ABPG – Brimstone Sulfur Symposium Vail - 2010 · PDF fileABPG – Brimstone Sulfur...

-1-

ABPG – Brimstone Sulfur Symposium Vail - 2010 Presentation hard copy material

I. ABPG Mission – History See following page 2 -3

II. ABPG Membership

See following page 4

III. ABPG Member Correspondence: August 09-Aug 10 See following pages 5 - 54

-2-

ABPG MISSION - HISTORY

Mission:

To accumulate a database on amine unit operations and become a clearing- house for the analysis and distribution of such data to the gas processing and refining industry on a global basis through articles in trade journals and through symposiums.

Purpose: To provide an open forum for exchange of operating experiences for the purpose of benchmarking, troubleshooting and developing best practices leading to improved unit operations and reliability.

Scope: The focus will be primarily issues pertaining to process units that will include amine treating, sour water treating, sulfur recovery and tail gas treating.

History: The history of the ABPG is relatively short. It was formed in late 1992 when a group representing the refining industry, design engineering and an independent consultant met to discuss the possibility of developing a real-world database for amine unit operations. The impetus for this initial meeting was a stated interest by many refiners, both major and independent, in evaluating their amine unit operations with respect to others in the industry. The early meetings were devoted to developing an amine unit survey questionnaire and the ABPG Best Practices Manual. Responses from the questionnaire were the basis for the 1994 database and includes 75 amine units. In subsequent meetings, ABPG members analyzed the 1994 database and developed two articles that were published in industry trade journals. The database was also the basis for the ABPG Amine Users Symposium held in 1995. In 1995 ABPG members developed a new survey questionnaire that focused on amine unit cost control. The results of this survey database were published in the Summer 1997 issue of Petroleum Technology Quarterly.

-3-

In 1997, the ABPG established a Data Exchange Network (DEN) to provide members with an open forum to post questions and exchange operating experiences. Since 1998, ABPG members have met annually to address specific topics of interest and develop outlines for future articles to be published that focus on issues of general interest to the industry. In 2000, the ABPG adopted a focus project to develop a protocol, format and procedure for standardized amine testing to present to the industry. This effort is still in progress. In 2002, the ABPG established a website to host the DEN. Currently, only ABPG members and ABPG member company personnel have access, but an effort is under way to make selected DEN data available in the public domain.

-4-

AMINE BEST PRACTICES – MEMBERSHIP ----- August 2010 Title: Member Directory [ADM-001]:

1. Asquith, Jim – Valero Energy Corporation 2. Bela, Frank – Member Emeritus (formerly Texaco, Shell) 3. Buziuk, Frank – Member Emeritus (formerly Chevron) 4. Crockett, Steven – BP (US) 5. Davis, Jay – Chevron 6. Eguren, Ralph – BP (US) 7. Hatcher, Nate – Member Emeritus (formerly ConocoPhillips) 8. Heeb, Dick – Marathon Petroleum Company LLC 9. Hittel, Shelley - SemCAMS 10. Keller, Al – ConocoPhillips 11. Kennedy, Bruce – Member Emeritus (formerly Petro-Canada) 12. Ritter, Nathan – Flint Hills Resources 13. Schendel, Ron – Consultant 14. Smith, Conrad – DCP Midstream (formerly Duke Energy Field Services) 15. Stern, Lon – Member Emeritus (formerly Shell Global Solutions) 16. Tracy, Frank - ConocoPhillips 17. Tunnell, Duke – Business Manager 18. Way, Bill – EnCana Corporation 19. Welch, Bart – Chevron 20. Young, Mark – Suncor Energy 21. Zacher, Mike – Member Emeritus (formerly BP Refining, UOP)

Updated 11-August-10 // lhs

[ ABPG – Membership.doc ] LHS/08-11-10

-5-

Amine Best Practices Group Member Correspondence – August 2009 – August 2010 Question Id: ARU-247 Title: Where do the Amine Strength limits come from? [ARU-247]:

Curiosity has finally got the best of me, so I have to ask, where do the commonly held Amine Strength limits come from? I would have assumed someone would have written a paper on this, but I can't find one. I hear limits like 20wt% MEA, 32wt% DEA, 50wt% MDEA, but I know of exceptions for each. Obviously the viscosity goes up, and assume the potential to foam goes up, but I was always under the impression the limits were based on corrosion, not physical properties.

I've heard of cracking of welds being a problem with amines, especially MEA, but now that we post weld heat treat everything in modern units I wonder if these old limits still apply. posted on 4/29/2010

Responses:

2. [ARU-247]: I would like to echo xxxxxx's comments I have used "rules of

thumb" and still do, but when a client has limited circulation and loadings through the roof arbitrary strength limits go out the window.

posted on 5/25/2010

3. [ARU-247]:

At risk of sounding like Bill Clinton or some other politician/lawyer, I first have to ask for your definition of “… commonly held … limits …”. There are some that are based on corrosion studies, that have been starting points for usage/discussion. Then, various members of the industry (amine venders, users, etc.) developed some different guidelines, based on industry application experience. And, some companies have their own “commonly held limits”, based on their operating experiences. For the most part, the operating experience adventures have been related to treating capacity, metallurgy selection and/or corrosion rates. I look at the “commonly held” limits that are discussed by others in previous answers as similar to 98.6 degrees being the “normal” human body temperature. Further review indicates individual

-6-

“normal” temperatures can vary from 98 to over 99 degrees, and not be a sign of poor health. The actual normal temperature for an individual is related to a number of factors. The same is true of amines. You have some people who claim excellent results with 35% DEA and others who are fearful of going above 25.1% DEA. Analogous situations exist with the other amines. There are so many things that affect corrosion, focusing on amine strength alone as the indicator of acceptable conditions is futile. The data and references need to be exactly that, background information. Individual acceptable conditions results vary. The units need attention to multiple variables to assure successful and acceptable operation. A number of years ago, some of our research people were trying to generate interest in the use of neural networks and various mathematical tools to identify correlations and relationships that escaped conventional analysis. I suggested amine unit corrosion as a function of many variables (amine strength, amine temperature, HSS levels, presence or absence of sodium salts, solids levels, amine velocity, etc.) as a situation that would be of great value if we could define the relationships. The proposal did not make the cut. Maybe the scientist members, or bored retirees, of the ABPG would be interested in pursuing such an effort!

posted on 5/23/2010

4. [ARU-247]: Well, because there are lots of issues with Amine Treating that I

am still trying to understand, my conclusion is that I'm not yet qualified to fit into xxxxx's "old amine folks" category !

posted on 5/18/2010

5. [ARU-247]:

I checked my dusty reference library and found that most experts quote the same amine strength limits without any further explanation. In one book by R.N. Maddox (1974), the reason for the limits was corrosion.

For DEA and MEA, he explained that we could use a higher concentration of DEA (30 wt%) because the molar ratio of amine to water is the same as for 15 wt% MEA. This reference was before the accepted use of MDEA.

The strength limits were mentioned again in the section on corrosion of carbon steel equipment.

-7-

posted on 5/18/2010

7. [ARU-247]:

Could it be a coincidence that the MEA and DEA concentrations on a molar basis are about the same? I recall when DEA was being used at 25%wt and 28%wt was a hard limit. When it comes to corrosion, moles rule the day over pounds.

So I guess the question then becomes why MDEA appears to be so much better? Less residual CO2 lean loading is the only thing that jumps out. I'll be curious to see what the JIP comes back with in this arena.

posted on 5/17/2010

8. [ARU-247]: Interesting comments provided by all

posted on 5/17/2010

9. [ARU-247]: I resemble the fact xxxx would imply some DEN members are old.

posted on 5/17/2010

10.

[ARU-247]:

I can tell you some new information and maybe I have been around, since before time. We have tried, by mistake, using 50% MDEA in a TGU with major problems and ended up violating on SO2. I suspect that part of it was due to viscosity and at that low pressure it might just be too far. We have no problems since going back to 45%. More recently I have seen reports by one of the amine suppliers who indicated that 50% MDEA in a primary amine system was fine. One of our refineries tried that with poor performance. However, I have not read the incident investigation to understand what occured.

posted on 5/16/2010

14.

[ARU-247]: I can't add a whole lot here but "cracking" in amine system equipment is not just related to amine strength (wt%). Cracking is another subject related more to hydrogen and its interaction with different types/grades of carbon steel - including hardness, fabrication methods and welding. As far as I can remember wt% limits are all fundamentally based on corrosion in the systems, equipment and piping.

-8-

posted on 4/30/2010

15.

[ARU-247]:

I'm not old enough to meet Ralph's criteria, so I don't know the origin. However, the corrosion work we have done shows the answer is likely related to corrosivity.

For instance, Nate and I did a paper at Brimstone showing 3% ammonia being too corrosive for CS at 180 F when highly loaded (>0.8 mole/mole) with H2S. That would translate to an MEA at about 10.8 wt% or DEA at 18.5 wt%. It looks as if there were simply total H2S picked up limits that helped develop the rules of thumb for amine strength. Also, as strength goes up, overall concentration of H2S of CO2 goes up in the lean amine. The research we quoted from Honeywell showed corrosion rates taking off at about 200 F, so more acid gas at higher temperature would have a big effect on corrosion.

Last, the HSS content rules of thumb (which COP no longer endorses) of 10% of the amine tied up as HSS may also have bee a factor since more amine strength led to higher HSS anion levels and faster corrosion. That is why we went to an anion content basis and not amine strength basis for HSS anion control.

posted on 4/30/2010

16.

[ARU-247]:

WOW! This is back to the creation of life itself. I pulled my trusty Gas Purification text by Arthur Kohl and Dick Nielsen and find that it starts with MEA back in the early 50s. (Actually, RR Bottoms is given the honor of using amines to sweeten back in 1930, if I recall. I believe he used TEA). Through experience heavily driven by corrosion, the recommended strength for MEA is 15%. Other work expanded the strength if you had corrosion inhibitors. Dow and Union Carbide did lots to progress this work.

Similar developments occurred with DEA, DGA and MDEA follow, all based on plant experience driven by corrosion.

