CDU Overhead Discussion

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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?

Answers

11/04/2011	A:	Alan Goelzer, Jacobs Consultancy, alan.goelzer@jacobs.com  For conventional crude oils, the vast majority of HCl, aqueous in the overhead accumulator of CDU+VDU atmospheric tower derive from thermal cracking of residual salts left in "desalted crude oil". Residual salts comprise a mixture of various salts besides NaCl. When the crude oil is heated in hot encon exchangers and the crude heater, most of residual MgCl2 thermally cracks; good share of CaCl2 thermally cracks; and a small but significant amount of NaCl thermally cracks. Temperatures in the preflash drum or preflash tower is often not quite hot enough to drive these thermal cracking reaction, especially if residual MgCl2 is minimal. A small proportion of HCl may derive from incidental or partial thermal cracking of organic chlorine species. Mitigation of HCl in overhead water is achievable by using best possible desalting of the crude oils, i.e. double desalting in appropriate size desalter vessels using "electrics" and "internal piping" provided by highly qualified desalter technology suppliers and chemicals treatments and auxiliaries. Target performance for conventional crudes [API = 28 to 42] is residual salt =0.5 ptb [one-half pound mixed inorganic salts per thousand barrels of desalted crude oil].
11/04/2011	A:	Amiya Kumar lahiri, Consultant, lahiri04k@rediffmail.com  Overhead chloride in processing of crude is due to hydrolysis of MgCl2 and CaCl2 to form HCl. The temperature range of hydrolysis of the two salts is however different. While starting temperatures of hydrolysis of MgCl2 is about 120C, that of CaCl2 is about 210C. The fact that you have problem with high chloride in main fractionator and not the pre flash column (Temperature – 250C), indicates that nature of chloride coming with the crude consists of Ca and Na chlorides and almost no MgCl2. Thus HCl is formed only downstream of pre flash column. Suggest you analyze the crude tank drain water for nature of soluble chlorides. This can be done also with desalter water provided fresh water added for de salter operation is process water.
09/04/2011	A:	Celso Pajaro, Sulzer Chemtech, celso.pajaro@sulzer.com  Inorganic chlorides will dissociate at higher temperatures. 95% of Magnesium chloride will dissociate around 375 C, while only 15% of Calcium Chloride will dissociate, and 5% of sodium chloride wi

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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.

Answers

04/08/2011	A:	Berthold Otzisk, Kurita Europe GmbH, otzisk@kurita.de  Replacing the metallurgy to a more resistant metallurgy is a good option to control corrosion in the hot section (1st stage). Changing the metallurgy requires a long planning phase and expensive procurement costs. The injection of an oil-soluble filming amine via hydrocarbon slipsteam or injection quill is a cost-effective and very efficient alternative to control corrosion. The typical dosing rate for a continuous treatment with a filming amine is in the 3-6 ppm range. The additional injection of a neutralizing amine and filming amine into the 2nd stage is very common.
01/08/2011	A:	Ralph Ragsdale, Ragsdale Refining Courses, ragsdales@juno.com  “From the design conception, water should only condense on the second drum…” I believe that this is expecting too much. A double drum design is intended to retard corrosion in the upper section of the column by refluxing warmer material, and apparently you are achieving that objective. Water will condense in the very first heat exchanger. Consequently, measures to dilute acids and inhibit corrosion should start upstream of the first exchanger. Equally important is reliable desalting operation.
01/08/2011	A:	Sam Lordo, Nalco, salordo@nalco.com  This is a common situation with double drum systems that use cold crude for cooling of the hot ovhd going to the first drum, the design only works on paper and failed to take into account shock condensation (condensation of the water on the tubes). When doing computer simulations the presence of water is not detected, that is because the calculations based on thermodynamic assumptions and do not take into account kinetics of the situation. The solutions that have been used are: to remove formation of water in first drum: maintain the incoming cold side approach temperature to with 15-25 F of calculated water dew point to prevent corrosion and salt fouling: replace metallurgy of piping exchanger shells, and bundles with acid resistant metallurgy. some use of chemicals (filmers and neutralisers) are successful if properly applied

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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?

15/12/2011	A:	Sridhar Balakrishnan, Nagarjuna Oil Corporation Limited, laksrid@yahoo.com  Copper strip Corrosion failures are caused by Active sulphur species like Mercaptans, Hydrogen Sulphide etc. Traces of Caustic carryover into Hydrocarbon streams also can contribute to Copper Strip Corrosion Failure. Other than Hydrogen Sulphide and Mercaptans , Elemental sulphur also contributes to copper strip corrosion failure . Doctor Test can be performed to detect presence of Mercaptans, Hydrogen Sulphide or Elemental Sulphur . There are many commercial Mercaptan and Hydrogen Sulphide Scavengers available in the market to mask the active sulphur species.
14/12/2011	A:	Lindsay McRae, Pall Corporation, Lindsay_McRae@pall.com  Caustic carryover from caustic treater can certainly cause Cu strip test failure and is a common reason for off spec products downstream of caustic treaters. Often this is due to inability of sand coalescer, mesh pad, electrostatic coalescer or other low efficiency coalscer not being to effectively enough remove entrained water /caustic from the hydrocarbon phase. This is part due to the very low IFT (Interfacial Tension) which may be as low as 0.5 dynes/cm which means this is a very stable emulsion and a difficult separation to make. High efficiency PhaseSep Liquid Liquid coalescers have been proven to remove sodium to very low levels. What type of separation equipment do you have currently downstream of your caustic treater? I am happy to help further if you need further assistance

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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.

