Summer 2022 Legal Internship – Energy and Environmental
Currently this is a hybrid remote/in-person position.
American Fuel & Petrochemical Manufacturers (AFPM) is a dynamic trade association representing high-tech American manufacturers of virtually the entire U.S. supply of gasoline, diesel, jet fuel, other fuels and home heating oil, as well as the petrochemicals used as building blocks for thousands of vital products in daily life, from paints to plastics, space suits to solar panels, and medicines to mobile phones. AFPM’s legal department participates in litigation affecting the refining and petrochemical industries; enhances AFPM’s advocacy initiatives by providing analytical support to the legislative, regulatory, communications, and outreach departments; provides legal support to AFPM’s business enterprises through the contracting process; and ensures the organization’s compliance with antitrust, copyright, and other applicable laws and regulations.
AFPM is looking for a currently enrolled second or third year law school student with an expressed interest in and/or experience in energy and environmental law. AFPM will work with the applicant’s law school to provide the applicant with class credit for their work, or the applicant can earn an hourly wage for a maximum of 30 hours per week. The legal intern works alongside AFPM’s General Counsel and focuses on a variety of legal and regulatory issues important to the refining and petrochemical manufacturing industries.
Responsibilities
- Conducts research and drafts litigation, regulatory, or administrative materials.
- Monitors developments in ongoing government and litigation proceedings.
- Presents on monthly Legal Committee calls.
- Works with AFPM’s outside counsel to monitor and assist with ongoing litigation.
- Other projects as assigned.
Qualifications
- Currently enrolled in law school; 2L or 3L students only.
- An expressed interest in, knowledge of and/or experience in energy and environmental law.
- Excellent writing, editing, communication and teamwork skills.
- Computer proficiency, including MS Office.
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Specialist, Issue Communications
This position is currently a hybrid remote/in-office position.
American Fuel & Petrochemical Manufacturers (AFPM) is a dynamic trade association representing high-tech American manufacturers of virtually the entire U.S. supply of gasoline, diesel, jet fuel, other fuels and home heating oil, as well as the petrochemicals used as building blocks for thousands of vital products in daily life, from paints to plastics, space suits to solar panels, and medicines to mobile phones. As a national trade association representing American refineries and petrochemical companies, AFPM engages in federal, state and local issues on behalf of our members. As part of this work, AFPM carries out a number of communications and education campaigns around specific issues and policy matters throughout the United States. AFPM follows a newsroom model for content development, in which members of the Communications team collectively review content performance, contribute news updates and identify opportunities for media engagement and owned content creation.
AFPM seeks a detail-oriented utility player to serve as Issue Communications Specialist within its growing Communications team. The Specialist will provide comprehensive communications, committee and coalition support under the umbrella of AFPM Issue Communications. This position will support AFPM engagement in various coalitions and industry groups, will develop master planning calendars for the Communications team, and will be an active contributor by monitoring key news and policy developments, submitting ideas for creative and written content around AFPM’s core issues and policies, and project-managing select deliverables.
Responsibilities
AFPM Newsroom support, content development
- Own development and ongoing revisions to a master calendar identifying key moments in time for Newsroom content planning
- Regularly track key news and conversations from thought-leaders, policymakers and media
- Support the development of issue-specific content, including blogs, statements, issue resource pages, backgrounders, etc.; create and adhere to workback timelines on each.
- Monitor key news and digital conversations to inform newsroom discussions and content
- Contribute ideas for creative and written content to be published on AFPM owned channels or pitched to media
- Assist in media relations activities, including list building, pitching, distributing press releases and materials, and tracking coverage
- Refine and update AFPM’s media packet
Committee and Coalition support
- Manage the scheduling, agenda-setting, and content development timelines for monthly AFPM communications committee meetings
- Maintain committee contact lists and develop a cadence for regular outreach and resource-sharing among members
- Participate in/manage follow-up duties stemming from various AFPM coalition meetings, ensuring content is shared, contributions are made, etc.
Project management
- Interface with external consultants and subject matter experts to complete specific creative tasks and content projects, on time and within budget
- Conduct other communications and administrative tasks as appropriate and as directed by the Director of Issue Communications and Senior Vice President of Communications
Qualifications
- A high degree of problem-solving and organizational skills, and an ability to develop and implement communications strategies and tactics.
