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ABPG – Brimstone Sulfur Symposium Vail - 2012 Presentation hard copy material

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

II. ABPG Membership

See following page 4

III. ABPG Member Correspondence: August 2011--Aug 2012 See following pages 5 - 33

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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.

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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.

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AMINE BEST PRACTICES – MEMBERSHIP ----- August 2012 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 – Phillips66 11. Kennedy, Bruce – Member Emeritus (formerly Petro-Canada) 12. Bellinger, Brandon – 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 - Phillips66 17. Tunnell, Duke – Business Manager 18. Way, Bill – EnCana Corporation 19. Welch, Bart – Chevron 20. Young, Mark – Suncor Energy

Updated 24-July-12 // lhs

[ ABPG – Membership.doc ] LHS/08-08-12

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Amine Best Practices Group Member Correspondence – August 2011 – August 2012 ARU ARU-256 HNBR Plate Exchanger Gaskets ARU-257 Flash Drum Sediment ARU-258 High MDEA Strength/Loading ARU-259 THEED ARU-260 Tandem Seals ARU-261 HP Rich Amine Sampling ARU-262 ARU-263

Structured Packing Inspection/Replacement Rich Amine Filtration Candidate

SRU SRU-224 Sulfur Transfer Pumps SRU-225 Incinerator Safety Trips SRU-226 Loading Arm Seal SRU-227 Sulfur Pump Trips SRU-228 Concrete Pit Roof Integrity SRU-229 SRU Overpressure - API 520 Task Force SRU-230 Zeeco Burners SRU-231 Capacity Increase by O2/SO2 SRU-232 Qatar Refractory Dryout Incident SRU-233 Burner Management Standards SRU-234 Feed Forward Control SRU-235 Potential New API Doc - RF/BMS/WHB SRU-236 Website for the Petroleum Refinery Information Col SRU-237 SO2 measurements by sulfur customers SRU-238 Tail Gas Valve Torque

TGT TGT-056 Quench Column pH Control TGT-057 Quench Column Filtration & Cooling TGT-058 Supplemental H2 Quality TGT-059 Startup with Claus Tail Gas

TGT-060 RGG Cooler Corrosion

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SWS SWS-030 Water Vapor Calc SWS-031 Tray Efficiency & Packing HETP SWS-032 SWS Bottoms Fouling with Elemental Sulphur SWS-030 Water Vapor Calc GEN GEN-034 Fundamentals of Safety GEN-035 Decommissioning Odorant Tank GEN-036 Ultrafab H2S Scavengers GEN-037 HAZOP / PHA Software GEN-038 Heating Value Analyzers

LLD LLD-001 TGU Mercaptans LLD-002 Rich Amine Flash Drum Alarms LLD-003 Stripped Water pH LLD-004 Presulfided TGU Catalyst LLD-005 Rich Amine Emulsions LLD-006 TGU Booster Blower LLD-007 Fixed Valve Trays LLD-008 SO2 Emission Spikes LLD-009 ARU LOPA LLD-010 OSHA National Emphasis Program (NEP) LLD-011 SCOT Catalyst Sulfiding - Problems LLD-012 Compabloc Lean/Rich Plate Exchangers LLD-013 Oxygen Line Fire LLD-014 Sulfur storage pit corrosion LLD-015 Burner Light-off Sequence LLD-017 Hythe Plant HAZOP & LOPA LLD-018 Legal Implications & 2011 LOPA Update LLD-019 SRU Hot Standby Operation

LLD-020 Startup Lessons Learned LLD-021 Injury Report of Sulfur Burn

LLD-022 Piping Changes in Active ARU

[ABPG – Aug 2011-Aug 2012 Correspondence Log.doc ] LHS/08-08-12

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Amine Best Practices Group Member Correspondence – August 2011 – August 2012 ARU

ARU-257 Flash Drum Sediment

Our fixed-level rich amine flash drum has an underflow weir followed by an overflow weir, downstream of which the pump takes suction on level control. Solids accumulation in the vicinity of the underflow weir is sufficient to restrict flow, requiring the operators to manually adjust the normally-closed suction valve upstream of the overflow weir. • Has anyone had a similar problem? • Any advice?

12-15-11

RESPONSES

1) 12-15-11

A shovel. The drum allows iron sulfide particles to settle and it becomes compacted over time. The compacted solids are difficult to remove without using some force like shovels or water blasting. On a temporary basis, if you can put a standpipe up through the nozzle to get above the deposits, that will achieve some short term relief.

2) 12-15-11 Start skimming the flash tank and/or filter the stream that is being treated in the contactor. Does the amine system have filters in it? Hope the flash tank has a manway! You might want to sample the solids and find out what is falling apart or being introduced into the system while you are down. 3) 12-15-11 I don't remember ever hearing of this kind of problem. Maybe your turnaround interval is longer than ours and we get it cleaned before it gets that bad. 4) 12-15-11 Assuming a packed scrubber on the flash gas, make sure it does not have (or used to have) carbon steel packing.

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5) 12-16-11

We usually find quite a bit of sludge in the rich amine flash drums at turnaround, although I don't ever recall it starving the pumps. We don't have Rich filtration.

The problem may be related to the design of your vortex breaker. We usually have a cage, containing dozens of 1/4" or 3/8" holes, that surrounds the vortex breaker. I've seen sludge buildup around the cage, but there is always a large gap between the top of the cage and the hat on the vortex breaker so that a flow path still exists if the cage starts to plug off.

I've seen stand pipes in towers where the pipe is the suction to a thermosiphon reboiler but don't recall one in this service. It should help. I can't think of much you could do on-the-run.