Perhaps, some of DEN members, since they were around since the creation of amines, could shed better light.

posted by: xxxxxx on 4/29/2010

Question Id: ARU-245 Title: High Pressure Amine Treating Attachment(s): ARU-245.doc [ARU-245]: Does anyone have data and/or experience (with references/sources) for high pressure (> 2200 psig) amine treating? How well

http://www.abpg.net/Documents.aspx?Id=1118�

-9-

do the public models do in this regime? posted on 3/22/2010

Responses: 1. [ARU-245]:

We also have some high pressure absorbers but only to about 140 Bar (2000 psig). As already stated, the big issue is loading. We have learned the hard way the importance of basing circulation on rich loading rather than treat to avoid undue corrosion.

posted on 4/1/2010

2. [ARU-245]:

The acid gas VLE data for most amines goes up to 80-90 atmospheres (1200-1300 psia) partial pressure. This means that, for the high pressure treaters, as long as the acid gas concentration is below, say, 50%, extrapolation is not required. Confirming what others have already stated, at these partial pressures the amine can be loaded to extremely high levels – in many cases to well over 1 mole/mole, and corrosion considerations are thus limiting.

posted on 3/27/2010

3. [ARU-245]:

Chevron has quite a number of them. We've got a division that licenses hydrocracking / hydrotreater technology and they like to design to high pressures and almost always include a recycle gas treater. Most are DEA, a couple MDEA and we've converted the three identical such units (~ 600 gpm circulation) at the Pascagoula Refinery to an MDEA/DEA blend without any problems.

Do you really need a good model for the amine side? There's really no spec on the H2S in the treated gas and with the high H2S partial pressure you get really good pickup anyway. It also allows you to run the rich loading up way past any reasonable value set to limit corrosion. My advice is to remember that it is a foaming system and thus resist the temptation to design too closely to flood limits.

posted on 3/23/2010

-10-

4. [ARU-245]: Sorry, the highest I've worked with is ~1000 psig. In general the models are OK with MDEA and not bad with DEA (even at 1000 psig). MDEA was still a little iffy the last time we modeled a system ~ two years ago. I agree the flash drum is the most problematic and the regenerator steam loads are directionally good, but the absolute doesn't match real world.

posted on 3/22/2010

5. [ARU-245]: We are not operating quite that high, but in the 1800 psig

range. The big concern, as Al indicated, is the absorption of H2S into the amine. I have as high as 0.7 mol/mol. You will have to sample at pressure, otherwise much of the H2S will be flashed once it goes through a flash drum. The risk is the corrosion in the absorber and hydrogen blistering. Don't trust the amine analysis unless you are sampling at pressure.

posted on 3/22/2010

6. [ARU-245]:

This question is just oh soooo perfect for Mr. Hatcher to handle, so I await his response. We have DEA in high pressure hydrocracker applications, but I do not recall how well the model-prediction matched reality.

posted on 3/22/2010

7. [ARU-245]: We have hydrocrackers that treat up to 2750 psig to remove

H2S from recycle H2 using MDEA. No CO2 removal or use of primary/secondary amines. Public models do OK on acid gas removal computations but don't seem to be super accurate on gas solubility and flash drum gas make. Lean amine and gas temperature can make a big difference in how much methane and ethane get picked up from a hydrogen stream.

posted on 3/22/2010

8. [ARU-245]:

I have not looked at this for over 1100 psig, but the fundamentals seem to indicate you could load up the amine pretty well. I am assuming you are talking about single phase gas treating. You may see some high intermediate contactor temperatures at the bulge as well as in the lean amine feed if you don't have enough cooling, and maybe some higher than usual flash gas rates as well. The rich lines may have to be stainless, especially at the letdown valve where velocities may

-11-

be scary. posted on 3/22/2010

Question Id: ARU-244 Title: Bubbles in Absorber Gage Glass Attachment(s): ARU-244.doc [ARU-244]:

What would cause bubbles in the gage glass of an amine absorber? One of our refineries has large bubbles, same diameter as the gage glass, on the absorber off of their Jet HDS unit. It operates at ̴ 750 psig and the bubbles happen every 10-20 minutes. About 3-ft away is the level column. Its lower take-off is about 6" above the bottom take-off for the gage glass, and there is no evidence of a disturbance in the level indication during the time of the bubbles in the gage glass. posted on 2/9/2010

Responses: 1. [ARU-244]: I vote with Nate on temperature and pressure. What are the

acid gases being removed?

posted on 3/15/2010

2. [ARU-244]: For fans of Carl Sagan’s “Contact,” I invoke Occam’s Razor:

Micro foam bubbles gradually disengage in the horizontal line between the tower and gage glass so as to coalesce into one large bubble which eventually burps out.

posted on 3/13/2010

3. [ARU-244]: No real experience to offer. However, the large bubble and

long time leads me to suspect a slow cycling of pressure. The amine is saturated as pointed out by others. If the pressure cycles even a small amount, gas will tend to come out as the pressure is lowered, and since the amine in the sight glass is in contact with vapor above it, it will tend to reabsorb gas as the pressure increases. Trend the column pressure and see if it varies very much and if it does whether the cycle time correlates with the time between bubbles.


-12-

posted on 2/11/2010

4. [ARU-244]: The flash drum in the case I cited was about the same

distance as you describe, and we did see periodic disturbances there driven by the level/stable foam issue in the H2 contactor. However, your instance does not seem to match this.

posted on 2/10/2010

5. [ARU-244]: No significant experience with large bubbles either. Seems to

perhaps indicate foaming or significant surfactant activity.

posted on 2/10/2010

6. [ARU-244]:

What is that old saying – something about curiosity killing the cat? You may want to see if this continues after flushing the level glass. However, the pressure and service may preclude this unless you have some outstanding block valving design.

I think that we, as engineers, do not often give the process credit for unsteady state operations. We tend to want (or attempt to will) the process to be steady. The bottoms is essentially saturated with dissolved H2 and light ends so any move in the process has the potential to release this stuff. Some heavy hydrocarbon emulsion may be causing a delay or reverse temperature relationship here as follows:

1. Some light ends increase in solubility with temperature in heavy hydrocarbon. Assuming there is some emulsion present, then let X = the solubility in a gallon of emulsified amine.

2. Emulsified amine travels into the sight glass where it cools. 3. Gas is released because H2 is less soluble (say 0.9X) in the heavy

hydrocarbon, and even much less so in water, causing a bubble to be released.

posted on 2/10/2010

7. [ARU-244]:

In response to Al, I reviewed the data for the flash drum along with any other process data that was available and could find nothing else that happened at the same time or close to it.

-13-

The rich amine flash drum is 1/2 mile from this absorber so I would not expect to have seen anything or that it would have been dampened out. However, I did look and didn't see anything.

posted on 2/10/2010

8. [ARU-244]:

Bubbles in the gauge glass is not a frequent phenomenon observed by me, but perhaps that is because of not spending enough time looking there. Many many years ago, when we installed a submerged vapor inlet to an amine absorber sump, I expected to see a lot of action by the level controller, as well as bubbles/froth in the gauge column, but neither happened at a level (no pun intended) to be of any consequence.

It would make sense that some entrained bubbles would have to make it to the gauge glass, but would not expect it to be on a predictable frequency. In a number of contactors in Europe, I believe Shell's design scheme is to fill the sump with packing to deal with undercarry of vapor/bubbles. Am not knowledgeable of how common a practice this is in the industry.

posted on 2/9/2010

9. [ARU-244]: I suspect that if we had glass columns like back in school or

at FRI we would see the occasional entrained gas bubbles popping out of the bottoms. I think every once in a while one finds the gage glass the short route. If you look close enough at the level gage there might be a slight blip on a similar frequency, or such a small change may be buried in the "noise".

posted on 2/9/2010

10. [ARU-244]: We've seen some very stable foam in the bottom of HDS H2

treaters that fooled the level transmitters. Are you seeing anything odd in the flash drum gas volume or H2S level?

posted on 2/9/2010

-14-

Question Id: ARU-243 Title: Regen Overpressure Due to Freezing Attachment(s): ARU-243.doc, ARU-243A.doc [ARU-243]:

Attached (ARU-243A) is the sanitized root-cause failure analysis of an incident involving overpressure of an MDEA regenerator due to freezing of the overhead aerial condenser and tower PSVs at ambient temperatures of -15 to -20°F. The pilot-operated Anderson Greenwood PSVs were neither winterized nor free-draining. Contributing factors included lack of condenser variable-speed fan drive, damaged air louver linkage which precluded remote control and false high temperature indication due to tracing heat at low/no condenser offgas flow. What is your experience with pilot-operated PSVs in cold climates? What is your engineering specification for winterization of PSVs? posted on 12/16/2009


Where we have pilot operated PSVs in wet service and cold climates, both the PSV and the reference line are winterized. Winterization needs to be appropriate for prevailing conditions. We had a failure on one application, and needed to upgrade the winterization.

posted on 12/17/2009

2. [ARU-243]:

A somewhat self serving response – BUT, I would suggest reviewing GEN-018; i.e. how many problems could be eliminated if we ‘took care of’ our valves/instrumentation. Also, your guy, Kevin Eckhart, had told me when I was helping Flexxiare with their variable pitch fan hub that there were many applications with process coolers because the pitch can go through null to slight reverse pitch. I know that, in Northern Canada, there has been at least one, and probably more, used in lieu of a re-circ unit because it is less expensive. Anyway, back to the self serving part – www.ges-tec.com has an outdated photo of a really mature person, but some useful information.




http://www.ges-tec.com/�

-15-

3. [ARU-243]:

Ditto what has already been said. I can only add that you need to ensure that the PSV discharge piping slopes downward to the header, with no pockets to trap liquids. Our cold-climate cooler housings have outlet louvers that can be closed to provide recirculation of warm air. They work well. VFDs and 2-speed motors can also help.


4. [ARU-243]: I have not seen pilot operated valves in low pressure amine

service. My experience is that the spring-loaded PSV, piping and bypass piping is winterized. They are also piped above the equipment and the header to ensure draining. On the lake in Indiana (which can get close to that cold) we had a discussion on how far to winterize the tail pieces as they slope to the main header. I don't remember how far the team decided on, but it was at least partially. I have not lost an air cooler with flow in my career, but I've only seen -23°F once and we did lose some un-drained equipment then. My understanding is that air coolers in this service should be built with steam coils. I believe that your refinery on the lake in Ohio has them. Indiana loathes air coolers, I suspect for fear of your type of incident.


5. [ARU-243]:

Like Bill, we also use conventional spring PSVs in most cases. To my knowledge, the main reason for considering a pilot-operated PSV is if the set point is close (within ~ 10%) to the normal operating pressure. For PSVs that may be subject to freezing conditions with liquids present, PSV in/out piping is heat traced, and never pocketed.

We also have temperature indication on the outlet of each cooler bank, which the operators watch quite closely – particularly since we have just come through a spell of -40° weather. We have also on occasion tarped over the louvers (or partially tarped some of them) to better limit air flow. A competitor has gone so far as to hang the tarps on a rod (like a shower curtain) to facilitate accommodating weather changes.