- 3+ years of relevant work experience; demonstrated interest in the energy and manufacturing industries is a plus.
- Conscientious with details, highly motivated, and able to metabolize feedback and implement edits across deliverables.
- An eye for clean, consistent formatting and presentation documents (particularly PPT), consistent with brand guidelines, as well as the ability to articulate design needs to professional graphics and print teams
- Experience with HTML, CSS and creative suites is a plus
- Strong verbal and written communication skills
- Familiarity with AP Style preferred
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Senior Specialist, Issue and Advocacy Communications
This position is currently a hybrid remote/in-office position.
American Fuel & Petrochemical Manufacturers (AFPM) is a dynamic trade association representing high-tech American manufacturers of virtually the entire U.S. supply of gasoline, diesel, jet fuel, other fuels and home heating oil, as well as the petrochemicals used as building blocks for thousands of vital products in daily life, from paints to plastics, space suits to solar panels, and medicines to mobile phones. As a national trade association representing American refineries and petrochemical companies, AFPM engages in federal, state and local issues on behalf of our members. As part of this work, AFPM carries out a number of communications and education campaigns around specific issue and policy matters throughout the United States.
AFPM seeks an experienced public affairs, campaign or advocacy communications professional to join its growing Communications team as Senior Specialist, Issue and Advocacy Communications. The Senior Specialist will develop communications and mobilization plans and related content to support AFPM engagement on key issues at the federal, state and local levels; oversee and partner with consultants on communications, grassroots/grass-tops and digital issue campaigns at the federal, state and local levels; and, execute the mobilization strategy for AFPM’s industry-wide engagement program, EMPOWER. The Senior Specialist will also be an active contributor, or “beat reporter,” in the AFPM newsroom, updating the team on policy developments, identifying priority issue content gaps and assembling smaller action teams within the newsroom to develop engaging content across AFPM-owned channels.
Responsibilities
Issue campaign communications:
- Work with AFPM state & local outreach and federal engagement teams to monitor developing issue campaigns and identify communications needs to support teams on the ground
- Develop communications plans and educational materials around key issues, including letters, template op-eds, draft testimony, fact sheets, FAQ documents, etc.
- Manage field teams, consultants and grassroots, grass-tops programs
Program mobilization
- Drive the EMPOWER program’s advocacy communications
- Manage advocacy reports, including company-specific engagement metrics
- Build out the issue education section of EMPOWER’s in-person training
- Expand EMPOWER facility mobilization resources to include a guide for hosting VIP site visits, inclusive of event planning templates, invitations and sample agendas
AFPM Newsroom
- Within the AFPM Newsroom, own issue-specific content, including blogs, statements, one-pagers, issue resource pages, backgrounders, etc. for relevant beats
- Develop plans around key policy timelines and manage relevant communications
Qualifications
- At least four years of relevant work experience; energy industry experience a plus.
- Campaign and/or advocacy experience, including mastery of digital and traditional engagement tactics.
- Accessible, clear writing and speaking skills, appropriate for grassroots audiences.
- Excellent judgment.
- A high degree of problem-solving and organizational skills, and an ability to develop and implement communications strategies and tactics.
Apply Now
Question 1: Historically, instrument air was used to purge FCC reactor instruments. More recently, dry gas or nitrogen is typically used for this service. Please explain the reasons for moving away from air and provide examples of operating upsets that have occurred when using air to purge instruments.
ASDOURIAN (Sunoco Inc.)
Gas purge streams for instrumentation in FCCU reactor-regenerator service are required to ensure their functionality. For example, the reliability of level- and pressure-measuring devices relies on clear impulse lines. The utilization of a continuous-purge gas stream ensures that catalyst particles are prevented from entering or are swept from impulse lines to keep them clear and reliable. Typically, Sunoco FCCUs do not use an air purge stream for instruments in reactor service. We utilize fuel gas or nitrogen for purge in this service. Nitrogen is preferred since it is a dry stream and contains no sulfur. It is also preferred as a continuous emission monitoring and instrument purge for these aforementioned reasons.
Reactor-side instrument air purge has led to elevated phenol content in sour water. Phenol concentrations need to remain within river discharge or biological treatment process limits. We are not aware of any operating upsets of an acute nature when air is in use in reactor service. Instrumentation in regenerator service commonly utilizes air as a purge stream.