6) Originator, 12-16-11

To clarify, the flash drum has three sections with feed entering the center and skimmed HCs collecting at the left end. Nominal turnaround interval is five years. At last inspection we found a mound of sludge as follows:

7) 12-16-11 We have definitely seen sludge buildup in the center compartment, and in some cases have added provisions for injecting a flush stream directly under the underflow weir. 8) 12-20-11 I have seen only one case of serious sludge accumulation in a gas plant Selexol flash tank, which had to be shoveled out at turnaround. This was the site where we tested a

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centrifuge for solids removal in a previous post. Unfortunately, the centrifuge was downstream of the flash tank. 9) 1-4-12 We generally avoid a weir in the amine flash drum. Our contaminants are generally lighter than the rich amine, so there may be a skimming box but there is generally no weir. The only suggestion I can offer is to install rich filtration. 10) 1-6-12 Our dirty amine system flash drums don’t have the underflow baffle, only an overflow for the HC skim – likely not as efficient for separation but avoids the plugging issue you are experiencing. Could consider cutting slots in the underflow baffle and amine outlet weir to effectively make one large compartment. If the HC separation becomes an issue then look into either an inlet gas or rich amine filter/coalescer. 11) 1-6-12

Surprisingly, rich filtration may not be the answer due to failure of the operations folks to appreciate the importance of solvent hygiene.

When filtering by hole size, all particles smaller than the hole will pass through. Thus, even full stream filtration operates no differently than slipstream filtration. If particles must gain size to be filtered by adding more precipitated Fe+2 and S-2, any particles passing through the filter holes immediately begin weight gain. What better place to gain the weight than in a nearly stagnant liquid with 30-min residence at the highest concentrations of both complexed Fe+2 and dissolved H2S – the rich flash drum?

The tendency that defeats rich filtration is that if the filter changes become cumbersome or expensive, the operations staff may choose to put off filter changes by – ta daa! – bigger hole size! What this means is that more and bigger particles will go to the flash drum to become more great big settled particles.

If choosing rich filtration to deal with the problem, the staff has to be committed to filtering the solution with ever smaller hole sizes in the filter to prevent the particles that leave the filter from becoming large enough to settle in the flash drum. This will allow the passing particles a chance to revisit the filter at a size that the filter can remove without giving them a chance to fall out before being able to return to the filter. The initial cost of filters and labor may be high, but there will be money saved by reducing turnaround frequency and turnaround cleaning time and labor.

We are visually misled by rich solutions because they turn dark and show particles faster than lean solutions. It is misleading because the solution from the sample point for

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either the rich or lean likely has the same particle population and size distribution for a given filtration hole size. The difference is that the rich amine has much more precipitating agent concentration (dissolved H2S) available to help the small particles in the solution grow faster than in the lean solution, giving the appearance of a higher concentration of particles.

The “smallest hole” filtration strategy can be applied just as well with lean filtration, and even slipstream filtration, achieving the same results as if applied in the rich filtration case. I observe in systems filtered by ConocoPhillips technology that the rich solution will remain much clearer than in systems filtered by conventional filtration because the ConocoPhillips particle remover is operating at the 0.1-0.5 micron level on a slipstream versus the 5-70 micron range for most conventional filtration installations.

12) 1-6-12 Your sketch implies sedimentation is greatest at the point of highest velocity, which baffles me (no pun intended). Perhaps flashing occurs as the result of local pressure reduction due to the temporary velocity increase as liquid passes under the weir (the same phenomenon responsible for lift of an airplane wing), causing accelerated corrosion of the weir compounded by downstream cavitation as the bubbles collapse upon pressure recovery. ARU-258 High MDEA Strength/Loading We are investigating feasibility of debottlenecking by increasing MDEA strength/loading. Modeling by two different software systems predicts we can go to 48 wt-% MDEA and 0.5 mole/mole rich loading, with the exception that the low pressure absorbers are unable to achieve 0.5 m/m. • Do you have actual data demonstrating stable, reliable operation at these conditions –

i.e.; have the models been validated? • I am particularly concerned about the effects of increased viscosity in the LPG liquid

treaters. 1-25-12

RESPONSES 1) 1-25-12 We've done this in TGUs at a couple of facilities – I've seen up to 60 wt-% on some samples and operation has generally been OK, although the towers tended to foam more often.

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In main systems we have not been able to go that high. I have two refineries that are running MDEA and one finds that the liquid treater becomes unstable if they go much over 40 wt-%. The other can't even consistently maintain that strength due to excessive losses. This system also has a liquid treater which is where I suspect a lot of it is being lost. They plan to recover the MDEA with a water wash. When we were designing for an MDEA/DEA blend, the amine supplier indicated anecdotally that most main systems they see tend to be in the 38-42 wt-% range, whether the blend or just MDEA. Maybe you can get your amine supplier to show you some "name withheld" plots of MDEA strength that would show whether anyone is capable of keeping the strength up consistently. My guess is the ones that can don't have liquid treaters. 2) 1-25-12 I have one site that normally runs 46-52% MDEA on the refinery main system because the high pressure GOHT scrubber is circulation-limited and rich loading is routinely 0.5-0.55 m/m. They have modified some rich piping in this circuit to reduce velocity and used SS in critical areas. Reliability has been good. The LPG contactor has water wash and coalescer to recover carryover. LPG temperature is held at 110-125°F. 3) 1-25-12 Our corrosion model shows that rich amine loading should be held below 0.45 for MDEA. We can easily reach 0.5, but severe CS corrosion results. Fuel gas treaters will have a problem reaching both high loadings and low H2S in the treated gas. Amine losses were excessive at high MDEA concentrations until we retrofitted the overhead KO drum with a water wash. 4) 1-25-12 We have natural gas treating systems that run at 50 wt-% and 0.55 m/m, and sometimes higher, but I don't think we are doing this in liquid treaters. We still push the envelope in liquid treaters, I just don't have any quick information. I will almost guarantee you that corrosion will be a large problem at the high loadings (which come with high temperatures as well) and you will end up having to install SS in key places, if not everywhere on the rich side. Amine degradation seems to hasten when operating at high loadings and high temperatures as well. 5) 1-26-12 Most of my work is also with gas treating using MDEA. We have run MDEA concentrations to as high as 53% but try to keep at ~50%. Agree the loading should be kept below 0.5 m/m. 6) 1-27-12 We have several units operating in the 45-50+ wt-% range without any significant issues, but I don’t have any rich loading data. Accelerated corrosion rates in some of the units