6. [ARU-243]: The reboiler heat medium is hot oil.

-16-


7. [ARU-243]:

While our Engineering Standards do not preclude pilot-operated PSVs, conventional spring-loaded PSVs are used in most applications. The most common reason to use a pilot-operated PSV is to allow a higher operating pressure than for a conventional PSV. I’m curious as to why you opted for a pilot-operated PSV to protect a relatively low-pressure system?


8. [ARU-243]: What is the reboiler heating media? posted on 12/16/2009

9. [ARU-243]:

Our standard, in cold climates, is winterization of the PSV and sensing line. One big problem is that the sensing line may accumulate some condensation which then freezes, thus comprising the pilot signal. As a side note, we have found that overcooling can often be avoided by reversing the direction of fan rotation. I suspect that the vessel pressure rating is 90 psig or more. I would be concerned if that pressure were relieved into an amine sump.


Question Id: ARU-238 Title: Fuel Gas H2S Determination Attachment(s): ARU-238.doc [ARU-238]: Performance data by a testing contractor (not Brimstone) included GC determination of H2S (20 ppm) and COS (80 ppm) in amine-treated fuel gas. The sample was not dried, which I would think would tend to result in partial hydrolysis of COS within the GC column and thus overstate H2S. A few extra ppm H2S reported can put them off spec. Comments? posted on 10/1/2009

Responses: 1. [ARU-238]: You would need to investigate the media in the GC column.


-17-

Often it is a molecular sieve. Molecular sieves tend to promote COS hydrolysis unless specially treated to prevent the filler from acting as a catalyst. I don’t know if they do this to GC columns.

posted on 10/8/2009

2. [ARU-238]:

COS hydrolysis and reverse reaction will occur in the vapor phase, and alumina is a pretty good catalyst. Had one instance of an alumina solid bed dryer removing water from a sour gas (H2S and CO2) resulting in very short cycle times. The H2S plus CO2 would react to form COS and water. Water killed the cycle times and the COS was at least several thousand ppm! Solution was to switch to mol sieve with a binder that did not catalyze hydrolysis. While at Fluor we developed an analyzer kit to test for sulfur compounds. COS was inferred by first removing the H2S, then converting the COS to H2S by vapor phase hydrolysis over alumina.

posted on 10/2/2009

3. [ARU-238]:

I think I know who owns it. I can see why COS could bleed into the fuel gas. You may be able to verify the H2S with a lead acetate style analyzer. I don't believe the COS will react.

posted on 10/2/2009

4. [ARU-238]: Fuel gas source is a Coker on an Alberta oil sands bitumen

upgrader. Amine is 30% DEA. posted on 10/1/2009

5. [ARU-238]: In fuel gas we have purposely looked only for H2S, but I don't

know if any hydrolysis occurs in the equipment pushing us to overtreat. posted on 10/1/2009

6. [ARU-238]: Not sure if this reaction can only occur when liquid (free

water) is available or not. We have seen problems making copper strip when COS has been present in NGL or propane liquid (with free water in it)

-18-

due to hydrolysis of COS back into H2S. If you have free water present in any amount I can see where you would have a problem. If it is 100% vapor phase gas then I am not sure if it will occur or how fast that reaction might be.

posted on 10/1/2009

7. [ARU-238]:

We operate an alumina treater for LPG to hydrolyze COS (followed by caustic treating). If the GC column used alumina, it may be very likely.

Normally we don't see COS in fuel gas if we're getting high propane/propylene recovery from refinery gas plants; it tends to go with the LPG. What is the fuel gas source?

posted on 10/1/2009

Question Id: ARU-233 Title: System Cleaning with Steam Attachment(s): ARU-233.doc [ARU-233]: Have you used steam to clean amine units for entry? I see where we all use some form of base, acid and neutralizer approach, or perhaps specialty stuff like Zymeflow. But has anyone used steam in combination with other chemicals?

Concern was raised that resultant high temperatures might cause stress cracking or damage (unspecified) protective coatings. I am unaware of any such issues, and would think that the added heat would help degas the H2 that could cause cracking. I am missing something? posted on 9/4/2009


We have used both Zymeflow circulation and steam-plus-Zymeflow, and found that the liquid chemical alone generates more waste to be handled than when combined with steam. But, liquid chemical circulation is more effective.

Drawback with the steam/chemical is that you have to ensure some sort


-19-

of circulation with the steam and chemical injection, otherwise you end up with a lot of residual material to be manually removed. There are several companies that specialize in cleaning of such systems.

posted on 9/12/2009

2. [ARU-233]:

We have used a chemical cleaning procedure that involves a chemical solution wash step followed by a step using steam and chemical (Zymeflow or equivalent) for vapor phase cleaning, then followed by a rinse step. The procedure worked very well in the last amine tower we cleaned.

posted on 9/11/2009

3. [ARU-233]:

Our three plants have slightly different philosophies:

• At Plant #1, the contactors are steamed with 1700 kPag (250#) steam. I’m not sure what back pressure, if any, is maintained. This plant has very good amine quality (very little particulate issues), and there is a slight residue left on the trays – in short, it works great. There have been no issues with residual H2S, although this may have been a problem when the contactors were cladded. (Cladding has been removed).

• At Plant #2, we use "pink water" (like Zymeflow) in the steam. There is no recollection of any residue or H2S issues. We recently used a specialty cleaning service (Young Energy’s chemical called "Envirolock") to replace the pink water.

• At Plant #3, we used to steam with Zymeflow. This facility has relatively high particulate levels in the amine. The Zymeflow cleaning left considerable dry product (no danger of H2S release) on the trays which had to be manually removed. This was neither effective nor done in a timely manner. In 2007, we tested another chemical cleaning process for removal of solids. It worked FANTASTIC. After the steaming phase, we did a chemical circulation (downside is that H2S is generated during the acidification step and a path to flare is required). The tower was spotless when opened, permitting immediate entry by inspectors once the inspection trays were removed. The other three towers (Zymeflow wash) were in the same condition as 2003. We tried manual cleaning but there was simply way too much fouling of the bubble caps. We ended up using a "powerball" to clean, but found that to really get everything out, the tray manways have to be

-20-

physically removed from the tower – at additional labour cost.

Our turnaround planner sums it up as follows: "After personally being in the towers in 2003 and 2007, I am convinced that chemical cleaning is the safest and most effective way to deal with any solids. If the amine is clean, simple steaming at high temperatures is proven [at Plant #1]."

posted on 9/10/2009

4. [ARU-233]:

We use steam as a carrier to do vapor phase cleaning of sour water columns, however, we try to avoid using steam in amine systems. If you leave any amine behind in the column and then steam it, the steam vaporizes the water in the amine and concentrates the amine which, in combination with the high temperature, leads to alkaline stress corrosion cracking. We cracked an absorber at our Wales refinery a few years back doing this. We've been using coatings with increasing frequency, usually to coat weld seams in vessels that are part of our wet H2S inspection program. Some go on like paint, others by trowel. The preferred coating seems to change every few years. Most are made by Belzona, which has at least one that can take a 150# steamout.

posted on 9/9/2009

5. [ARU-233]:

Two questions to be answered are whether there are any coatings in the system and whether there are any stress relieved components. If so, steam is not your friend. For equipment that did not have these constraints, hot water wash and/or steam cleaning was very prevalent. However, it did not remove pyrophoric iron and heavy hydrocarbons, nor degas the sludge (particularly of all H2S). It would take a long time to get H2S and hydrocarbon levels low enough for entry. And there was always a subsequent dirty manual cleaning job that could release more H2S and/or hydrocarbon. So, steam cleaning was done for a very long

-21-

time, with very poor success.

All of the problems I noted are why we had so many folks spend a lot of trial-and-error time and effort to find better cleaning methods.

posted on 9/7/2009

6. [ARU-233]: In my opinion/experience, steam-only cleaning would be a

difficult task, since there is typically too much "goo" in the tower to be adequately de-gassed. I have seen vessels pass initial H2S/HC testing, only to fail shortly thereafter due to time-release of H2S, etc. from the muck in the tower – particularly that which is layered onto the trays or packing.

posted on 9/4/2009

7. [ARU-233]:

We used to use only steam, then later a combo of steam and ZymeFlow. Disposition of residual H2S is probably trickier nowadays.

posted on 9/4/2009

8. [ARU-233]: I expect that it would be fine. The only real experience I’ve

had is cleaning vessels that had contained liquid and gaseous hydrocarbons with only very small amounts of H2S. The vessel was not technically sour, but once we began steaming the vapors contained H2S well beyond 10 ppm and it stank! Steam will clean well but no telling how long it might take.

posted on 9/4/2009

9. [ARU-233]:

We successfully cleaned a DEA vapor recovery absorber by bottoms-to-feed lean amine recycle with steam injection to ramp the temperature up to 210°F. The tower was floated on the fuel gas header, with no gas flow. The dirty amine was flushed into the system in the course of restoring operation. I suggest that any contactor with a bottoms pump be provided with a recycle line to permit this procedure.

posted on 9/4/2009

-22-

10.

[ARU-233]: We use steam to heat the cleaning solutions or to get the last bit of stink out a vessel, but not as a primary cleaning agent. I don't see how steam alone would remove any significant deposits.

posted on 9/4/2009

Question Id: ARU-231 Title: Liquid Amine Treating Attachment(s): ARU-231.doc [ARU-231]: I have a 175 gpm DEA unit treating liquid hydrocarbons (C5+ mix or NGL = Natural Gasoline Liquids) that has experienced some high liquid loadings on certain trays. After becoming aware of the high DP, tower gamma scans were done at amine rates of 135, 145 and 160 gpm. The scans showed high liquids loadings on trays 12 through 6 (out of 20 numbered from the top). The results suggest flooding on these trays. I don’t know if foaming would also show high liquid loadings. I have asked the plant if defoamer has been added.

Assuming no tray damage (based on tower scan company report) and no fouling (tower was entered last year), could such flooding be caused by buildup of key components (e.g. C7) trapped in the middle of the tower due to internal refluxing? Reboiler steam demand has also increased. Could I have a layer of liquid hydrocarbons on the top of the DEA in the bottom of this still causing this percolation problem? posted on 7/22/2009


I had our fractionation expert take a look at the scans. His opinion is there is a flow restriction, likely due to fouling. The pattern does not look like foam due to the localized nature. He also believes tray 1 is damaged.

Our recent experience with a system like this was due to C17 - C36 hydrocarbons (mostly paraffins, < 5% alpha-olefins-source is coker gas plant) accumulating in the reflux and making the tower puke occasionally. The lean amine was in the hundreds of ppm HC while the reflux system got up to 60% HC, so it looked like the HC wanted to build up in the top. Interestingly enough, the condensate (NGL stream) they were treating was at times extracting HC from the lean amine!