WALKER (UOP)
We used instrument air on early units with bubbling bed reactors. With the advent of all riser cracking and tee disengagers in the 1970s, localized coke accumulation became more common. We know of one North American FCC unit that suffered overheating of the reactor head caused by localized coke burn, which was oxidized by instrument air purges. On some units, a shotgun off the top of the tee was used to keep the top head of the reactor active and coke-free. And then as we went to more and more closed systems, dry gas or nitrogen was used as a purge.
WARDINSKY (ConocoPhillips)
We have not experienced any operational upsets due to instrument air purges in FCC reactor service. However, we have experienced problems with riser differential pressure taps using refinery gas purges in one FCC. This was due to heavy coke formation inside the pressure tap piping. An 18-inch coke ball was found on the outlet of one tap. The coking was believed to be partially due to hydrocarbon liquids present in the refinery gas. When switching to natural gas purges in FCC reactor service, proper start-up procedures need to be in place to use nitrogen or instrument air when the reactor is being heated up for a refractory cure and dry-out.
PHILLIP NICCUM (KBR)
Using instrument air to purge FCC reactor instruments has not been a historical practice at KBR. One of the concerns can be that during extremely low feed rates, such as maybe during a start-up or a feed outage, you can have a buildup of oxygen in the top of the fractionator or the overhead drum, which can exceed the explosive limit. All these issues can be avoided by using an oxygen-free medium.
Question 2: Which type of valve technology or design is typically utilized in units with high catalyst withdrawal rates? Do you continuously withdraw catalyst? From a reliability and safety perspective, what type of hardware are you using for control? What is the best withdrawal line design?
THOMPSON (Chevron)
Valve selection for FCC catalyst withdrawal services is dictated by temperature and erosion considerations. FCC catalyst is very erosive and when withdrawn from the regenerator is typically in the 1200°F range. These considerations, coupled with high velocities when purge or carrier air is added, lead to very severe conditions with lots of erosion. We have developed a Best Practice for catalyst handling systems and the information that I will be presenting generally follows those guidelines. We have experience with four types of valves in catalyst withdrawal service. They are a conventional gate valve with or without hard facing; the Tapco Mini Slide; the Everlasting rotating disc valve; and high performance ball valves. Generally, the gate valves have been poor performers, even with hard facing, giving one to three years’ life. Both the Tapco Mini Slide and the Everlasting rotating disc valve have given good performance, typically lasting multiple runs. We have limited experience with the high performance ball valves. Continuous catalyst withdrawal from the regenerator has been suggested as a way to even out the swings in level and catalyst activity that occur when catalyst is withdrawn. We have no experience with that sort of a system, but we have several units that have been interested in perhaps trying it. For units that have power recovery turbines, we do use a form of continuous catalyst withdraw off the third-stage hoppers, which has its own specialized design. For intermittent and semi-batch operation, the valve types described earlier are used for throttling. Block valves are most commonly low chrome gate valves with hard-faced seats. Temperature monitoring of the withdrawal lines is recommended because if the withdrawal rate is very high, then the line may exceed the design temperature. We have a few units that have added fins as a way of cooling the catalyst when it is withdrawn. Carrier air is a big help in cooling the catalyst. Catalyst withdrawal lines are subject to leaks at the erosion points. We have looked at using boronizing and other similar sorts of coatings as a way to mitigate the erosion, but these have not been widely applied. The erosion generally occurs at turns; and so for those, we have used cushioned tees. That is the preferred method for preventing the erosion. Also, we found that air purging of the blocked valves can create localized erosion, particularly if the air is left on when the valve is sitting in a closed position. We had an experience a year or two ago where we actually eroded through the side of a valve body under those circumstances. So the recommendation is to use the air purge strictly when the valve is being moved, either opened or closed, and to leave the air purge off otherwise.
ASDOURIAN (Sunoco Inc.)