Answers

08/07/2011	A:	Lindsay McRae, Pall Corporation, Lindsay_McRae@pall.com  You may be having recycle of sour water from CDU overhead drum back to CDU which can cause corrosion in the head of CDU and in condenser. Sometimes residence time in overhead drum is not sufficient for a decent separation so sour water goes with naphtha to debutaniser and also with reflux back to CDU and perpetuates the corrosion cycle in CDU overhead / condenser . This is more common after CDU is debottlenecked or heavier / sourer crudes are used which makes CDU OH drum separation performance marginal. The use of corrosion inhibitor assist to help reduce corrosion, but also can act to stabilise emulsion in CDU OH drum reducing the interfacial tension and making the separation more difficult again contributing to recycle of sour water back to CDU overhead. Are you having any issues with debutaniser tray fouling or HDT reactor plugging or feed exchanger fouling? This can also result from corrosion in CDU overhead / condenser and is an indicator of that. Check desalter operation for a start. If that's OK, then you might want to consider high efficiency Liquid Liquid coalescer on the naphtha steam from the bottom of the CDU overhead drum. By reducing sour water recyle, corrosion can be tackled at its source.
07/07/2011	A:	Ralph Ragsdale, Ragsdale Refining Courses, ragsdales@juno.com  Could it be that, in the case of the preflash column, the overhead vapor contains water vapor, and in the case of the preflash drum, it does not? Corrosion typically occurs where the water condenses, unless a good system is in place to retard the corrosion.

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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.

Answers

12/04/2011	A:	Berthold Otzisk, Kurita Europe GmbH, otzisk@kurita.de  In general caustic addition after the desalter, a monel cladded overhead line and a pH control of 5.5-6.5 of the sour water are very good tools to keep the corrosion potential low. A continuous water wash is favored instead of periodical water injection to avoid salt fouling and corrosion. The design of the wash water injection system is very important. It can be the scale pan of a perfect salt removal or inadequate washing procedure. The main questions are: - How much water is injected during the periodical washing procedure ? - Is an increase of conductivity, chlorides or corrosion byproducts reported after starting the periodical water wash ? - Where is the wash water injected ? - Are spaying nozzles used to disperse the water ?
05/04/2011	A:	Eric Vetters, ConocoPhillips/R&D, eric.w.vetters@conocophillips.com  Continuous water wash in your case would reduce neutralizer usage marginally in your case if all the water comes from demineralizer make up. The fresh water dilutes out the acids so that less neutralizer is needed to control pH in a slightly acid range. The savings in neutralizer would likely be more than offset by the cost of the additional water, however. Most units recycle water from the accumulator so continuous water wash has no effect on neutralizer demand in that case. The intermittent water wash that you are using is likely not related to your lack of overhead line corrosion. Water wash is really mainly trying to protect your overhead coolers. If you are experiencing short life on your overhead bundles, then going to a continuous water wash is likely to help improve bundle life. When water wash is not being injected salts and/or acids can condense on the tubes leading to corrosion. Your intermittent water wash may stop salt related fouling but won't necessarily stop corrosion.
05/04/2011	A:	keith bowers, B and B Consulting, kebowers47@gmail.com  Adding more wash water will reduce the CONCENTRATION of chloride in the total wash water, rendering it less corrosive, thereby requiring lower additions of corrosion inhibitor. Continuous wash water use is highly preferred over intermittent for this service because it lessens the development of corrosion cells. Far better to keep corrosion inducing deposit from ever forming than trying to ensure they are periodically removed.
05/04/2011	A:	Sam Lordo, Nalco, salordo@nalco.com  if the wash water is truly demin water (which is not normal) the actual conc. of cl will be reduced as the demin will dilute the corrosive and it is the conc of Cl that is the enemy, the other aspect is demin water typically has a higher pH and hence some pH control will come with using water wash Overall using water wash continuously is much better than ono-continuously because the salts that form and reside in the overhead bundles go thru a wet/dry cycle potentially creating very active corrosion cells

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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%.