-23-

posted on 7/24/2009

2. [ARU-231]: I would also look hard at the methanol concentration in the

accumulator vessel. You may just have to dump the accumulator to waste to get it out of there. We have seen this before with methanol but you will also get rid of any other liquid contamination this way. The trick is to keep the contaminant from getting into the amine up front at the contactor!

posted on 7/23/2009

3. [ARU-231]: Attached (ARU-231) are the regenerator (not the contactor)

gamma scans which reveal increased liquid levels on the middle trays as the amine rate is increased. I believe the regenerator bottoms contains substantial hydrocarbons entrained from the contactor that is causing this high tray loading.

posted on 7/23/2009

4. [ARU-231]:

If you can actually see foaming in the liquid/liquid contactor then you absolutely have a bubble point problem. Nate and others have mentioned things to check, and comparison of boiling point with contactor simulation results for temperature at each contactor stage is a must (must correlate to pressure in the column as well). I don’t think that a gamma scan would show foaming in a liquid/liquid contactor unless you were making bubbles (boiling the NGL) due to phase behavior at those conditions. If you can raise the tower pressure you might see your problem just go away. Hot lean amine would not help you much here either. Where do you run your NGL/amine interface? Is it at the top with amine being the continuous phase and NGL being the dispersed phase, or is it the other way around (amine dispersed and NGL continuous)? You will have better luck running it at the top if you have adequate disengaging space. The answer to this question may help you resolve what you are actually seeing in the process variables as well. Are you making the treat?

posted on 7/23/2009

5. [ARU-231]:

-24-

The application is liquid/liquid removal of CO2 and some H2S from NGL. The problem is apparent tray flooding in the middle of the regenerator.

posted on 7/23/2009

6. [ARU-231]: Sorry to be confused, but the description say treating liquid

HC, but the operations description sounds like a gas-liquid contactor application. Can you elaborate?

posted on 7/23/2009

7. [ARU-231]:

Bart's scenario of boiling LPG can be checked if you can safely catch bomb samples of the inlet and outlet liquid hydrocarbons for GC, and compute the boiling pressure at the temperatures you are observing within and around the tower. Different companies have different guidelines, but I would personally say that 20-25 psi margin between the bubble pressure and tower operating pressure is reasonably safe. If this unit has C5+ as you say, then emulsions are also a distinct possibility. I have never seen scan results for a L/L treater, but foaming per se is not possible unless there is a gas phase. I can say that using de-foamers for liquid/liquid treaters will stabilize and make emulsions more tenacious.

What is the liquid hydrocarbon rate and tower diameter? There are some rough rules-of-thumb total superficial velocities if I recall.

posted on 7/23/2009

8. [ARU-231]:

I suspect an emulsion in the rich amine, otherwise the C5+ would presumably come out in the rich amine flash drum. Often such emulsions are evidenced by cloudy-to-milky reflux. Emulsions suggest surfactants, which of course can also promote foaming. One way to let the HCs go overhead is to purge reflux, or raise the reflux temperature. If you’re fortunate enough to have a top bleeder on a horizontal reflux line, it will act as a HC trap from which you can collect a sample.

-25-

posted on 7/23/2009

9. [ARU-231]: I agree with Steve. I have seen columns where material

gets "stuck" in the middle and can't go up or down. It screws up the column until you burp it overhead or slump the tower.

posted on 7/22/2009

10. [ARU-231]: It is possible that you have some hydrocarbon that boils in

the bottom and re-condenses higher in the tower, in which case the only way to get it out of the tower is to drive it overhead or let it out the bottom. This would also require that the absorber was operated with the amine too cold, thus allowing hydrocarbon to condense in the absorber and be sent to the regenerator. To avoid an upset in the SRU, cool the tower and let it out the bottom, although you may exceed H2S limits coming off of the absorber pushing out the top will send it to the SRU and so you will need to be prepared for a potential upset there. I.e.; unless you have a skim draw off of the tower you are going to upset one of the two options.

posted on 7/22/2009

11. [ARU-231]: Not sure if this applies, but we had a Coker come up after a

turnaround at one refinery and, in an over-zealous effort to recover all the propane with their revamped unit, operated a tower in the GRU section such that a lot of the H2S went out with the LPG rather than the process gas. The loadings in the LPG/DEA treater went very high with a resulting high exotherm. Column appeared to be foaming all the time until the GRU was adjusted. I believe we were boiling the LPG in the column where the exotherm was highest.

posted on 7/22/2009

Question Id: SRU-196 Title: Continuous Reaction Furnace Pilot [SRU-196]: Does anyone have continuous pilots to expedite Reaction Furnace restarts? The idea is to only trip the pilot when not proven by its dedicated flame sensor. A discussion at Vail a few years back suggested that continuous pilots are now fairly common, but one burner manufacturer questions the feasibility. This is a 2-zone NH3-burning furnace without O2 enrichmen. posted on 7/26/2010

-26-

Responses: 1. [SRU-196]: my recollection of concern with continous pilots is

deformation if they get hot (flow shut off during shut down or by error). Once deformed it is very difficult to remove for repair or replacement.

posted on 7/27/2010

3. [SRU-196]: We use Stackmatch pilots on our SRUs. They are retractable

but most of our plants leave them inserted and shut the gas off after main flame is lit. A purge is left on the pilot to keep it from overheating. We have one plant that leaves the pilot burning with acid gas in the unit. In all of our plants, an SRU shutdown also shuts off the pilot.

posted on 7/27/2010

4. [SRU-196]: We don't use pilots on any of our Main Burners and are

using high energy retracable igniters (Durag & HEC).

posted on 7/27/2010

5. [SRU-196]:

We have had some continuous Stackmatch pilots in our SRU T'Rx's in the past; most are now being replaced with removable Stackmatch units, as that eliminates the concerns of adequate purging to prevent thermal damage if left in the T'Rx.

In my experience, upon an IPF trip of the SRU, all incoming gas streams are double blocked, thus a continuous pilot would not remain functioning. Also, N2 purges continue, unless the trip is due to high pressure (as measured on the air line, downstream of the final control valve).

posted on 7/27/2010

6. [SRU-196]: My understanding was that the pilot normally stayed on

during a unit trip provided the dedicated sensor continued to prove the pilot flame.

posted on 7/26/2010

7. [SRU-196]:

-27-

I forget the discussion, but how did they fit into the S/D scenerio.

posted on 7/26/2010

8. [SRU-196]:

We don't have any reaction furnaces with continuous pilots. I thought the Vail discussion of continuous pilots was for incinerators - where we do have some continuous pilots.

posted on 7/26/2010

9. [SRU-196]: We have several SRU's with the continuous pilots installed,

the brand we used was stackmatch,.. A couple of the refineries with them love them and they are reliable, the supply gas needs to be reliable and clean.

posted on 7/26/2010

10. [SRU-196]: We do not have continuous pilots in the RF in any of our

sulphur trains.

posted on 7/26/2010 Question Id: SRU-192 Title: Sulfur Pit Eductor Woes [SRU-192]:

I’m not sure how many ABPG members are under a “Consent Decree” with sulfur plants but I have a few questions concerning control of sulfur pit vapors.

I have been asked by one of our facilities about isolation of the pit offgas and the motive steam and allow the jacketed downstream piping to "heatsoak" (in order to melt out any residual sulfur built up in the piping); although pit vapors would now be coming out of the air inlet piping, the logic behind the question makes sense.

Depending on the age of the unit(s) and length of piping runs, sections of the piping may sag over time and sulfur could pool.

As I understand the environmental point of view, any bypass of the eductor is assumed to be a bypass of a control device, hence an excursion from our consent decree of continuous control of sulfur pit vapors.

-28-

▪ How many of our group has sulfur vapors that are being educted (with steam or instrument air as motive) that are free of plugging?

▪ How many of our group has steam or air operated eductors with the downstream side piped to an incinerator?

▪ How many of our group has eductors piped back to the thermal reaction furnace?

· Are there fewer problems with this design?

▪ How many of our group has a redundant eductor system?

Periodic SO2 spikes in an incinerator analyzer could be from (1) small amounts of pooled liquid sulfur or (2) small solidified pieces of sulfur making its way to the incinerator where it is burned; either being result of eductor system issues. posted on 6/29/2010

Responses: 1. [SRU-192]:

Our Consent Decree doesn't specifically address the eductors. Each of our sites is subject to state regulations which grant a maintenance window to repair the eductors or replace with warehouse spare. Usually this works out to a certain number of hours per Quarter that the eductor can be down.

Most of our sites do not have spare eductors (or blowers, in some cases), although all or most wish they had. Typical is a warehouse spare.

All of our eductors are use steam as the motive. Most of these have a limited life, Typical is erosion of the throat leading to poor performance, not plugging. We haven't been very successful in moving to a better metallurgy to prevent this.

None route the pit vapors to the reaction furnace. Some go to Stretford, some go to thermal oxidizers in Wellman-Lord units and emissions are scrubbed prior to release. A few go to the back-end incinerator.

We've seen the SO2 spikes you describe, usually we attribute this to issues with sulfur build-up in the TGU bypass piping due to leaking valves, that ignites during shutdowns when we route through it.

posted on 7/6/2010

2. [SRU-192]:

-29-

Some of our SRUs, mostly the newer ones, have eductors that use heated air as the motive fluid to send the pit vapors to the reaction furnace. These systems have worked well. Some of these SRUs have a backup eductor that uses steam to send the pit vapors to the incinerator if there is a problem with the primary system.

Most of the older SRUs sweep the pit vapors to the incinerator with a steam eductor and do not have any redundancy. There have been a few plugging issues, mostly attributed to insufficient tracing and insulation, but on occasion due to wet steam.

One refinery has 2 SRUs that use blowers instead of eductors to send the pit vapors to the incinerators. One of the SRUs has had trouble with plugging because the pit vapor mixes with the TGT absorber offgas just before entering the incinerator and this section of piping is not Controtraced. The other SRU has this section of piping Controtraced and has not had this plugging problem.

posted on 7/6/2010

3. [SRU-192]:

Most of our plants have steam driven eductors routed to the incinerator with the exception of one SRU that currently vents the pit to atmosphere but has a project on the go to install an eductor – not sure how they have been able to get away with venting for this long. The installations utilize 50 psig steam but the preference for new installations is to go with 150 psig if available to minimize the risk of plugging. At the start-up of one SRU a few years back, the pit vent system and eductor completely plugged off and one of the primary contributing factors was improper design and installation of the Contro Trace system. In addition the steam supply pressure at the location was only 40 psig, further exacerbating the problem. Upon re-design and installation, the Contro-tracing system has been working without issue.