Sunoco FCCUs typically use manual gate valves with either stainless steel or chrome bodies on catalyst withdrawal lines. We have air purges on the seat and the stem. Recently, we began installing Nitronic 50 coatings on the stem for added protection against erosion. Along with the gate valves, one of our units uses plug valves; and yet another has a ball valve installed downstream of the gate valve. Several other valve designs have been used to try to improve or speed shutoff and extend valve life. High performance ball valves were installed on one unit for two runs. These valves were much more expensive than gate valves, but the thought was that a quarter-turn design with upgraded seat and design material would give better and quicker shutoff. However, we did not realize a drastic improvement. One unit has tried knife gates, since this type of valve is used extensively on ESPs to the dump catalyst. However, on the hotter surface of the regenerator, the knife gate design did not perform well and experienced many mechanical issues. It has been removed from service. One unit also used the ball valve in one installation; and again, there was no noted improvement in shutoff or service life. One unit uses quarter-turn plug valves; and again, they have seen no major service improvements or drawbacks associated with the plug versus the knife gate. Thus, there have been several attempts to use higher performance valves, but none has worked any better than gate valves. We continue to examine valve options for improved reliability in this service. Regarding continuous withdrawal and control, all of our installations are on units that dump catalysts intermittently. All catalyst dumps are manually controlled based on instrument readings either at the bed level or the online temperature readings, depending on the limitation. The challenge on all these installations is the same: achieving tight shutoff after a dump of very hot and erosive material. The catalyst withdrawal valves are typically reworked and often replaced at each turnaround. Sunoco FCCU catalyst download lines are primarily carbon steel. Some installations use double plates in areas where we expect high erosion, such as elbows. Carbon steel lines have been used with varying degrees of success. Some units have had no issues over extremely long service lives, and others have experienced minor holes that can be managed with patches during a run. On major projects, some alloy has been installed on catalyst unloading lines. Current industry standards regarding design temperatures would dictate using alloy material when replacing unload lines. The use of alloy creates installation and future maintenance challenges. Industry material standards and negative experiences at some facilities would most likely drive Sunoco towards using alloy materials for future catalyst unloading line replacements, even with the challenges of installing and repairing these type of lines.
WALKER (UOP)
UOP recommends continuous catalyst withdrawal for high catalyst users, maybe five or more tons per day. Continuous catalyst withdrawal, in combination with continuous makeup, allows you to minimize the catalyst level and inventory. This results in better activity maintenance and lower particulate emissions, as well as reducing manpower requirements. We recommend Everlasting rotating disc valves to control the flow of the catalyst. Cooling fins are used on the withdrawal line to cool the catalyst before entering the hopper. The alloy metallurgy is used to accommodate the high temperatures associated with the catalyst withdrawal. Carrying air is used to cool the catalyst and maintain the line below allowable temperature limits. Flow controllers are used to adjust the carrying air and skin TIs are used to monitor the temperature. Everything is controlled by the DCS and runs with very little operator intervention. The system is essentially a regenerator-level controller with a very slow reset. The withdrawal valves are normally closed, then opened periodically for a short time, and then closed again. We do keep a gate valve adjacent the regenerator for isolation.
WARDINSKY (ConocoPhillips)
We typically rely on a series of two to three gate valves to withdraw catalysts from the regenerator. Some of these valves have actuators on them. The valve internals are metallurgically enhanced to reduce erosion; and for high temperature service, we plan on replacing the valves at each turnaround. With the exception of third-stage separator underflow, we do not continuously withdraw catalysts from our regenerators.
HAZLE (NPRA)
I want to remind you that your Answer Book includes some of the panelists’ responses as well as responses from other people that submitted them before the conference. I encourage you to open that and follow along and keep track.
KEVIN PROOPS (Solomon Associates)
Aram, when you were talking about valves, you mentioned that you have or have considered stainless steel. You also mentioned that you are considering alloying the line. I believe, Pat, you used the word alloy. I believe we have brought up, in the past at these sessions, concern about polythionic stress corrosion cracking in this service, and I would like to confirm or clarify whether we are talking about the 300 series stainless or something else. My experience would be that if you are having problems with erosion on the line and you are considering alloy, then I think, economically, you might do better to have a larger pipe or go with the cushioned tee-type installation and not go to alloy because I have experience with these lines lasting a very long time in carbon steel service or low chrome. I would like to hear comments on metallurgy from both Aram and Pat.
ASDOURIAN (Sunoco Inc.)
You bring up a very good question. We do have folks that we pay to take care of this type of alloying questions. Unfortunately, I am not one of them, but I can query those personnel and put my response in the Answer Book.
