 Q: Is it safe to consider back pressure of 50-70 kg/cm2g when my PSV set pressure is at 229 kg/cm2g? Why are we limited to 3-5 kg/cm2g back pressure maximum when we are designing the HP flare? API 520 part 1 says that I can consider up to 50% of set pressure of balanced PSV, so can I consider up to 100 kg/cm2 g when my PSV is set at 220 kg/cm2g? If not, then what is the reason? (4)
16/07/2009 Q: How can one fix minimum circulation flow and scheme for a pump which is undergoing in revamp, specially when flow is going to reduce after revamp? (3)
09/06/2009 Q: Which on line process analzyers including NIR and gas chromatograph are installed in DCU, VDU and VGo HDT units?  
04/06/2009 Q: In what situation is a pneumatic test at one kg/cm2 to be preferred to a hydro test at the design pressure of a vessel? (2)
02/11/2008 Q: Sample Probes: How are the vibration calculations done (vibration calculations to ensure that the probe cannot fail to resonance effects / harsh process conditions)? Are there any software packages available to check that the sample probe selected can withstand the process parameters (pressure, temperature, flow, fluid density, etc.)?  
16/10/2008 Q: On the LPG (Liquefied Petroleum Gas) outlet line from the bottom of the storage vessel (Horton sphere or mounded bullet), remote operated isolation valve (ROV) is provided for isolation of the facility in the case of emergency. This remote operated valve shall be fire-safe type conforming to API 607 or equivalent in order to protect the valve from external fire situation. In case of pneumatic operated ROVs, we would like to know whether the actuator system comprising of diaphragm & spring requires fire protection? If it is required, how the protection can be given? Is there any mechanical design requirement for the diaphragm/spring to protect the actuator from external fire case? What is the standard practice?  
23/09/2008 Q: I am working a project where I am trying detect phase changes. The project consist of detecting phase changes from water to butane by using flow meter density detectors. This idea is only for ideal case, but the reality is that, caustic may be present. Here is where the issue comes.
The question that I have is this: what method should I use to detect different phases. For example, mixed water and caustic? mixed Butane and Caustic? Again, the point is to detect phase density changes from water to butane. 		 
11/07/2008 Q: How effective are the latest automation & control systems for ULSD hydrotreaters? Are they making a significant contribution in producing on-specification distillate product (< 8-10 ppm sulphur)? What is the feasibility of "extending" these control systems to upstream feed-stream distillation systems (i.e., tighter control of hard-to-remove refractory compounds entering hydrotreater)?  
07/07/2008 Q: In general, where has the influence of good fractionation allowed for significant improvements in meeting stringent petrochemical product specifications (e.g., propylene, styrene, etc.) at higher charge rates? Besides the recent improvements to fractionation column internals, what is the extent to which automation & control systems can be leveraged to deliver higher efficiency, run-lengths and resistance to corrosion in product recovery trains?  
07/07/2008 Q: Under what circumstances is it cost effective to revamp the FCC main fractionator so that the amount of heavy FCC naphtha feed to ULSD hydrotreaters can be increased while still meeting finished ULSD product flash and distillation requirements? Are most ULSD hydrotreaters designed with a three-product stripper using a fired heater, or is a simple steam stripper adequate? (1)
21/06/2008 Q: Is there a noticeable increase in blending clarified FCC slurry oil into No. 6 fuel oil? Since this obviously circumvents the need for blending lighter, higher-value products into the No. 6 fuel oil, how much of an impact on total refinery profitability can be expected? Are some refiners instead opting to use higher percentages of slurry oil as feedstock to a coker unit or a hydrocracker? (1)
17/05/2008 Q: We have two TIC in reformer heater outlet manifolds for temperature control which act on fuel gas of heater. Low limit of these TIC,s are 700°C, but in some cases (i.e start up) we need to control temp. lower than 700°C. One of our operators suggested we change the lower limit of TICs to less than 700°C. Is this possible without any safety and design problems? (1)
01/04/2008 Q: In what type of situations can we use 2 solenoid valves in series and when do we use 2 solenoid valves in parallel ? (2)
01/04/2008 Q: What is the problem in providing PSVs only on the feed line in a distillation column and not providing any PSV on the overhead line, given the fact that the PSVs on the feed line have been designed for reflux failure case? (1)
25/03/2008 Q: We are relocating a refinery which has a lot of control valves missing Are there companies which can supply old but fully refurbished valves meeting quality standards? (1)
03/03/2008 Q: The US EPA now permits blending of RFG gasoline without oxygen. Has any refiner or blender reported the ability to meet RFG gasoline emissions constraints without the use of ethanol or other oxygenated component?  