-30-

At our US refinery there is a project underway to improve reliability/environmental compliance by adding another route for the pit vent to the SRU reaction furnace. Currently there is only one steam eductor sending the pit vapor to the incinerator.

posted on 7/6/2010

4. [SRU-192]:

At one of our gas plants we were using steam eduction (55# steam) to the incinerator. This plant recently shutdown. The only problem we had in recent times was when the steam jacketing on the line failed (corrosion to inside of piping) and this led to plugging. This occurred after about 20 yrs of runtime. The other two gas plants have their pits located very close to the incinerator and the draft from the incinerator is sufficient that no additional motive force is required. We don't have consent decrees in Canada so not as restrictive here. We have no redundancy and all the pit vents go to our incinerators.

posted on 7/6/2010

5. [SRU-192]:

Most of our older plants were set up to put the pit/tank vapors only to the incinerator by steam eductor. Stretford equipped plants put the pit vapors to the Stretford evaporative cooler. As the pit vapor contribution to the stack SO2 emissions began crowding out acid gas capacity, we went to either using eductors to the reaction furnace or using D’GAASS to process the sulfur immediately out of the process and sending the D’GAASS overhead to the reaction furnace. Our newest plants do not have in-ground pits, only tanks. The eductor systems in the newer plants we have installed are primarily air driven and go to the reaction furnace. A redundant steam driven eductor is provided, and an alternate path to the incinerator is provided. Sulfur plugging has not been the primary issue in the steam driven systems, the main problem we’ve observed is corrosion. Any liquid water in the system combined with SO2 in the vapors leads to holes and chunks of hydrated iron sulfate (looks like concrete!). We have removed the insulation from an eductor system only to find the insulation was the remaining “wall” of the pipe! Some of this was driven by ground water leaks in the pit or steam coil leaks, some by steam jacket leaks into the piping.

-31-

posted on 7/1/2010

6. [SRU-192]: We normally design our eductors with 150# motive steam

which results in discharge temperatures well above the sulfur melting point and generally more reliable operation.

posted on 7/1/2010

7. [SRU-192]:

How many of our group has sulfur vapors that are being educted (with steam or instrument air as motive) that are free of plugging? Our newer systems are better designed and more reliable than the older (5+ yrs). Attention to details like steam trap operation and missing insulation goes a long way to keep these reliable.

1. How many of our group has steam or air operated eductors with the downstream side piped to an incinerator? All 35 of our U.S. sulfur plants can send vapors to the incinerator.

2. How many of our group has eductors piped back to the thermal reaction furnace? Of these, approx 20% routinely send pit vapors to the RF and this system is mostly independent of the Incinerator eductor except common suction piping which is usually steam jacketed.

3. Are there fewer problems with this design? Reliability is more a function of good design and installation than where the vapors are routed. Eductor should be the high point with suction and exhaust lines well traced, non-pocketed and sloped away from the eductor. We find that properly applied and insulated ControTrace works well. Minimal flanges and no exposed metal.

4. How many of our group has a redundant eductor system? We are upgrading some systems and including a second eductor.

posted on 6/30/2010

8. [SRU-192]: Steve covered the BP sites. There is nothing new from the

other sites I've seen.

posted on 6/30/2010

9. [SRU-192]:

The Shell and Motiva refinery SRU's have some of all the options

-32-

described. One refinery uses heated air for the eductors and all others use medium pressure steam. The eductors (often with a built-in spare) can all be routed to the incinerator, with a number having the capability to recycle to the Thermal reactor burner or directly into the Zone I of the T'Rx (with lots of interlocks and other monitoring for safeguarding). Eductor plugging is not normally a problem, in my experience, provided there is good management of the steam jacketing steam traps and the steam is dry, etc. There are more instrumentation maintenance issues with pit vent recyle; the pay off, of course, is reduced SOx in the stack of typically around 50 ppmv.

Our ---- refinery had significant issues with sulfur pooling up in tail gas lines until adequate line slope could be configured.

posted on 6/29/2010

10. [SRU-192]:

Ours vary with each refinery because some of the consent decrees proceeded the assumption of the refinery.

However most have steam eductors that either go to a caustic scrubber, with the bypass going to the incinerator or the eductor vent goes to the incinerator. In either case typically the eductor discharge piping is jacketed or contra-traced and we have had little problem with plugging of the line. One refinery has a sulfur drain off of the discharge line that is also jacketed that is combined with the condenser rundown line. We do also have one (and others to be designed) where gas (either final condenser off gas or nitrogen) is swept through a sulfur collection vessel and then into the TGU. On those there is no bypass.

The other concern is the discharge of the gas coming off of the tanks and rail/trucks. There is typically an SO2 spike, if those vent gases are routed to the incinerator when we are loading sulfur into a truck / railcar.

posted on 6/29/2010

Question Id: SRU-189 Title: E2T Reliability for High Temperature Trip [SRU-189]: We recently had a loss of containment incident in one of our SRU Reaction Furnaces. The primary root cause was determined to be operating temperature exceeding the refractory temperature rating (3200°F) while firing on natural gas at slightly sub-stoich conditions with insufficient moderating steam. We are waiting on refractory testing results to determine if the brick quality was also

-33-

a contributing factor. Moderating steam was estimated at < 2 lb steam/ lb NG based on the control valve position as the flow meter was not working, which equates to an adiabatic flame temperature of > 3200°F. The refractory brick along the entire top half of the furnace collapsed and showed signs of high temperature deformation. There are three E2Ts installed on the furnace with two located in the front section tied to the SIS on a 1oo2 voting system to trip the SRU on high high temperature. These two devices were reading a difference in temperature of ~300°F and the highest reading only peaked out at just under 2000°F prior to the hole through. The third E2T located in the back section was not working at all, flat lined at 700°F. Not only was there insufficient moderating steam being added due to a procedural error, but the safety shutdown system did not perform as required and actually mislead the Operators of a safe operating condition. The majority of SRUs within our company use E2Ts for high T trips with the exception of the some of the older Gas Plant SRUs that only use them for indication. Following are my questions for the group. Note that some of these items were discussed previously in SRU-021 in 1998, but I would like an update: 1. How many plants have Reaction Furnace high high

temperature trips? Gas Plant or Refinery operation?

2. How many plants utilize E2Ts for the high temperature shutdowns? Have you had a high temperature excursion(s) where they did not trip the unit?

3. How often do you calibrate and by what method – thermocouple, color chart, hand temperature gun, send to factory?

4. How many plants are using Delta thermocouples? Do you consider these to be more accurate and reliable? How long have they lasted?

-34-

posted on 6/2/2010

Responses: 1. [SRU-189]: I don't really have anything new to add. Our sulphur plants

(on the back end of gas plants) have similar set up to Bill's comments. E2T's are for indication only, no shutdowns tied into them.

posted on 6/8/2010

2. [SRU-189]:

All the SRUs in our refineries have high high temperature trips. We use E2Ts for the high temperature shutdowns. I am not aware of any high temperature excursions where the unit did not trip. We have had some nuisance trips due to the E2T going off-scale on the high side due to electrical problems.

We do periodic cleaning of the glass, but I am not sure how often. Recently we have brought in an E2T rep to calibrate the units while the SRU is online. He brings a couple of factory calibrated portable guns with him and uses them to get a temperature and emissivity. Then he adjusts the E2T settings to match the readings he gets on his equipment. I am skeptical on how good this works because we had him come in once when the unit was fairly cool (<2000F) and calibrate the E2Ts. When the unit got hotter, it was easy to see by the color that the E2Ts were not reading correctly. We had to call the rep back in to recalibrate them.

We do not have any Delta thermocouples. posted on 6/8/2010

3. [SRU-189]:

Sobering disussion. I have observed that E2T infrared devices have trouble reading fuel gas fires above ~2500F. As firing is moved towards stoichiometric, the measured furnace temperature flattens out well before stoich is reached. This is in stark contrast to what I recalled computing. If it were a simple flow meter error, then the temperature would have gone down because we moved through stoichiometric firing. This was simply not the case.

The particular E2T that we were working with was clean. I do not know how much further the performance could have decayed as deposits build in the

-35-

view path.

The best that can be done, I think, is to measure a point refractory temperature with a ceramic thermocouple. I say refractory temperature because these devices do not stick in the furnace much further than the refractory (when installed correctly) and are themselves encased in a ceramic sheath that is purged with cold gas.

posted on 6/8/2010

4. [SRU-189]:

At two of the three sulphur plants in my world, we have high temperature alarms but no high temperature shutdowns for our E2T temperature sensors on the reaction furnace. At these locations, the temperature in the RF is relatively low (<1000 C). At the one plant where the RF is a little warmer (~1200 C), we have high temperature shutdowns from the E2T. The set point for the high temperature shutdown is lower than your case, ours is set at 1450 C (2642 F).

At these moderate temperatures, the E2T works fine. posted on 6/3/2010

5. [SRU-189]:

Just wanted to add a few comments.

We use mostly E2T's but also therocouples and do trip on high temperature based upon a voting system.

We have seen that even with the high concentrations of Al in the refractory, good to 3200 °F, that have normal operation and never exceeding 2800 °F during a run, that the refractory on the top is "glazed" indicating that it has seen temperatures above 3200 °F. I also realize that the E2T's are all pointed down, so that any liquid will flow out, that the thermocouple is the only way that you can measure the temperature in the top of the TR.

We have also burned through the upper section of a TR after firing on natural gas for extended periods of time without good temperature indication.

I always think that one of the best ways is for the operators to check, visually, ie use the color chart, to see what it really looks like in the TR and if there is any question, they should slow down/ back down until they know that they are in a safe operating range. This is normally a problem on start-up but any time is good too.

-36-

posted on 6/3/2010

6. [SRU-189]: Folks switched to E2T when they came out because the older

style thermocouple had an average life span measured in nanoseconds. However the Delta appears to be robust and I see a combo of Delta and E2T in new construction. I agree with all the previous comments. An additional comment, many older retrofits used existing nozzles so the E2T's were not necesarilly aimed properly. I'll leave it to guys with operating units to give you a current status and acctual numbers.

posted on 6/3/2010

7. [SRU-189]:

What Computational Fluid Dynamics (CFD) modeling has taught me (from the school of hard knocks):

1. Acid gas and fuel gas flame patterns are completely different in a typical SRU burner. If your temperature devices were place based on the highest expected acid gas firing temperature, it is almost certain it will miss the highest fuel gas burning temperature area.