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but was attributed to high bicine levels. We are in the process of gathering data for simulations to better understand the operation and will update with more info when available. 7) 3-12-12 We target 50% MDEA in our gas treaters. 8) 4-17-12 The main considerations in a liquid treater are the solvent viscosity and solubility of heavy hydrocarbons, especially BTEX. I have tabulated these values below for 45 and 55 wt-% MDEA at 100°F and 120°F. 55 wt-% MDEA is quite a bit more viscous and holds a LOT more BTEX than at lower strength.

ARU-260 Tandem Seals • What is current practice regarding tandem seals for pumps in the sulfur block – rich

amine, ARU reflux, SWS charge, SWS reflux or pumparound, acid gas KO drum, etc.?

In the units we have built over the past few years most of these pumps have had tandem seals, but there is a lack of consistency among different locations. One site might have a tandem seal in one service while another site will not have a tandem seal in that same service.

• This is similar to ARU-047, but that was from 10 years ago. Have practices changed since then?

3-26-12

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RESPONSES 1) 3-26-12 I would say that environmental standards are much higher now and that double seals are more frequently required everywhere. We see it more on hydrocarbon service pumps but of course anytime there is a potential for toxic gas or fires there will be serious consideration of going the double seal route. 2) 3-26-12 Agree, we also have some with the dry gas seal design, mostly as result of increased environmental scrutiny. 3) 3-26-12 In general, double seals = standard practice for any scenario that would otherwise result in H2S emissions. 4) 3-27-12 For > 300 ppmw H2S our standard requires the use of API 682 seal flush plan 74 – dual pressurized N2 seal. ARU-263 Rich Amine Filtration Candidate As seen in the following photos, the rich amine is extremely dirty, yet the lean is surprisingly clean despite only 10% slipstream filtration. In fact the lean filter inlet appears almost as clean as the outlet.

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In my simple mind, the filters are doing nothing. So where is all the rich amine black gunk going? They do report very frequent filter changeouts and lean/rich plate exchanger cleanouts, and major sludge buildup on tower trays. • Is it possible their amine system is acting as a lean amine filter before it has a chance

to get to the actual filters? • How can the filter elements be so plugged, but the lean amine slipstream to the filters

is “clean”?

5-18-12

RESPONSES 1) 5-18-12 Looks like a good case for rich side filtration. 2) 5-21-12 It is common for rich amine to appear dirtier than lean, although not to the extremes in this case. My understanding is that as H2S is stripped in the regenerator, residual iron is complexed by amine degradation products that happen to be chelating agents. According to Jim Jenkins, bicine in particular is a strong chelant. Despite heavy fouling, I’m sure the % of suspended solids precipitated from solution in a single pass is insignificant. The lean amine may not be as clean as it looks. In the photo it appears hazy, suggesting an oil emulsion (naphtha would strip out in the regenerator). If you tried to read print through the samples, the filter outlet may in fact appear significantly clearer than the inlet. If they are using polypropylene (or other synthetic-fiber filter elements), I suggest switching to cotton which has some adsorbency. I’m having trouble reconciling sludge analyses of (1) 48 wt-% moisture, (2) 47 wt-% loss on ignition, and (3) 95 wt-% combustible matter. Regardless, iron is only ~ 1.5 wt-%, so most of the deposit is either organic or elemental carbon. Assuming the former, most likely both rich and lean contain emulsions which, in my mind, could promote

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effective dispersion of FeS to render the rich opaque, while complexed iron would be invisible in the lean. A less likely scenario is that elemental carbon from a heavy oil gasifier accounts for most of the black particulates in the rich. In my experience, partial ox carbon is likely hydrophobic and would be extracted by an oil layer which may accumulate in the bottom of the regenerator. I suggest two simple lab tests: 5) Add hexane or light naphtha to a rich amine sample to see if the black particles tend

to concentrate in the hydrocarbon phase. 6) Filter sufficient rich amine to accumulate a reasonable amount of sludge which can

then be acidified. FeS dissolves, carbon doesn’t. 3) 5-29-12 Sounds like sludge on the trays points to the system doing a pretty fair job of separation and precipitation of solids – probably need to check the flash tank and the still bottom head for similar buildups. The reboiler may be fouled as well, and if there is a surge tank then that may be filling up too. 4) 5-29-12 Remember that filters are for particulate removal and they are probably doing that, although it may not be visible in the samples. The black "shoe polish" is common in amine systems and we have seen it come out more in the regenerator towers, but also in the feed side of the feed/effluent exchangers. It is a mix of some hydrocarbons and amine. And yes, I agree that this is another application for filtration on the rich stream.