WALKER (UOP)
I agree with the polythionic stress corrosion cracking comment. When I refer to alloy, I mean 5-chrome or similar.
THOMPSON (Chevron)
I would agree with that. We typically have 5-chrome. We have a few places that have selectively used just 1¼-chrome, but usually it is 5-chrome. We stay away from 300 series stainless for the reason you mentioned: that PSCC is a known risk and there is really no need for it at that location.
PHILLIP NICCUM (KBR)
I would like to just agree and reinforce that in catalyst withdrawal service, we would definitely recommend staying away from a stainless steel, such as 304-type stainless steel. We have seen instances where it had been used and the lines would break due to polythionic acid cracking.
MASHUD MARTLE (KBR)
In the past, we have used stainless steel 321-X for catalyst withdrawal lines and kept avoiding the polythionic corrosion. We kept nitrogen purge so that keeps a continuous flow into the regenerator to the flue gas, which does not condense, and it keeps the nitrogen as a blanketing. We used 321 stainless steel and it worked very well in a few instances.
ZIAD JAWAD (Shaw Stone & Webster)
Mike, you mentioned the flue gas fines collection systems. In those systems with the fourth-stage underflow, do you utilize gravity drain down into the fine topper? Has anyone seen corrosion in the fine topper if it is pressured up in that service?
WARDINSKY (ConocoPhillips)
I am not aware of any corrosion problems in those lines. I have not heard any reports of that. We do have, I believe, some fourth-stage separators with gravity drainage to a hopper where the catalyst is then cooled and offloaded later.
WALKER (UOP)
I have heard of corrosion in that area. The catalyst accumulates down there. It can insulate and you can trap corrosive materials. We insulate and heat-trace that area.
ZIAD JAWAD (Shaw Stone & Webster)
In those services, do you have metering block valves or different types of block valves? Do you have corrosion in those lines as they meter the catalyst down to the fine hopper?
WALKER (UOP)
Those hoppers are usually on a timer and they are periodically unloaded to maintain the level. I am not sure if that answers your question.
WARDINSKY (ConocoPhillips)
Yes. The hoppers are typically unloaded at least once a shift in that service. I am not aware of any corrosion issues associated with the valves.
REZA SADEGHBEIGI (RMS Engineering)
Besides temperature that Ralph mentioned, one of the key criteria in designing those valves is the pressure drop. You know, the regenerator pressure can run anywhere from 15 pounds to as high as 50 pounds. So when you look at designing that valve, you are taking a lot of pressure drop if you are running a 40-pound regenerator and you want to go down to zero, basically, or one- or two-pound. So that is the one you have to look at. It is similar to designing a slide valve. You may need to have a two- or even a three-valve system to allow you to take reasonable pressure drop across the valve. Otherwise, it is not going to last very long, especially if you have to withdraw very often. The other thing that I have seen happen is that erosion in the piping that you were talking about downstream: Most cat crackers do not pay attention to how much purge air rate they have going through there. They just open the valve. They have no idea whether it is too much or too little. I would recommend putting some sort of a restriction orifice or a flow meter and target about 30 fps velocity. That will ensure that your catalyst is moving and that you do not have erosion, especially around the elbows. Thanks.
DOC KIRCHGESSNER (W.R. Grace Refining Technologies)
Pat, I would like to ask you, in particular, a question. You commented about the simple regenerator-level control scheme. Would you care to comment how prevalent this is in actual practice? About how many people do you know who are actually, continuously, adding and withdrawing catalysts from the FCC regenerator?
WALKER (UOP)
I am not sure how many continuous withdraw systems we have operating. I am intimately familiar with one that is working very well in the Middle East, and I believe we have a handful of other ones that are also working without any problems; again, using the Everlasting valves. Prior to that and since the beginning of cat cracking, it was done periodically maybe once a day or once every three days, depending on the unit, and that still works fine. It is still the most common industry practice.
WARDINSKY (ConocoPhillips)
I am a little skeptical of the continuous withdraw system because within our system, we see a lot of units struggle to maintain a continuous addition to minimize swings in the unit operations. One of the first things we do when we go out is to try to get people to look at loading systems that are reliable and that maintain a continuous addition to the regenerator. We still seem to experience a lot of problems with loading systems and reliability of those systems.
