The Department of Labor and Industries cited a refinery for forty-five alleged violations of various Washington Administrative Code sections assessing a penalty of $2,393,000 as a result of an explosion and fire that occurred at the refinery on the early morning of April 2, 2010 that resulted in seven fatalities. The refiner contends that it did not violate any of the code sections and that the explosion and fire was caused by something unrelated to its failure to follow these rules. The Department has failed to show by a preponderance of the evidence that the refinery committed any of the alleged violations and the Corrective Notice of Redetermination is VACATED.

DISCUSSION

During the early morning of April 2, 2010 a tragic event occurred at the refinery. Employees were preparing to start-up a bank of exchangers in the naphtha hydrotreater (NHT) unit following a clean-up of the equipment. Soon after starting the process the shell of the E-6600E exchanger ruptured resulting in an explosion and fire. Seven employees died as a result of the explosion. Several government agencies investigated the incident, including the Department of Labor and Industries. It issued a Citation and Notice of Assessment on October 1, 2010 citing for allegedly violating forty-five sections of the Washington Administrative Code and assessing a penalty of $2,393,000. the refinery filed a timely notice of appeal and the Department reassumed jurisdiction. It issued a Corrective Notice of Redetermination that affirmed all the alleged penalties. the refinery filed a timely appeal with the Board.

The parties have vigorously litigated this appeal. Hours of testimony were taken and numerous depositions filed. I have issued three orders granting, in part, and denying, in part, summary judgment based on motions filed by the refinery. After the issuance of these orders in which I also grouped certain alleged violations, eleven remained with a resulting penalty of $490,500. When such a tragedy occurs in the workplace most people assume the employer must be at least partially to blame. The Department certainly placed the blame squarely on the refinery as shown by the number of alleged violations and the amount of the fine. But even a Department investigator, admitted that the fact an accident occurs does not necessarily mean that there is a violation of a process safety management standard, the bases for most of the alleged violations.

I have heard the testimony, reviewed the record and exhibits numerous times and I have not found that the Department, who has the burden of proof, has shown that the refinery is responsible based on the rules cited in the Citation. The Department only called one of the many employees who took part in the inspection and that was to admit certain documents so it is difficult to understand much of the Department's bases for the Citation. The Department cites to documents and "facts" in its closing brief that are not in the record or have not been admitted to the record. The Department did not even present any evidence to show the bases of the penalty. It tried to prove its case by calling numerous present and former employees of the refinery and one expert for the citation dealing with inspections procedures. Unfortunately for the Department the testimony of these witnesses was remarkably similar regardless of their present position with the company and regardless of their being in management or a line employee. There were a few who obviously blamed the incident on the refinery but they were unable to really articulate what the refinery did or didn't do to cause the explosion.

The refinery's witnesses, including Department employees as well as highly regarded experts from the petroleum industry, were far more effective at showing that regardless of any shortcomings that existed in the refinery's programs they did not violate any of the cited regulations and did not cause the explosion.

I must also point out that the majority of the alleged violations did not directly relate to the explosion and fire. Some were related to the aftermath when the refinery responded to the explosion, some with processes that had no effect on the equipment being defective and others, violations that apparently were found during the inspection.

The real crux of this appeal is that everyone admits to the cause of the explosion, high temperature hydrogen attack (HTHA). Before discussing HTHA I should discuss how the NHD operated. The Zone A operation supervisor at the time of the incident gave one of many descriptions of the process. The NDH was housed in Zone A at the refinery. The unit removes nitrogen and sulfur from a naphtha feed. Exhibit 202 illustrates the process. He stated that the unit, the reactor, treats the feed so it can be moved to the reformer.

Hydrogen gas is added to the liquid feed and moves to the reactor feed effluent exchangers. The feed stream enters the tube side of both banks of reactors at the bottom of the banks. After the feed enters the exchangers it exits as effluent from the shell side. They exchange heat as they go through the reactor, the feed being heated as it travels through the exchanger. It then exits at the bottom, the C exchanger, and goes to the inlet of the B exchanger and exits the B and enters the inlet to the A exchanger on the top. It does the same thing on the other set of exchangers and the two feed streams join at the outlet of both banks and then enter the NHT furnace where it is heated to achieve the desired reactor inlet temperature.