SRU

SRU-227 Sulfur Pump Trips

We have some new units that are having difficulty with sulfur pumps tripping as the unit rate increases. The plants are attributing the problem to overheating and/or high viscosity sulfur, but everything is jacketed or ControTraced with 52 psig steam (~ 300°F). The pumps are vertical Lewis pumps and are installed in a "collection header", not a conventional concrete pit. 12-6-11

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RESPONSES 1) 12-6-11 Lewis in particular recommends 35 psig steam to the pump jackets. The pump shaft bushings are sulfur lubricated, and higher local steam pressure has been found to result in viscous sulfur within the bushings. See attached bulletin (SRU-227A). 2) 12-6-11 Our Shell Scotford sulfur pumps (degassed sulfur) had lots of problems initially with Lewis pump bearings overheating. There were some indications of inadequate sulfur flowing into the bearings. Am not sure if there were any mechanical adjustments made, since I recall that Lewis initially claimed "all is OK with the pump design." We have similar pumps at the three new SRUs at Motiva Port Arthur that we will be starting up around first of 2012. A mechanical person there is supposed to be checking with the Scotford folks to discuss their issues in greater detail. Will report back to ABPG when I hear the results. 3) 12-6-11 Check the bearing clearance on the pumps. GAA presented a paper at Brimstone in 2005 (attached excerpt SRU-227B) that discussed sulfur pump overheating/fire issues solved by increasing the pump bearing clearance from 0.012-0.014" to 0.020". Also talks about the steam pressure and pump differential expansion problems. We recently had a pump lock up due to uneven heating of the casing and shaft, but fortunately no damage. 4) 12-6-11 Have they checked the NPSH available, suction piping geometry and discharge pressure piping for hydraulic issues? What do the pumps actually trip on? Vibration, bearing temperature, motor overload, during starts? Is the power supply all checked out as adequate? If they trip during steady increases in flow rate do the pump curves match the intended service? I always go back to the basics on these kinds of things. 5) 12-6-11 To prevent the pump lockup I think was described on new unit startups, a Lewis field rep advised us to leave steam off the pump boot jackets until the sulfur level is two feet above the pump bowl for 12 hours. Otherwise the boot can grow more than the shaft, potentially jamming the impellor against the case. However, I saw no such caution in the Lewis instruction manual on a recent startup.

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6) 12-6-11 We have a similar problem with pumps tripping when % O2 enrichment increases to the point that sulfur rundown from the first condenser exceeds 330°F, resulting in an average pit temperature > 300°F. One plant solved the problem by circulating 250°F condensate through the pump jackets when on O2. In addition to 35 psig steam, one sulfur expert recommended retrofitting our vertical pumps with 1800 rpm motors. 7) 12-6-11 We had similar issues with Lewis pumps, attributed to overheating. Bearing tolerances increased friction and pumps tripped and/or caught fire. Lowered steam pressure, checked bearing clearances and everything has improved. 8) 12-6-11 Attached SRU-227C was presented at Brimstone this last year by a German pump manufacturer. A fair amount of time was spent discussing bearing clearances and steps required to prevent overheating. An interesting read. 9) 3-13-12 We were, and to some extent still are, having issues with Lewis sulfur pit transfer pumps on a new unit tripping with high degassed sulfur temperature. The pumps run continuously (3600 rpm). We increased bearing tolerances and routed the bearing flush in parallel, instead of in series. This has helped to keep the pumps from tripping, but the pumps will still trip if the sulfur temperature reaches ~ 315°F. In the following picture you can see the tubing that feeds the bearings in parallel.

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SRU-228 Concrete Pit Roof Integrity

A challenge has been raised at one of our refineries about the justification for installing gratings on top of the existing sulfur pit. • Do any of you have actual experiences where pit lid failure placed personnel in

danger? The refinery’s pit lid had deteriorated to the point that rebar was showing where the concrete had spalled off, and you could indeed see through the holes into the pit. One argument is that perhaps pit lid deterioration develops over such a protracted period of time that there would be lots of warnings prior to the pit lid becoming weakened to the point of endangering personnel. 12-8-11

RESPONSES 1) 12-8-11 The quick answer is no, we haven't had a sulphur pit lid failure, but we are continuing to monitor the condition of the concrete pit walls. We have noted cracks and holes developing since the last turnaround inspection. Our oldest concrete sulphur storage pit is 16 years old with a capacity of 3,000 tonnes. Although we haven't had a failure, I would support the idea of a grating if access is to be allowed. In our case, we don't permit anyone to walk on the top of the pit. 2) 12-8-11 Yes, we have had a pit roof failure where a complete section of the roof caved in. This was a very large pit, maybe 60' x 100', where the roof had been used for both pit access and general foot traffic. It is currently our recommendation that pit roofs be periodically checked for strength, and to either minimize or eliminate access. In refineries with small day pits we recommend installing grating over them where access is required. 3) 12-8-11 We had a couple of pit roofs spall off 2-3" of concrete on the underside and go unnoticed until pit inspection. Not enough spalling to cause failure, but the risk was certainly there. We have put down grating on or above some pits to access equipment. We discourage non-essential foot traffic over pits. 4) 12-8-11 I know of one facility that won't let anyone on the roofs of three particular pits out of concern for damage. I haven't seen a complete concrete roof failure, but know of several questionable pits that