2. To keep the fuel gas flame temperatures in check, about 5 lb steam/lb fuel gas is needed for slightly sub-stoich firing.

3. No matter how accurate your instrument is, or how well calibrated it is, it seems to measure only what refractory it “sees” (E2T), or the refractory adjacent (thermocouple). What it misses is the 500 F temperature gradient between what is being measured and where the hottest part of the flame is impinging on the refractory or ferrules.

A CFD model will probably cost about $25K to 40 K, but is well worth it to set your operating parameters. I suggest contacting HEC (Dave Sikorsky) as they have considerable experience in the area.

posted on 6/3/2010

8. [SRU-189]:

Very nice summary of points by Ron, so will only add supplemmental comments:

- we (Shell-US) reluctantly used E2T's to trip on high T'Rx temperature in earlier times. With experience gained using the Delta double thermal wells/thermocouple design, have switched to Delta as the Safeguarding device (2oo2 @ SIL 1) and the E2T's as indicating (a good pun might have been to mis-type and refer to the E2T's as "indecaying," since calibration

-37-

drift is ALWAYS in question)

- our typical high temp trips are set at 2900 F, unless circumstances require a lower setting (but not above 2900)

- while a thermocouple will provide a valid temperature-related millivolt output that just requires proper calibration, the E2T's appear to be seriously affected by the gas composition in the T'Rx, thus changing their reported temperature. Believe that is why they initially had some burn-thru's when SRU's began switching to O2 enrichment. Not sure how well their different heads can "read" temperature. But, anytime one has to determine which head, which wall, which flame, which....well you get the picture...to focus on, there has to be serious concerns.

- even good things can have their vulnerabilities: the Delta's must have a large enough nozzle for installation, otherwise, there is a good chance that thermal cycles can result in the refractory breaking the ceramic thermowell(s)

posted on 6/2/2010

9. [SRU-189]:

I was involved in quite a few high O2 mods - both burner only and Double Combustion. Based on testing done on the BOC pilot unit, the E2T is not very reliable at high temps (around 2800 F). All these units had high temp trips. The general feeling at the time was that thermocouples are much more accurate, but the infra red is more robust. I believe we had 3 thermocouples and 2 E2Ts. The E2Ts were calibrated against the installed thermocouples. I'm not positive but I believe the trip was off the thermocouples with 2 out of 3 voting. Theses thermocouples from Delta have a constant N2 purge to protect them and are in a ceramic thermowell. The only problem with the thermocouple is that if you lose one for any reason, it is gone until the next shut down. In practice the thermocouples have proven to be farily robust as long as the N2 purge is maintained. (One thermocouple was lost when an operator stepped on the purge supply tubing).

Incidentally, don't believe that refractory rated for 3200 F can withstand temperatures any where near that. That rating is for an oxidative atmosphere. The reducing atmospher in a Claus furnace is much more severe. Most operators trip at some where around 2850 to 2900 F with alarms well before that.

posted on 6/2/2010

Question Id: SRU-188 Title: Loss of Level in SRU WHB

-38-

[SRU-188]: If the SRU shuts down on low WHB water level and it is thought that the level may have dropped below some of the tubes, what is the best way to go about re-introducing BFW? Should all purging, even instrument purges, be shut off to keep from moving heat from the thermal reactor into the WHB, or should a big nitrogen purge be started to try and cool down the thermal reactor and the WHB? How do you determine when BFW can be re-introduced? Is it at a specific thermal reactor temperature or is some other criteria used? posted on 5/20/2010

Responses: 1. [SRU-188]: No experiences to share on this one.

posted on 5/25/2010

4. [SRU-188]: I have corrected Frank's original response to reflect his correction.

posted on 5/25/2010

5. [SRU-188]: Correction!!! My earlier response should have said to not

introduce water to the waste heat boiler until the temperature at the INLET of the WHB (essentially the MRF temperature) was below the boiling point of water at the rated pressure of the boiler.

posted on 5/25/2010

7. [SRU-188]: Once a tube is uncovered, its potential for going above the yield temperature of carbon steel (800 F) is so high, the expectation would be that the tube was damaged; and there would be a possibility of a liquid water leak. Refilling the WHB with liquid water may condemn the entire exchanger and other parts of the unit to sulfurous acid corrosion failure later on. From the CFD modeling exercise I showed the group at Dallas, it may be possible that a cold nitrogen purge actually ends up going through the bottom side tubes of the exchanger in a purge situation and the hottest gases would be displaced to the top where the exposed tubes are. This would make the heat damage situation worse.

-39-

It appears that choosing a cooling fluid for the shell side of the exchanger in this situation is the key to dealing with residual heat migrating from the refractory. The temporary cooling medium cannot contain liquid water. With shell side cooling in place, the refractory can then be cooled to prepare the exchanger for testing/inspection. BFW addition should not take place until the exchanger is proven not to leak at service pressure.

posted on 5/24/2010

8. [SRU-188]:

It depends upon the design. Is this a "kettle" type steam generator with the steam disengaging zone as part of the vessel, above the steam generating tubes? Or, does it have an independant steam drum, sitting elevated above the waste heat boiler. In the second case, if it can be absolutely verified that there is a level in the steam drum, you can safely reintroduce water to restore the level, similar to a typical steam power generating boiler. If it does not have a separate steam drum, I would advise against trying to "save" the situation without shutting down the unit.

For a unit without a separate steam drum, my recommendation is to shut down the unit, purge with nitrogen or air and do not reintroduce water until the temperature at the inlet of the waste heat boiler (essentially the MRF temperature) is at or below the boiling point of water at the waste heat boiler rated steam generating pressure. Even then, introduce the water slowly.

I never retained the pictures that Bruce Scott had from about 25 years ago. But, they showed what happened after water was reintroduced to a waste heat boiler that had lost its water level. The entire boiler ruptured/exploded from the pressure surge when the water entered teh boiler. Fortunately, no one was knjured, but the waste heat boiler was totally destroyed. The tubes looked like pretzels and pretty good sized pieces of the boiler were thrown several hundred feet away.

With just a low level, you may be able to slowly rebuild the water level without doing damage. And, you might get away with this several times. But, the differnce between success and failure is a rather fine line. And, the difference in consequences is huge, potentially fatal.

posted on 5/23/2010

9. [SRU-188]:

Having seen one of our Deer Park SRU WHB's wrecked when boiler water was re-introduced shortly after Operations realized the level had dropped

-40-

too low, my conclusion is that BFW can not be re-introduced while the boiler is at process conditions. That T'Rx was 75 psig rated. Also, a non-pressure rated (or certainly no more that ca. 15 psig) SRU at the Delaware City refinery actually separated the burner from the T'Rx when water was re-introduced while hot.

I agree that leaving the small purges going is OK, but do have some concern with introducing a large purge volume. Once tubes are exposed, may have no choice than to let the IPF trip the unit and cool down prior to determining if boiler intrgrity is good for re-start.

posted on 5/23/2010

12. [SRU-188]:

I think it would be safe to leave the instrument/nozzle purges on, but I would not perform a firebox purge until an acceptable level had been VERY SLOWLY restored. Unfortunately, the operator's instinct is usually to slam the BFW valve wide open.

I figure the level of the steam/water mixture in the boiler is actually much higher than the water level in the sight glass. Another thought is to vent the boiler in an effort to drop the pressure and thus raise the level as the result of flashing.

posted on 5/20/2010

Question Id: SRU-187 Title: Claus Combustion Air Low Flow Trip [SRU-187]:

Does anyone else have combustion air "low flow" trips on their Claus units? Is the intended purpose for reverse flow?

I have 4 units and all have a trip setting at ~20% of DCS scale and no one knows why. Using conventional flow element this would make sense with ~5:1

-41-

turndown capability. It would make more sense to use something like "V-cone" for a more accurate reading and acheive ~10:1 turndown and have a lot more "wiggle" room (technical term).

All submissions/comments appreciated posted on 5/19/2010

Responses:

2. [SRU-187]: I cannot add anything worth while to what has already been

presented here.

posted on 5/25/2010

3. [SRU-187]:

We have low air flow trips on all of our SRUs with the exception of a couple of the grey haired units. All are implemented for reverse flow protection and in the most recent SRU design we eliminated the 30” check valve due to reliability as mentioned in the previous responses. The trip is implemented as a SIL 2 rated system combined with the flame failure on the Main Burner. A venturi meter with a separate SIS transmitter is utilized for the trip function. I am not aware of any incidents with this configuration not detecting a low flow condition that would require changing to the control valve Dp measurement. We also use the FALL to prevent burner damage when operating at low turndown. This is more applicable to Duiker burners where backfiring can occur resulting in mechanical damage. This can be covered by operating procedure but our experience is Operations will try and operate as low as possible and have seen damage to many of these burners. With the HEC burners this is not a concern as the turndown is usually much lower than the flow meter minimum range.

posted on 5/25/2010

4. [SRU-187]: We do require low flow S/D for preventing reverse flow.

posted on 5/24/2010

-42-

5. [SRU-187]:

We did identify a reverse flow scenario here related to sudden loss of the blower. I've talked to Operators who were aware of this happening with the result of acid gas coming out the blower vent valve and air intake despite the check valve. In our company we've used 3 different trips at various locations to try to address this: 1. low air flow, low pressure on blower discharge, and 3. low differential pressure between blower discharge and MRF. After much review this last year, we've settled on the following as our standard:

Our template says that we need two IPLs for reverse flow. To achieve this we use a DP across the combustion air flow control station. If it starts to indicate a reverse flow then we trip the plant. We use low low flow trips to protect against flame out due an unexpected/sudden decrease/increase in combustion air flow. Again, we think it could lead to a death so we need 2 IPLs – one option is a SIL2 on low low flow. Most air flow meters are venturi because of the low DP but we don’t use these as a protection layer because it is possible for a venturi meter to pass from forward to reverse flow without indicating a loss of or reverse flow. --------------- Team Leader Sulfur Business Network

posted on 5/21/2010

6. [SRU-187]:

We have low air flow trips on our SRU's for the reasons suggested, ie reverse flow.