27/02/2008 Q: It is a primary requirement of instrument change-over philosophy that all existing field control systems, safety systems and associated field instruments should remain fully operational and functional in their current configuration until new systems are fully installed, tested and and commissioned successfully. The existing field instruments and associated plant control and safety systems will be operating in parallel with the newly expanded facilities until commissioning is successfully completed. My question is that how parallel operation is possible and how the old system is decommissioned.
 
06/02/2008 Q: In a multi product cross country pipeline pumping petroleum products like Motor Spirit & Diesel etc it is required to trip the running booster pump in case of accidental closure of the motor operated valve on the pump discharge line to prevent no flow condition of the pump. Due to difference in density between Motor Spirit (0.73) and Diesel (0.825), is it required that the trip setting pressure to be reduced during Motor Spirit pumping & increased during Diesel pumping? What is the standard practice w.r.t discharge pressure trip setting in such multi product pumping?  
05/02/2008 Q: Shutdown Control valves are required to isolate the process in case of emergency. What are the testing parameters and acceptance values of such control valves testing? Details of time of closures, time of openings, tightness criteria, fire rating etc would be helpful.  
05/02/2008 Q: In Sulphur Recovery Unit, provision for Nitrogen purging exists in the Reactors to prevent temperature runway. In certain cases it has been found that manually operated isolation valves are provided on Nitrogen injection line instead of remote operated isolation valve. This makes it difficult to take immediate action and control the temperature excursion. What is the design practice by process licensors?  
27/01/2008 Q: What are the basic differences, advantages and disadvantages, between controller using ordinary 4ma-20ma system and Foundation fieldbus? (1)
08/01/2008 Q: We have a butterfly pressure control valve (PV) in hydrogen product line from hydrogen unit to hydrocracker unit without any block valves and bypass line on it. Another PV on this line is fitted in split range arrangement with first PV and connected to flare line. Can anybody explain about the design criteria about installation bypass and block valves on a control valve? (2)
26/11/2007 Q: I am still amazed at how few companies are using Inverter Technology on Fans and Pump applications.
Is there much demand for European manufactured Inverters within Petrochemical industry? 		 
19/09/2007 Q: Please advise on reduction of ammonia emissions from a fertiliser plant.
Our emissions from a urea plant stack is about 150 ppm, and we need to reduce them to 50 pp to comply with EPA regulations. I know some plants are provided with an acid washing system.
I would be grateful for advice from anyone with experience in this field. 		(1)
13/09/2007 Q: Where can I find diaeclectrical constant for refinery products (gasoline, kerosene, diesel, raffinate etc.)?  
06/09/2007 Q: I am looking for a complete wireless control system solution enabling us to have a smooth plant with no, or just a few, signal cables coming from the site to the control room. Are any of the well known DCS vendors offering such a wireless, yet reliable, data acquisitioning system? (1)
23/08/2007 Q: What instrumentation and related analytical systems are available
to ensure that high-volume biofuels production conforms to regulatory specifications in markets such as Europe and North America? 		(1)
09/07/2007 Q: What are the most important automation and control components being incorporated into new projects to help operating companies increase capacity and meet higher quality specifications while reducing recycle and energy costs? (3)