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no one is allowed on in other plants as well. _______________________________________________________________________________________ 5) 12-8-11 One large Canadian gas plant reportedly had major issues with their pit roof and I understand did not allow access. 6) 12-8-11 We had a pit roof that was discovered to be in bad shape, following which no one was allowed to walk on it. This was in effect for over a year until the roof was replaced during a turnaround. We also had another pit roof that was condemned upon inspection of the pit during a turnaround. The roof had to be replaced, which added to the turnaround work scope. 7) 12-9-11 Structural Preservation Systems is currently evaluating the roof of one pit using ground penetrating radar to help define work scope in preparation for turnaround. The technique can reveal loss of concrete or laminations. It takes about a day to complete the survey then about two weeks to crunch the data. End result is a map of the roof noting areas of compromised integrity. I was impressed with their expertise using this technology. 8) 12-9-11 I have noticed that, while not universal, it is fairly common practice to NOT allow traffic over the pit roof. No direct experience with failure placing personnel in danger. 9) 12-10-11 So, my conclusion from an earlier response is to see if Structural Preservation would like to expand the use of their radar detection technology to search for tunnels under the US/Mexico border, to locate drug smugglers...and elsewhere, to look for terrorists! 10) 12-11-11 We've had a refinery rope off a pit roof for about a year until the next turnaround due to integrity concerns, but don't have a blanket policy preventing roof foot traffic. 11) 12-12-11 We only have one plant with a concrete pit lid and after 40 years it is still in good shape. Walking is allowed on the concrete lid and no one seems concerned about it. At the other facilities, we have aluminum pit lids and there is no walking on these lids – they have grating / catwalks for access to the rundowns, pumps and such.

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12) 12-16-11 We have not had any failures of pit roofs. We have seen superficial cracks and have laid large sections of aluminum grating (simply to distribute weight out) over these pits. When Pritchard designed one of our units in the mid 90s, they insisted on a cat-walk above the pit roof based on their claim that a roof had collapsed and someone had fallen into the pit.

SRU-232 Qatar Refractory Dryout Incident

A few years back, some sulfur recovery units at the big gas processing facilities in Qatar were being started up. There was an incident where a temporary heater being used to dry out refractory exploded and killed someone. Does anyone have an industry bulletin or report concerning that incident? 3-12-12

RESPONSES 1) 3-13-12 There is a brief discussion on the following Qatar Gas web site. It would appear that enough gas flowed into the vessel to create an explosive mixture before they tried to ignite it. http://www.qatargas.com.qa/SafetyAlert.aspx?id=207594

SRU-233 Burner Management Standards

• Is there a particular standard that you are aware of that SRU burner management systems must be constructed to? 4-19-12

RESPONSES 1) 4-20-12 In my experience, the BMS is established by the client setting the requirements with the detailed engineering company. 2) 4-23-12 Agree, NFPA (for process heaters/boilers) is hard to use as a guide as it doesn't really apply to the Claus Furnace.

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3) 4-23-12 We have to follow Canadian standard "CSA B149.3 – Code for Fuel Approval of Fuel Related Components on Appliances and Equipment" but of course this is more applicable to conventional firing. To vary from this code in Alberta we need a Municipal Variance (local jurisdiction approval) and have it designed and stamped by a Professional Engineer. So, at the end of the day, we are using the CSA B149.3 as a 'guide' and fully documenting where and why we need to take exception. 4) 4-24-12 My experience has been much like others. There is no "officially recognized" standard in the U.S., but a lot of people fall back to some of the fundamentals in the NFPA which, as most of us are aware, does not really address the issues we face in our facilities. I suppose you always have to watch out for local jurisdictional requirements, but unless you shake some trees you might not ever know and you could stir up quite a storm. 5) 4-24-12 From one of our engineering standards: "Design and selection of the type of BMS system is typically based on requirements set by ANSI/ISA 84.00.01-2004 Parts 1-3 Safety Instrumented Functions (SIF) in BMS." These designs range from simple relay systems to field PLCs to the DCS. TGT TGT-057 Quench Column Filtration & Cooling • Can I get a show of hands from those without sidestream quench water filtration? • Is anyone using plate exchangers for quench water cooling? Gasketed or welded (e.g.

Compabloc)? 10-6-11

RESPONSES 1) 10-6-11 Have some with filters and some that have bypassed them completely. No plate exchangers. 2) 10-6-11 We have sidestream filtration on most of our units and recommend it for all new ones. Never will I agree to use plate exchangers in this service due to the fouling issues and struggles to clean them.

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3) 10-6-11 We have three Stretford Contact Condensers without filters. Our new SCOT has 10% sidestream filtration. But the SS circulation loop is so clean that the filter only catches trash and the occasional sulfur glob. I push for Compabloc for most exchanger applications, but we only have shell/tube and airfans in quench water cooling service. 4) 10-6-11 We have sidestream filtration on most of our units. We do not use plate exchangers in this service. 5) 10-6-11 Most of our TGUs have quench filtration at ~10%, with exception of one Flexsorb TGU that has none. No plate exchangers in quench service. 6) 10-6-11 I have not seen a unit without filtration. Back in my BP days, one unit had plate exchangers. They didn't like them and may have switched them out. Another refinery was building a new unit and during our tour of existing units they fell in love with Compabloc. It was at a tiny unit in the northwest and the operators loved it. Unfortunately I faded out before installation. 7) 10-7-11 All our units have 10-20% sidestream filtration. One unit is using gasketed plate/frame trim coolers that require frequent backflushing. Other units use shell/tube, but the newest SCOT unit will have Compabloc in this service. 8) 10-13-11 Most of our newer US SCOTs are using full-flow filtration on the quench water circulation loop. If confident of no SO2 breakthroughs, then less filtration should be fine. Allowing sulfur to form in the quench water and line carbon steel surfaces can result in under-deposit corrosion that leads to hydrogen blistering. 9) 12-16-11 All five of our quench systems have filtration – four full flow and one at 33%. Cooling is either by shell/tube or airfans. TGT-058 Supplemental H2 Quality We are taking advantage of low-temperature hydrogenation catalyst to replace an RGG with HP steam reheat, thus requiring supplemental H2. The H2 stream is from a platformer and at best contains 75% H2 with the other reformer cats/dogs.