WALKER (UOP)
I have just one more comment on what Mike said about addition systems. It seems that the most reliable, repeatable systems are those based on day hoppers on weigh scales.
Question 3: Carbonate stress corrosion cracking (CSCC) has been identified as a cause of failure in FCC main fractionator overhead systems. What changes in feed quality, unit operation, or configuration would lead to increased risk of CSCC? What parameters do you monitor to determine whether a system is susceptible to CSCC? Has the problem been significant enough to warrant either comprehensive PWHT in potentially affected areas or localized PWHT when problem areas are identified?
THOMPSON (Chevron)
Carbonate stress corrosion cracking, CSCC, is characterized by inter-granular, sometimes branchy, scale-filled cracks. It is believed that ammonium carbonate is the main contributor to the cracking mechanism. Scale is typically black magnetite, and the corrosion, as far as the corrosion product, and sometimes iron carbonate, which is unlike the sulfide stress corrosion cracking that occurs with iron sulfide.
Chevron finds that the work by Kmetz and Truax published in 1989 still holds true. The conditions under which CSCC are a threat include susceptible material, which would be carbon steel that is either not post-weld heat-treated or poorly post-weld heat-treated; pH levels above 9.0 and carbonate concentrations above 100 ppm; or pH levels between 8.0 and 9.0 and carbonate concentrations above 400 ppm; and finally, electrochemical potentials between -500 and -600.
Stainless steels are basically immune to carbonate stress corrosion cracking and some facilities have used that as a way to solve the CSCC problem. We basically monitor the parameters of pH and carbonate levels to determine if we are in the range where CSCC is a problem, especially if we have non-post-weld heat-treated equipment. It is easier to monitor pH than anything else. And if we have a good sense of the carbonate ranges, pH may be the only parameter that we monitor.
Higher nitrogen levels will lead to higher ammonia. And of course, this result will increase the pH, which could lead to CSCC. Similarly, anything that promotes CO2 will increase the amount of CO2 that is available. We found in the 80s, when we went to complete combustion on many units, that series of events really tipped us into the range where CSCC was a problem.
We know that there are a number of companies that look at the sulfur/nitrogen ratio and we find that this ratio can be useful. Nevertheless, we use pH measurement and carbonate measurements as the defining parameters for monitoring.
Regarding the use of post-weld heat-treat as a mitigation against carbonated stress corrosion cracking, we are convinced that it is very effective if the heat-treatment is done properly and there are no unusually applied external stresses. We found that we needed to go to a more severe post-weld heat-treat than is typical—for example, what the code would require— and we have to have better temperature measurement, wider bands, and things like that.
Our standard practice is to call for post-weld heat-treat for all new systems that are subject to CSCC and also on systems where we might be changing conditions where that could be a factor. Since implementing these procedures, we have not had an incident in over 10 years now.
WALKER (UOP)
The question mentions that CSCC was found in the main fractionator overhead system, but I would like to point out that carbonate stress corrosion cracking has also been reported in the gas concentration unit although only in locations where there can be an aqueous phase. So you would not expect to see this in, say, the debutanizer, but you might see it in something like a high-pressure condenser.
The problem is most pronounced in hydrotreated feed derived from high nitrogen crudes, such as Californian or Nigerian. Hydrotreating is very effective at reducing sulfur but less effective at reducing nitrogen. So if you start with a high nitrogen gas oil and severely hydrotreat, you can wind up with an FCC feed that has a very high nitrogen-to-sulfur ratio and subsequent high pH.
Most of the equipment in the main column and gas con is already heat-treated because it operates in wet H2S service. Consequently, the carbonate stress corrosion cracking is generally limited to the piping, which is normally not heat-treated, even in wet H2S service. I would like to also point out that this problem is fairly uncommon. Since first reported, we have only had one of our grassroots units deemed at risk for this, which justified unilateral post-weld heat treatment.
ASDOURIAN (Sunoco Inc.)
Sunoco FCCUs typically do not process hydrotreated feed; therefore, the naturally occurring sulfur-to-nitrogen ratio, which has been linked to this phenomenon, is not being altered. We have not observed CSCC at any of our FCCUs. Our FCCU overhead systems have had enhanced inspection programs in place for corrosion and cracking for quite some time.