However, more recently as we are performing PHA's, LOPA's and SIL's even the SD's aren't adequate to protect against employee exposure

posted on 5/20/2010

7. [SRU-187]: We require a low air flow shutdown for the main purpose of

preventing reverse flow. You cannot rely on a check valve. We recently had a reverse flow incident where gases came out the air blower intake on an SRU that has not yet been upgraded to include the low air flow shutdown. The check valve on the blower discharge failed to prevent the

-43-

reverse flow. Several personal H2S monitors alarmed on personnel in the area, but thankfully, there were no injuries. We normally set the shutdown setpoint at the lowest accurate value that can be obtained from the meter. At one plant we used the differential pressure upstream and downstream of the air control valves as the shutdown instead of low air flow because the flow meter was not accurate enough on the low end.

posted on 5/20/2010

8. [SRU-187]:

A few comments from my perspective:

- check valves have been totally discredited for back flow prevention because they are a passive device, incapable of being monitored for functionality until the event. This unreliability is even more likely with low deltaP flow-reversal

- back flow prevention is the primary driver for "low air flow" trip, in my experience. A challenge is establishing adequate deltaP measurement to maintain a reliable response

- since the burners require a minimum of air flow to represent the cumulative flows as being adequate to prevent overheating, then if the low air flow trip functions successfully, the falling dP becomes an additional level of Safeguarding against actual reversal of air flow/flow of process out of the air intakes

posted on 5/19/2010

9. [SRU-187]: See SRU-101. I can't find the reference, but I recall Lon

saying they use the venturi flow signal for the low-flow trip and the low-range PDI (SRU-101) for the reverse-flow trip.

posted on 5/19/2010

10. [SRU-187]: I don't know what the trip is set at but we do have low air

flow shutdowns for the RF burners at our sites. No one here knows if it is intended to protect against reverse flow or if it is just based on minimum turndown and concern about flame stability. We have check valves in the blower discharge line that should be protecting against the reverse flow scenario. So I'm thinking the low air flow is more to protect against the flame going out.

posted on 5/19/2010

-44-

11. [SRU-187]: Projects I have been involved with have had low air flow trips

to prevent reverse flow. Can get a bit tricky with high levels of O2 enrichment because the air flow does go down quite a bit.

posted on 5/19/2010

Question Id: SRU-180 Title: Pit Draft Measurement Attachment(s): SRU-180.doc [SRU-180]:

• Does anyone measure sulfur pit vapor space pressure (draft)? • Is measurement reliable? • Where did you locate the pressure tap? • Has sulfur plugging been a problem?

posted on 9/30/2009

Responses: 1. [SRU-180]: Several sites look at flows around the eductor and

downstream, but I have not seen pit pressure measurement.

posted on 11/9/2009

2. [SRU-180]: We do not measure this either.

posted on 11/9/2009

3. [SRU-180]:

One of our East Coast plants has to monitor pit pressure as part of their environmental permit due to past previous-owner sins. Requirement is to maintain a negative pressure at all times when the unit is in service. They use a regular 316SS PT mounted on the roof. This pit is also used for degassing. The plant reports that plugging is seldom an issue. Regular checks and PM are performed.

posted on 11/4/2009

4. [SRU-180]: We do not measure draft.


-45-


5. [SRU-180]: I believe that most folks are monitoring sweep air flow into

the pit via venturis or other low loss devices as opposed to draft. The issue with only looking at draft is that there is no guarantee that fresh air is sweeping the pit headspace in the location you think it is. If, for example, a gauge hatch was left open or leakage through roof joints was severe, there could be dead pockets of high H2S present above the LEL.


6. [SRU-180]:

For a new project we are using a V-Cone bi-directional flow meter for air intake (which will be jacketed piping). There is insufficient pressure drop for an orifice meter. We have had good experience with V-Cone for single directional flow measurement. This installation will be a learning experience regarding use of a V-Cone for bi-directional measurement.


7. [SRU-180]: We have at least one refinery where they use the eductor

inlet pressure to help ensure that they are below the targeted 25 % of LEL. They are considering moving the pressure sensor closer to the pit because if the eductor inlet line were plugged they may still see a good vacuum. The reliability of the pressure transmitter has been good, as far as I know. The eductor line and associated connections are steam jacketed.


8. [SRU-180]:

Sulfur pit vapor space pressure measurement is not typical from my experience. Operations typically keeps an eye on the pit inlet vents and knows there is an eductor problem when observing a visible exhaust.


9. [SRU-180]:

With induced ambient air sweep, any pit vacuum results from pressure drop across the air inlet nozzles. I question whether

-46-

that pressure drop is normally appreciable or noteworthy. Pascagoula is the exception due to inlet air preheat exchangers, in which case an air-purged DP cell would suffice. We have measured vacuum at the eductor suction to alert the operator to plugging of the line between the pit and eductor. Assuming the line is steam-jacketed, any plugging most likely occurs at flange joints, particularly if un-insulated. My experience suggests that temporary interruption of flow will allow conductance of heat from the jacket to melt the plug.


10. [SRU-180]:

We do not monitor the sulfur pit pressure. We have occasionally measured the eductor suction with a hand gage via a Strahman valve. Some units have flowmeters on the sweep air to the pit, but they have not worked very well.

posted on 10/1/2009

Question Id: TGT-050 Title: Tail Gas PSVs Attachment(s): TGU-050.doc [TGT-050]: I freely admit to becoming crotchety in my old age. One source of irritation is the practice of relieving TGU quench columns, absorbers, amine surge tanks, sumps, etc. to the flare rather than incinerator. Flares are for combustibles (of significant concentration). The regenerator should of course relieve to the flare, but relieving tail-gas-service equipment to the flare unnecessarily creates a potential path for reverse flow. I was once called in to troubleshoot a situation where the operator inadvertently opened the bypass in the course of returning a quench column PSV to service, resulting in a 2-day mystery and major environmental incident due to black smoke from the incinerator. Has anyone else encountered similar occurrences of reverse flow from the flare header to support my argument against relieving TGU tail-gas-service PSVs to a flare?


-47-

posted on 7/8/2009

Responses: 1. [TGT-050]:

We typically have a Quench tower PSV that vents to flare. I am not aware of any incident where we backflowed gas from the flare header into the quench tower.

posted on 9/11/2009

2. [TGT-050]:

On our most recent MDEA-based TGU, we put PSV's on the Quench (set at 15#) and Absorber (set at 50#), both routed to the flare. We used dual PSV's with block valves car-sealed open. No bypass was installed. I don't know of any flare header reverse flow events involving the TGU.

posted on 7/9/2009

3. [TGT-050]:

I don't have much specific experience to draw from, but it seems to me like it would be best to have a dedicated line to a dedicated flare if flaring is required or a dedicated line to a dedicated incinerator if that is what is required. I would also be concerned about mixing water-wet gas with anything that could get cold (or even be influenced by cold ambients) due to freeze potential.

posted on 7/8/2009

4. [TGT-050]:

We haven't had that experience. Our standard design has no PSV on the Quench or Absorber towers (which are stacked), since there are no downstream tail gas valves. Amine sumps vent to atmosphere via carbon canisters. Procedures ensure that only lean amine is routed to the sumps; rich is displaced to the process with lean amine or condensate. I support not tying the TGU, except the Regenerator, to the flare.

posted on 7/8/2009

5. [TGT-050]: I’m not aware of any such incidents. We car-seal closed the

-48-

bypass valves and a specific procedure is required to break the seal. posted on 7/8/2009

Question Id: SWS-026 Title: Plugged Overhead Instrument Tap Attachment(s): [SWS-026]: Has anyone else had issues with ammonia salts plugging the Sour Water Stripper overhead pressure controller? What is the solution? We've had this issue come up from time to time in various towers. Steamout removes the deposits, but they tend to come back over time. posted on 3/17/2010

Responses: 1. [SWS-026]:

As Al suggests, trace and insulate with continuous purge, preferably steam.

posted on 3/18/2010

2. [SWS-026]: We have had issues with salts plugging the overhead pressure

transmitter because the tap was not adequately steam traced and insulated, and have successfully used a continuous steam or N2 purge to keep the taps clear. In one case the thermocouple was only a couple of feet downstream of the pressure tap, and the upstream steam purge caused false high readings at low gas rates which resulted in overcooling of the offgas.

posted on 3/18/2010

3. [SWS-026]:

SWS overhead temperature control is critical. Ammonium salts invariably deposit below 165-170°F.

posted on 3/17/2010

4. [SWS-026]: My experience is essentially aligned with ---'s: steam

trace and insulate the instrument tap, root valve and piping/tubing, and also maintain a continuous 50# steam or

-49-

hot N2 purge. posted on 3/17/2010

5. [SWS-026]:

I've seen successful applications of either an intermittent flush or continuous purge of the instrument taps with stripped water. If intermittent flushing is used, operator buy-in to the importance is critical. In some cases the same philosophy is applied to all instrument taps on the column as well as overhead system. Bottom sight glass taps, for example, can accumulate all kinds of crud and goop. I also like to see connections near the overhead control valve to allow for intermittent flushing of the valve with stripped water or steam. If it is done regularly, there are few problems. If you wait until you have signs of plugging, you may not be able to wash the problems away.

posted on 3/17/2010

6. [SWS-026]:

In Alberta, we use a diaphragm seal, 1-scfm continuous N2 purge and electric tracing to maintain 185°F.

posted on 3/17/2010

7. [SWS-026]:

We steam trace and insulate the instrument tap, root valve and piping/tubing, and also maintain a continuous 50# steam or hot N2 purge.

posted on 3/17/2010

Question Id: SWS-025 Title: Sour Water Tank Vent Odors Attachment(s): SWS-025.doc [SWS-025]: We have an internal floating roof sour water tank with a nitrogen blanket above the floating roof which vents to atmosphere. We are getting high H2S readings at the top of the tank during out-breathing and, consequently, odor complaints. Similar tanks at


-50-

other refineries do not have this problem. There is a sour water flash drum upstream of the tank that operates at 2 psig. Has anyone had a similar issue with a sour water tank and what did you do to correct it? What are some of the options for addressing this issue, and what are the pros and cons of each option? posted on 3/2/2010

Responses: 1. [SWS-025]:

The Shell Martinez refinery vents their sour water tank to atmosphere via carbon cannisters. The canisters are changed frequently – daily in at least one case! The floating oil layer is certainly the longest-standing practice in many refinery sour vapor odor-containment strategies that I am also aware of.

posted on 3/3/2010

2. [SWS-025]:

You can't flash H2S without flashing the NH3 that is holding it there. Perhaps you are getting some H2S-rich hydrocarbon that is weathering. The diesel layer is a good solution to weathering. Occasional skimming will prevent saturation of the HC.

posted on 3/3/2010

3. [SWS-025]:

We had this problem a couple of times. One time was during turnaround when we had to take the sour water flash drum out of service (or we may have been operating it at a slightly higher pressure). The HC layer on the sour water tank quickly became saturated with light-ends and H2S, causing the tank to vent to atmosphere. Changing the HC layer as others have mentioned helped. Returning the flash drum to service (or normal low pressure) fixed the problem. The other incident occurred just after commissioning a new SRU. In this case the sour water acid gas KO Drum, which was pumped down to the sour water tank, was the culprit. Seems that Operations liked to completely empty the drum, resulting in acid gas subsequently leaking through to the tank.