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• What problems should we expect from the hydrocarbons, either in the catalyst or amine?

I would think the heavy ends could accumulate in the amine and cause foaming eventually. 12-11-11

RESPONSES 1) 12-11-11 Low-quality reformer H2 contains two very bad actors – chlorides and hydrocarbons. Chlorides will irreversibly damage the catalyst, and the HCs may crack and/or plug the pores. The amine problems will come later, not the least of which will be buildup of heat-stable thiosulfate when the catalyst begins slipping SO2. Ugh !! We have had pooped-out catalyst that chronically slipped SO2, small enough to not noticeably impact quench water pH, but enough to produce a slow, steady rise in HSS. 2) 12-11-11 I agree. Steve Massey (Criterion) was dead set against reformer H2 due to likely coking of the catalyst. In my experience, with three Claus stages you can generally adjust the air demand set point to maintain 2% H2 at the TGU without supplemental H2. 3) 12-11-11 I agree – should have enough H2 in the tail gas so that supplemental H2 is not required. Not sure if it is a matter of adjusting air demand as much as keeping the front zone hot (which is typically done in a refinery to destroy NH3). Dissociation produces H2 and it does not all disappear on cooling. 4) 12-11-11 I think that most of the problems have been mentioned. In the plant that I know about, the biggest problems were from the hydrocarbons in the amine, particularly aromatics conducive to foaming and emulsions. If you are close to SRU/TGU capacity limits you may not be able to go high on the tail gas ratio, otherwise that is a good choice to avoid the need for supplemental H2. 5) 12-12-11 Here's another problem: this refinery does not have natural gas or reasonably constant fuel gas quality, so is using this same reformer gas as fuel to the RGG. Over the past few years, they have sooted the hydrogenation reactor so often and so bad that they start up the recycle eductor and eventually pull a vacuum downstream of the reactor. This results in air being

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sucked in, fouling the system with sulfur and contaminating the amine. Without a consistent source of fuel gas, which option do you recommend? 6) 12-12-11 If you are asking how to better operate the RGG until decommissioned – make sure SRU is on ratio and adjust RGG air/gas to maintain 2% H2. Is burning propane an option? I'm confused. Are they somehow using the recycle eductor as a booster blower? Booster blowers routinely operate with negative suction pressure. 7) 12-12-11 This is a Comprimo design with an eductor after the quench column. They start the eductor to help with plant hydraulics when the SCOT reactor ΔP becomes high. They can get more feed in the SRUs with the eductor online but they also start to pull a vacuum downstream of the reactor. This is where they have found leaks that allow air to be pulled into the process. 8) 12-13-11 We are using SMR H2 in our new LT SCOT and expect only intermittent use during upset conditions as there should normally be sufficient H2 in the tail gas as previously mentioned. There is concern even with SMR H2 of lube oil carryover and have made provision for a future filter if this is an issue. As an aside one of our plants currently has so much H2 in the tail gas that it is interfering with stack O2 measurement. Regarding the reformer H2 contaminants, it seems you are just transferring the problem from a burner fuel issue to the direct H2 injection and, although this may be an intermittent feed, the contaminants will still deactivate/plug the catalyst and reduce the run length. To improve the reliability of the unit the Reformer H2 needs to be cleaned up with a chloride removal bed and additional purification to remove the hydrocarbons. 9) 12-13-11 We use reformer H2 in four of the five refineries with TGUs. In two of these plants, the reformer H2 is also used as the fuel source to the feed heater burner. We rarely have issues with sooting. However, H2 purity is typically > 90%, possibly because the reformers are CCRs. In addition, all the H2 goes through chloride guard beds. Years ago, when there was a reformer catalyst issue at one of the refineries and H2 purity dropped into the 70% range, the tail gas reactor bed was sooting up every couple of months until the reformer catalyst was changed out.

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10) 12-16-11 Agree with others’ comments. We have two units currently on reformer H2, and are installing purchased H2 capability for the reasons mentioned. 11) 12-16-11 Within the last three months we have commissioned two new units with steam preheat (both saturated/superheated) and using reformer H2. So far, the catalyst is operating at 480°F inlet and no signs of hydrocarbon fouling/deactivation. Another of our plants has run this way since 2003 without incident, but not with LT catalyst. They had a choice of two H2 sources. One gave them some heavy liquid, but it did not do anything beyond accumulating in the preheater and increasing pressure drop. We drained the liquid and switched to the other source and have since been free of problems. In most other plants we tend to specify PSA hydrogen first before going to less pure sources. 12) 12-19-11 I have seen problems as mentioned with liquid HCs in reformer H2 causing soot problems over the 3-5 year catalyst life. These units benefited from installation of efficient KO drums on the H2 stream, located close to the TGU reactor. TGT-060 RGG Cooler Corrosion Since last turnaround we have seen a significant increase in process-side pitting on the lower portions of the carbon steel tubes in our SCOT RGG Waste Heat Boiler (before the Hydrogenation Reactor). Steam pressure is 380 psig. Recent changes include a sweeter crude slate and new SRU – both resulting in high turndown forcing us to recycle tail gas using the startup blower to moderate RGG outlet temperature. • Has anyone has a similar experience? 3-6-12

RESPONSES 1) 3-6-12 Has the process exit temperature decreased significantly with the change? 2) 3-6-12 More questions than answers: • What is RGG fuel, air/gas and steam/gas? • Is startup blower suction negative? • Does startup blower have tandem shaft seals with N2 pressure? • Is burner high intensity?