These inspection methodologies include wet fluorescent magnetic particle inspection for environmental cracking. Our associated sour water strippers are post-weld heat-treated to mitigate potential metallurgical impact of carbonates since this can manifest itself in those systems. The primary control that is used is post-weld heat-treatment of the welds. The post-weld heat-treatment, we have found, has also improved the resistance of welds to wet H2S and cyanides attack, which is common in these types of systems.
WARDINSKY (ConocoPhillips)
ConocoPhillips has experienced carbonate stress corrosion cracking in one FCC main fractionator overhead and wet gas compressor system in which intergranular and base metal cracks were discovered in 78 welds. This unit runs 100% hydrotreated feed with a high nitrogen content. Eighteen full-separation clamps were installed until the affected piping could be replaced at the next turnaround.
SHELLY ROMMELMANN (Washington Group International)
Aside from clamping, if you have a couple of years until the turnaround and you are operating in a carbonate stress corrosion cracking range, what can you do operationally to alter the pH without using mass quantities of water for dilution or harsh chemical addition?
WARDINSKY (ConocoPhillips)
I think the unit in question that experiences this within our system probably looked at various chemical additives, such as ammonium polysulfide (APS) and filmers that would protect the surface of the metal. Obviously, they implemented more elaborate lab testing and started looking at pH and monitoring carbonate levels in the sour water.
THOMPSON (Chevron)
I would say that without implementing some proactive responses, such as selective heat treating and things like that, it is going to be difficult to address CSCC without some sort of a turnaround. Usually, you are in a position where oftentimes you cannot change the chemistry enough to be able to get yourself out of the range. That is very unit-specific; however as Mike mentioned, there may be the opportunity to, for example, switch from APS to a filmer as a way to control corrosion if you are just marginal.
For example, one of the things we found a little bit disturbing is that we even had cracking at places where pipes were supported in pipeways. This was completely outside of weld zones. So sometimes this occurs in locations where you would not even expect it, making it very difficult to do enough monitoring and really pick up all the locations where you might be at risk.
SAM LORDO (Nalco Energy Services)
I do not have anything to add to the panel’s response, but there is a NACE Task Group that is looking at this issue. It is TG347 and they will be issuing a report. They have actually done a survey of the industry. As you have heard, there are a lot of things that go into this carbonate cracking that are not well understood and rules of thumb do not always apply across the board. So what they have done is they have surveyed the industry and tried to capture all the incidences out there that have occurred and what are the parameters around them. Also, I would like to note that in several locations, we have been successful when applying a filmer in places where carbonate cracking has been known to occur.
REZA SADEGHBEIGI (RMS Engineering)
You can reduce the amount of the ammonia produced in overhead by cutting back the riser temperature or basically slowing down the severity of the cracking. That can be done by reducing riser outlet temperature and maybe by putting in more active catalyst. That way, you slow down the cat circulation, yet do not lose that much on conversion. Also, that person who asked that question needs to look at the air distributor, as well as the catalyst withdrawal system regen catalyst. If you are dragging all of the CO2 down with the flue glass into the reactor, then you must have a mild distribution problem. Normally, you have the flue gas coming down and there is a ratio of the nitrogen to CO2. If that CO2 is higher than it is supposed to be, then you can look it up at the sponge absorber off gas. Normally, a sponge absorber off gas has somewhere between 1% and 2.5% CO2 in it. If you see that number has gone up, then you have to look at your regenerator to see how air and a regenerator catalyst withdraw nozzle are working out. So by reducing cat circulation rate and reducing riser temperature, you reduce the ammonia. And at the same time, you reduce the amount of entrained CO2 that goes down into the reactor.
WARDINSKY (ConocoPhillips)
I want to mention that I believe the corrosion community is divided on whether APS has any mitigating effect on the carbonate stress corrosion cracking. About half of them believe it works and the other half do not. That is maybe one of those things that will come out of the NACE Task Force.
I was thinking more about this question. I believe that the unit where we experienced it did try to raise their water wash rates to try to reduce the pH. This is a unit that if you cut back riser outlet, you are going to make more slurry; and so, you are going to hit some constraints somewhere else. That is probably easier said than done. They basically just held on for two years until their next scheduled turnaround.