Answers

02/03/2011	A:	Amiya Kumar lahiri, Consultant, lahiri04k@rediffmail.com  I have come across two types of situation which can result in overhead corrosion in Coker distillation column: 1. High pH in the range of 9.0 – 9.5. Corrosion under this condition in my opinion is related to ammonium bi sulfide corrosion. The temperature being high (about 520C), sulfur and nitrogen compounds in the feed crack to produce H2S and NH3 respectively which in turn produces corrosive alkaline bi sulfide. 2. Presence of chloride in O/H. Chloride is not expected in this case as all Mg and Ca chlorides get dissociated in crude and vacuum units. Feed to coking unit is heavy hydrocarbon from bottom of different units and also includes slop. In one such study the source of chloride in Coker distillation column was identified to be the desalter drain water (containing soluble Mg and Ca chlorides) which was added to the slop. 3. AnalyseNa, Mg and Ca chloride in vacuum residue water 4. I would suggest you additionally measure pH, and bi sulfide content of overhead water and also check if desalter drain water is part of the slop fed to the Coker. Relating corrosion rates to the above parameters will help in taking reliable corrective action.
01/03/2011	A:	Eric Vetters, ConocoPhillips/R&D, eric.w.vetters@conocophillips.com  Chlorides in the coker overhead normally come from additional hydrolysis of salt in the feed that did hydrolyze in the crude or vacuum unit furnaces. The only way to lower the mass of chlorides is to improve desalting. Putting in more make up water for the overhead water wash will dilute the chlorides but not change the mass. You should pick the amount of water used to ensure that you excess water injected that will remain liquid after contacting the hot overhead vapors. Typical guidelines for similar systems call for at least 25% of the injected water to remain as liquid after flashing at the injection point. If your chlorides are too high you can form ammonium chloride that precipitates in the fractionator. The ammonia is a normal byproduct of the thermal cracking reactions of nitrogen containing compounds in the coker feed and is not normally controllable. This salt causes tower DP to increase until a water wash is required to remove the salts. Besides hurting fractionation and possibly capacity, this salt formation and subsequent water washes can also cause corrosion. To avoid ammonium chloride deposition in the tower, you need to either control desalting to control the mass of chlorides formed for the overhead temperature being operated at. If you are getting salt deposition you need to either improve desalting to reduce the mass of chlorides formed or increase the overhead temperature to move the salt point out of the tower. Your refinery chemical supplier should be able to estimate the salt point temperature based on your actual operation.
01/03/2011	A:	Morgan Rodwell, Fluor Canada Limited, morgan.rodwell@fluor.com  The root cause of chlorides in the coker fractionator overhead is most likely chlorides in the feed. Chloride salts that are not removed via desalting will largely pass through the CDU and VDU and end up in vacuum residue. Some crudes also contain small amounts of organic chloride hetero-atoms. The conditions in the delayed coker are sufficient to break down the organic chloride and to hydrolyze many of the chloride salts. The chlorides will then rise up the fractionator as HCl and then react with basic species (e.g. NH3) in the overhead. You may want to check whether you have NH4CL sublimation occurring in the top of the column or in the condenser as this can cause very serious corrosion. Wash water and amine/ammonia neutralization are often used to reduce the corrosive nature of this water. Reducing the chlorides in the overhead is really only achievable if you do a better job of desalting the crude upstream of the CDU.
01/03/2011	A:	Celso Pajaro, Sulzer Chemtech, celso.pajaro@sulzer.com  Besides chloride you need to analyze ammonia, the corrosion mechanism in the overhead of a delayed coker main Fractionator is ammonia chloride salts deposition which cause under deposit corrosion. Chlorides are coming with the residue and they are release under the Delayed Coker Fired Heater conditions, one way to reduce chlorides is to improve the operation of the crude unit desalter, other method that has been used is adding a small amount of low strength caustic to the crude after desalter, caustic will react with the calcium and Magnesium chlorides producing sodium chloride which is less susceptible to hydrolyze under fired heater conditions, please made sure that sodium content on the vacuum residue is kept below 30 ppm to avoid high coking rate in the delayed coker fire heater tubes.
01/03/2011	A:	Christopher Turner, Snamprogetti Ltd, chris.turner@snampro.co.uk  How much water enters the column with the hydrocarbon feed? This water (even after desalting and dehydration) will still contain salts which may be contributing to the chloride.

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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.

Answers

01/05/2011	A:	Ramadan milad, AGOCO, RMSALEH@YAHOO.COM  As you are operating the common stack furnaces at low temp than normal, you should carry out a cross check all of your gauging equipment, also the Damper material to be compared with the other furnace dampers
18/04/2011	A:	Sudhakara babu Marpudi, Oman Oil RPI, m_sudhakarababu@yahoo.com  Check the health of the flames in the furnace. It is most probably an issue related to after-burn of the fuel. If the burners are on Fuel Oil, low viscosity of Fuel Oil, eroded Fuel Oil gun nozzles can lead to very tall flames, shifting the load from Radiation section to Convection section of the furnace. If the burners are on Fuel Gas, then adjust the air to burners. Gas flames will burn wherever combustion air is available, and the convection area is the definite area where unused combustion air will be available before the Flue Gas passes thru the convection bank (in view of back pressure). Idally the Flame length of a Fuel Oil flame (which is normally taller than the Gas flame) shall be around one third of the height furnace radiation zone (one third of the tube length for bottom fired vertical furnaces).
07/12/2010	A:	Simone Robinson, Tube Tech International Ltd, simone@tubetech.com  The cause of your problem could be a cleanliness issue on the convection side.

Crude distillation