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3) 3-7-12 What is your BFW temperature and where does it enter the heat exchanger? I had experience with an SRU/TGU operating at high turndown with BFW entering the bottom of the exchanger at generally < 250°F, and sometimes closer to 200°F. The sulfur condenser bottom tube rows plugged with solid sulfur, compounded by under-deposit corrosion, and the TGU Reactor Effluent Cooler bottom row also corroded rather quickly. 4) 3-7-12 Pitting is typical of under-deposit corrosion. If burner is low intensity, are you occasionally making soot at high turndown? Cold recycle gas is typically combined with SRU tail gas upstream of the RGG, likely resulting in a noticeable buildup of solid sulfur over a few days. If operators periodically stop recycling to melt the sulfur to alleviate pressure drop, entrained droplets combined with soot simultaneously generated due to high turndown could conceivably coalesce as a viscous coating on the tube wall and gravitate to the bottom. Since the heated tail gas is unsaturated, the liquid sulfur may tend to weather off, leaving a porous, highly carbonaceous matrix containing interstitial H2O and SO2. I presume tube skin temperatures are too high for even capillary condensation at operating temperature, but sulfurous acid would promptly condense when the unit is idle. 5) 3-7-12 I do not know the corrosion mechanism. However, I have also seen corrosion on the bottom row(s) of tubes in the cooler. One plant was able to find a design to change from carbon steel to an alloy to avoid the corrosion. I don't remember how they did it but I do remember that there were major concerns about using alloy in fixed-tubesheet exchangers. It was not easy but they did find a solution. 6) 3-7-12 We haven't seen problems in this area. 7) 3-7-12 All our SCOT boilers generate 50 psig steam and are downstream of the Reactor; no corrosion issues. Have only seen one third party application such as yours, and do not have significant experience to comment on the corrosion you are observing.

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8) 3-8-12 All of our TGU boilers also generate 50 psig steam, and we have not seen any corrosion issues, even at high turndown. 9) 3-11-12 Before a recent comment, I did not realize the WHB is before the Reactor, which I have not seen before. That changes the chemistry – the porous carbonaceous deposits now contain interstitial H2O and SO2 which will promptly condense as sulfurous acid when the unit is down (as my previous response is revised). 10) 3-12-12 I also did not catch the "before" aspect. We did have significant trouble when incinerating an elemental-sulfur containing gas in front of an SO2 absorption style TGU. The WHB was destroyed by sulfuric acid – I watched as the chrome solution dripped from the exit pipe! DuPont cautioned us that SO3 formation was common in elemental sulfur burning. SWS SWS-031 Tray Efficiency & Packing HETP

• What are typical tray efficiencies and packing HETPs in sour water strippers?

My recollection from a former life (and very dated, unfortunately) are that there were considerable variations.

8-26-11

RESPONSES 1) 8-26-11 For new construction, we tend to use a 50% Murphree tray efficiency or 33% overall efficiency for sour water service. Model it both ways and use the most conservative. 2) 8-26-11 33% efficiency has been our standard value. 10 feet of packing is equivalent to about 3 trays. 3) 8-30-11 Our current strippers have 36 trays in the stripping section and were simulated using 12

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theoretical trays or 33% efficiency. 4) 8-31-11 It probably has more to do with which property package (EOS) you are using in this primarily water based system. I am still betting that about 4 feet of random packing will get you a single theoretical stage or just go with 33% on the efficiency for a tray. Structured packing may be a bit different. SWS-032 SWS Bottoms Fouling with Elemental Sulphur At one of our refineries we have an ongoing fouling issue in the SWS that we have not seen in our other stripper units. The deposit material is fouling the SWS bottoms stripped water side from the feed-bottoms heat exchanger, outlet piping and pump. Operations are having difficulty controlling the SWS level due to fouling in the control valve. See attached analytical reports for a recent sample. The deposits are mainly elemental sulfur accounting for 95+wt% of elemental sulphur in a 2007 sample, but more recent 2012 samples contained 70% S and 30% carbon and this material can not be melted so steaming out the SWS is no longer an option for removal. Frequency of the fouling is every 1-2 years and seems to happen fairly quickly when it occurs. Questions:

1. Any experience or knowledge related to carsul formation in the bottom of SWS? 2. What causes element sulfur contamination in sour water? One theory is oxygen ingress

into the sour water system resulting in direct oxidation of H2S to sulfur which becomes insoluble in the SSW.

3. What about sulfiding agent use in hydrotreating catalysts, could they play a role in sulphur contamination in sour water?

7/11/2012

RESPONSES 1. 7/16/2012: NOTE: the sour water tank has a floating roof vented to atmosphere with a

diesel blanket layer.

2. 7/16/2012: Re quench water SO2 as an oxidant source, there is no SCOT unit at this

refinery.

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3. 7/16/2012: Sorry, don't have any of these to worry about (lucky me).

4. 7/12/2012: We have seen similar fouling in the sour water loop of flare gas recovery systems. Most of our FGR systems use liquid ring compressors and generate a small sour water purge stream. There are strainers on the circulating water going back to the LRCs and we have experienced rapid strainer fouling with sulfur/FeS. We have correlated degree of fouling with oxygen in the feed gas. Vacuum unit off-gas, a notorious culprit for O2 ingress, is commonly the root of the problem. We are managing the issue by using dual strainers with spare SS baskets for quick changeout. Strainers are sometimes swapped 3-4 times daily. In your case, the SWS may be seeing a water stream that has dissolved O2 that when mixed with H2S in solution eventually yields sulfur particles and all of its associated challenges.