-51-

Maintaining a minimum liquid level in the KO drum remedied the problem.

posted on 3/3/2010

4. [SWS-025]: The pro to this is that it's a simple fix. The con is that over

time the rag layer will tend to grow from transient sources, and if you draw the tank level too low you will feed some of the HCs to the stripper (not good).

posted on 3/2/2010

5. [SWS-025]:

I agree with Nate's recommendation. This is a common practice for storing sour water in fixed roof tanks and has a good history of success. Many facilities have enough oil carry-under with the sour water from their process facilities that they have to regularly skim oil from above the water. Places with an "oil tight" sour water system do have problems with saturation of the oil layer, after which there are odor complaints. As Nate states, changing out the oil solves the problem.

If your situation is "new" and there is an oil layer above your sour water, I would suspect that the amount of oil carried into the tank is minimal and over time the oil that has been in the tank became saturated with H2S.

posted on 3/2/2010

6. [SWS-025]: What are the concentrations of H2S and NH3? posted on 3/2/2010

7. [SWS-025]: Pump about a 1’ layer of diesel above the water to absorb the

H2S. It will have to be changed out if the emissions reappear. posted on 3/2/2010

Question Id: GEN-027 Title: Fireproofing Attachment(s): GEN-027.doc


-52-

[GEN-027]:

Several of our projects are dealing with the question of where fireproofing is required (if any) in the Claus and amine-based tail gas treating sections. What has been your experience with fireproofing in SRUs, amine units and sour water stripping units? posted on 11/5/2009

Responses: 1. [GEN-027]: We do not typically fireproof in the sulfur plant area for the

reasons previously cited. posted on 11/9/2009

2. [GEN-027]:

We typically do not fireproof these units, assuming no potential for liquid hydrocarbon pools.

posted on 11/7/2009

3. [GEN-027]: We have also done the same as Jim indicated – minimal-to-no

fireproofing when there was no plausible case for creating a HC pool fire case.

posted on 11/7/2009

4. [GEN-027]:

My experience is similar to most of the responses; I've seen almost all approaches to the issue. It can depend on location (where in the world) of the unit, site (where in the facility and what is around the SRU), timing (when was the unit built; when was the last major incident in this facility), local regulations, project or facility manager experience and may other factors. A good risk assessment session with appropriate experts should be done to get the "best" answer for a specific facility.

posted on 11/6/2009

5. [GEN-027]:

Steve raises another issue – fire case is often the controlling relief case. When do you not do fire case? Are relief valve and header costs high enough that if fire would be the controlling

-53-

case you would not size for it regardless? I bring this up as a discussion item because I have been posed the question before.

posted on 11/6/2009

6. [GEN-027]:

API 2218 covers fireproofing practices in petroleum and petrochemical processing plants, and I believe it refers to NFPA 30 and OSHA 1910.119 (PSM) as well. I believe there is also some coverage in API 2030, NFPA 15, API 2218 and others. It has been my experience that this aspect of our business is not now and never has been applied consistently across the board, even in facilities built by the same company in different areas of the U.S. They are not consistent within the same company! It mostly comes down to your insurance underwriters and that part of the business. It also connects up with fire brigade philosophies as well as first responder and emergency plans. There is always an opportunity to discuss passive fire protection systems vs. active fire protection systems too when you get into these discussions. Fireproofing is just one of the elements that is involved. You put a bunch of us in a room to discuss this and it would go on for a week.

posted on 11/5/2009

7. [GEN-027]: I have seen this handled differently at sites. Can you have a

ground level fire in an amine or SWS unit? Can you get a pool fire from an adjacent unit? Since Claus units have a fire box, do we fireproof adjacent areas? I would answer no, site specific, and yes. I have seen people with the authority answer all yes without a review just to be conservative. In some projects it may be easier to be consistent and fireproof everything, maybe because you may build a hydrocarbon unit next door in five years.

posted on 11/5/2009

8. [GEN-027]:

We have done the same as Jim indicated. Also, it does eliminate the PSV sizing case for fire if there is no plausible case for pooled hydrocarbon.

posted on 11/5/2009

-54-

9. [GEN-027]: We have gone with minimal-to-no fireproofing when there was no plausible case for creating a "HC pool" fire case.

posted on 11/5/2009

Question Id: LLD-017 Title: Burner Light-Off Sequencing Burner Light-Off Sequencing Basis discussions while conducting my SRU training, there can be a lack of understanding by some Op/Tech personnel of the critical importance of correct sequencing of lighting a burner. The key issue can be simply addressed by considering the explosive range of hydrocarbons and their Autoignition temperatures: Table I. Autoignition Temperatures The following autoignition temperatures (in air) predicted for the components in the SRU, in descending order:

NH3 = 1200 F (explosive in air: 16 - 25%v) H2 = 1075 F (explosive in air: 4 - 75%v) [very high flame speed ! ] CH4 = 1000 F (explosive in air: 5 - 15%v) H2S = 500 F (explosive in air: 4.3 - 46%v); Liquid Sulfur = 450-

480 F

NOTE: We emphasize that the autoignition temperatures noted above are pertinent only to initial lighting of the SRU burners, since they are based on conditions of excess oxygen (air). During normal operation of the SRU, the burner is operated in oxygen (air) deficient conditions. The temperature required to sustain combustion during normal operation are considerably higher than the generic autoignition temperatures of the various fuels when there is excess air available.

SEQUENCING: From the table, it becomes clear that when lighting a natural gas fired burner, it is imperative to start the air flow and then the gas flow. For example, if AIR is started first, the NAT GAS has only to increase its concentration to ca. 5%v in order to reach a combustible mixture. Conversely, if nat gas is started first, there can be a significant “gas bomb” created before the concentration is reduced by air down to 15%v or less. One paradigm trap that may have led people to start nat gas flow first is the admonition that the SRU must not have free oxygen in contact with the catalyst, hot

-55-

sulfur, pyrophoric iron, etc. While permitting uncombusted oxgen to enter the SRU is bad, avoidance of an explosion is more important. Actually, if nat gas is started first, a significant amount of air must flow to lower the nat gas concentration from 100% all the way down to ca. 15%v. Likewise, as soon as the much larger air valve starts to open, the smaller nat gas valve can quickly catch up and raise its gas concentration to the 5%v+ concentration. IGNITION: From the table, it is apparent that attempting to light a nat gas/air mixture without a pilot/ignitor is significantly more dangerous than that of H2S. Attempting to light an H2S/air mixture without a pilot/ignitor is less dangerous, due to both the autoignition temperature being rather low, as well as the explosive region being much broader. In any event, I would not support attempting to “light off the wall,” particularly with the highly reliable pilot/ignitors now on the market. One additional point: When setting up the temperature control loop, my experience is that the burner control/responsiveness is significantly improved by having the TRC set the air flow and have the nat gas ratio controlled to the air flow. After all, the air flow has to move about 9.5 times more flow than the nat gas flow. posted on 8/27/2010 Question Id: LLD-016 Title: Applying LOPA to Amine Unit Design Attachment(s): Part 2 - Applying LOPA to Amine Units 2010 meeting v2.ppt [LLD-016]: Attached are the learnings for amine plant LOPA discussion per our annual meeting. Question Id: LLD-015 Title: Mercaptan Removal Agent (MRA) solvent Attachment(s): Mercaptan Removal Solvent Status.doc [LLD-015]: Per our discussion at the annual meeting, I am attaching the status of ARU-188. In summary, Dow continues to test and reformulate the solvent. posted on 4/15/2010 Question Id: LLD-014



-56-

Title: Sulfur storage pit corrosion Attachment(s): Concrete Pit Corrosion.ppt [LLD-014]: Here is the PowerPoint presentation that I was unable to show at the 2010 ABPG meeting. posted on 4/14/2010 [ABPG – Brimstone Sulfur Symposium at Vail 2010.doc ] LHS/08-27-10


-57-

Amine Best Practices Group Member Correspondence – August 2009 – August 2010 ARU ARU-248 Use of Triazine for ARU turnaround prep ARU-247 Where do the Amine Strength limits come from? ARU-246 Rich amine Filter / Coalescer ARU-245 High Pressure Amine Treating ARU-244 Bubbles in Absorber Gage Glass ARU-243 Regen Overpressure Due to Freezing ARU-242 Merox Extractor Pluggage ARU-241 MEA Reclaimer Caustic ARU-240 Dow UCARSOL GT-10 Antifoam ARU-239 Regenerator Insulation Fire ARU-238 Fuel Gas H2S Determination ARU-237 MDEA Regenerator Entry ARU-236 DEA Tech Service ARU-235 Far East Reclaiming ARU-234 Amine Colors ARU-233 System Cleaning with Steam ARU-232 Sour TEG ARU-231 Liquid Amine Treating ARU-230 Amine Sump Vent ARU-229 Package Amine Units SRU-198 Sulfur Plant QRA SRU-197 Flame Arrestors for Pit Vapor to Thermal Oxidizer SRU-196 Continuous Reaction Furnace Pilot SRU-195 Jacketing vs ControTrace SRU-194 Applied Analytics SRU-193 WHB Fouling SRU-192 Sulfur Pit Eductor Woes SRU-191 DSO Destruction in the SRU SRU-190 D'GAASS Rundown SRU-189 E2T Reliability for High Temperature Trip SRU-188 Loss of Level in SRU WHB SRU-187 Claus Combustion Air Low Flow Trip SRU-186 Acid Gas Balance Line SRU-185 Mercury in Sulfur SRU-184 Fires in N2 Blanketed Sulfur Tank SRU-183 Emergency Sulfur Handling

http://www.abpg.net/QuestionAnswerDetails.asp?QId=740&curpos=1&HomePage=1�




































-58-

SRU-182 High Turndown SRU-181 Prilled Sulfur Flammability SRU-180 Pit Draft Measurement SRU-179 Amoco Degassing SRU-178 Blasch Ceramics VectorWall TGT TGT-052 Tesoro in need of "Loaner" SCOT Booster Blower TGT-051 Incinerator Rental TGT-050 Tail Gas PSVs









ABPG – Brimstone Sulfur Symposium Vail - 2010 · PDF fileABPG – Brimstone Sulfur...

Documents

Transcript of ABPG – Brimstone Sulfur Symposium Vail - 2010 · PDF fileABPG – Brimstone Sulfur...