5. 7/12/2012: At risk of stating the obvious, O2 in some form is the culprit. As I see it, elemental sulfur in the sour water exists as a combination of colloidal sulfur and polysulfides. Once temperatures exceed 120 C in the lower stripper, colloidal particles coalesce into microscopic globules of liquid sulfur upon which organics tend to glom, subsequently depositing as an organosulfur matrix at < 120 C. Also, my understanding is that elemental sulfur can be an oxidizer in aqueous systems, and my experience suggests that polysulfides thus also tend to promote tray fouling with polymerized organics. (See SWS-002.)

6. 7/16/2012: I asked my partner to wade in on this since we recently encountered a similar situation in Oman. His comments --

1. Any experience or knowledge related to carsul formation in the bottom of SWS?

Looks like they are getting some heavy hydrocarbon in the sour water system.

1. What causes element sulfur contamination in sour water? One theory is oxygen ingress into the sour water system resulting in direct oxidation of H2S to sulfur which becomes insoluble in the SSW.

Could be O2. They did not mention SCOT Unit quench tower as source of SO2.

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2. What about sulfiding agent use in hydrotreating catalysts, could they play a role in sulphur contamination in sour water?

My understanding is sulfiding agents breakdown to H2S so I would not expect that as a source of elemental sulfur in SWS.

7. 7/11/2012: I don't recall ever seeing elemental sulphur in the SWS as you described.

However, we did have a lot of deposits which we attributed to the coke fines. We used to have to shutdown and chemical clean every 6-months. We are now back to a more typical 2-years.

8. 7/11/2012: Nothing new to add. Agree that O2 somehow is the culprit

9. 7/11/2012: Are sour water storage tanks floating roof, inert gas blanket or vented to

atmosphere with diesel/kerosene layer?

10. 7/11/2012: We have seen repeated SWS fouling more typically from hard water deposits.

We did have a SWS totally plug up when polysulfide injection was left running when the column was shut down. Since the Claus reaction can occur "everywhere," would seem to me, at least, that O2 intrusion could be reacting with the abundant H2S to form SO2, that then further reacts to sulfur. Will leave the more precise interpretation of the data you have presented to Messrs Keller and Hatcher, et al.

GEN GEN-035 Decommissioning Odorant Tank • What procedures are being used to decommission odorant tanks?

I notice that there is an outfit (MRR) that will seal up the tank haul it away and use a furnace to thermally destroy any remaining odorant. • Are there methods to chemically clean onsite, and reuse the tank for another purpose. • For example, has anyone tried Merox (caustic plus catalyst) to convert all the

remaining mercaptan to disulfide oil?

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12-9-11

RESPONSES 1) 12-9-11 I thought the practice was to flush with diesel. 2) 12-12-11 I believe the best way to eliminate the stink is by filling it with Chlorox and then dumping that to waste. Not too sure if you want to re-use the vessel again in terms of introducing all that chlorine into the vessel but this is how they clean up odorant spills in the gas patch. 3) 12-12-11 If you do an internet search of mercaptan neutralization and/or mercaptan deoderant, there are several companies that claim ability to chemically react mercaptans to clean vessels. I have never used any of them, but the field of chemical treatment continues to offer new or improved solutions and this may be a case in point. 4) 12-12-11 Peroxide or KMnO4 may be useful here. Chemical cleaners should be able to recommend one. I have no direct experience to share. 5) 12-14-11 Our cleaning expert recommends inhibited acid wash, followed perhaps by some neutralizing wash such as dilute caustic or baking soda solution. 6) 12-14-11 No experience with decommissioning, but some time ago we discussed the metallurgy needed in systems with mercaptans. Attached GEN-035A is an excellent reference for material selection, with a hint at cleaning if mercaptans are present. 7) 12-15-11 Have fun considering the product noted for use in neutralizing mercaptans in humans and produced from an organic base! If you have some time, look at other pages of their web site. Not only reported to be non-toxic, actually recommended for human consumption. I thought I would share this for the entertainment value: http://www.champex.co.uk/tech1.asp I also ran across another article that discussed attacking mouth odors (including mercaptans) with toothpaste. The article noted that toothpaste with ClO2, an oxidizer, addresses this situation. So, maybe cleaning the vessel with toothbrushes would not be a punishment, but a potential approach? Or, just a ClO2 solution – but mild since it would be exothermic. Of course, I'm not sure how the mercaptan additive carrier solvent that remains in the vessel would respond to or inhibit the effectiveness of these approaches. No matter what approach you use, review the mercaptan MSDS and be sure to account for the fire hazard they mention when the mercaptan additive is exposed to oxidizing agents. 8) 12-19-11 If the tank is located in a refinery, I'd flush the contents with kerosene/diesel and then send the mixture to a hydrotreater. Once this is done a caustic/bleach flush of the tank will remove residual RSH. I "know" of an incident many years ago where the operating persons "thought" an abandoned odorant tank had been cleaned with a HC flush, but after dumping the few gallons of residual liquid into a "remote" sewer found that it was RSH. The incident cost the company a few million $$ to settle the law suits from odor complaints since the stench drifted into a neighborhood and school about ½ mile away. [ ABPG Presentation – LHS – Brimstone Sulfur Symposium at Vail 2012.doc ] LHS/08-20-12