The reaction takes place and the effluent returns to the exchangers at the top of the inlet of the A and D exchangers on the shell sides. The heated effluent then goes through the exchanger from A to B to C and it begins to lose heat. From the heat exchangers it goes to the cooler. The Zone A operation supervisor stated the process depicted in Exhibit 202 is a continuous loop. Exhibit 203 is a closer view of the E-6600 exchangers that was further described by the Zone A operation supervisor.

The process is the same on the other side for the D, E and F exchangers. A materials engineer, testified as an expert witness for the refinery. He has a long history in the petroleum industry and has worked with numerous companies as well as the American Petroleum Institute as an expert on topics including HTHA and other damage mechanisms and inspections. He inspected the damaged exchangers and reviewed a number of documents. He discussed HTHA with the use of Exhibit 227. He testified that HTHA occurs in equipment that is operating at high temperatures and at a high hydrogen partial pressure.

A metallurgist who performed a corrosion review for the refinery while working for Capstone in 2008, stated that HTHA is a degradation mechanism that can take place in material commonly used in refineries. He also stated that it depends on the presence of hydrogen at high temperature and high pressure. The hydrogen is originally in the form of gas and it decomposes at the metal surface at high temperature and high pressure into atoms. Once it is in atom form it goes through the steel and if the steel is not resistant enough it can combine with carbon within the steel and form bubbles of fissures and cracks.

Both the metallurgist and engineer discussed API 941 which is a recommended practice for the petroleum industry issued by the American Petroleum Institute. It contains the Nelson Curve, Exhibit 229, which is used by the industry to determine if a particular steel is susceptible to HTHA.

The Nelson curve represents three variables, the material, carbon steel, hydrogen partial pressure and temperature. The curve also contains reported incidents of HTHA as well as where there were reported exposures where the mechanism did not occur. The engineer pointed out that you cannot plot conditions on the Nelson curve if the temperature and partial pressure are not taken at the same time. This is a key factor in this case since the Department alleges that there were times when the temperature was above that on the curve and when the partial pressure was above the curve but not when they crossed those limits at the same time.

After the incident at the refinery reports surfaced where HTHA occurred where the temperature and partial pressure were below the edition of the curve in existence at the time of the explosion. As a result the API performed a detailed evaluation of the curve and issued a new edition which updated API 941. Exhibit 230. The engineer was a contributing member to the API taskforce that issued this revised practice.

Exhibit 231 is the new Nelson curve that was prepared as a result of the API taskforce findings. Based on the new API findings the decision the refinery made, based on the findings of a corrosion review, to not inspect the B and E exchangers for HTHA would have been different since the temperature in the new curve is about 90 degrees lower.

The metallurgist testified that if the new curve was in existence in 2008 he would have recommended that the refinery inspect the B and E exchangers for HTHA. These established facts do not necessarily lead to my conclusion that these alleged violations should be vacated. The way in which they are written leaves the refinery even though they may not have been a direct cause of the explosion. I have reviewed each remaining alleged violation on its own to determine if any should be affirmed and I will review each in this order to explain my ultimate decision to vacate them in their entirety.

 

Violation No. 1 Items Nos. 18 (a) and (b)/ WAC 296-67-037(2)

In its citation the Department alleges that the refinery did not implement written procedure I-08.08 for E6600 B and E to maintain the integrity of the process equipment. The citations give Sections 7.1.1, 7.2, 7.3 and Attachment B, Sections 2.0, 5.0, 6.0, 7.0 and 9.0 as not being implemented.

WAC 296-67-037(2) requires that the employer establish and implement written procedures to maintain the ongoing integrity of process equipment. There is no dispute that the refinery had the written procedures the issue is whether they were implemented. This WAC is a performance safety management standard which allows the employer the flexibility to "kind of pick and choose the best way for them to comply with the standard".

The engineer also testified that it is up to the employer to pick and choose what they feel is the best inspection and test to perform. This does not give the refinery carte blanche relief from following Department rules because it has the written procedure but it certainly gives it the ability to design the procedure and if it follows it I find it hard to find that the Department can second guess them especially under the circumstances in this appeal. In fact, the Board has found that the Department cannot substitute its judgment for that of the employer involving the appropriate standards to set under process safety management as long as the standards otherwise are consistent with recognized and generally accepted good engineering practices.

I could cite this generally in all the following alleged violations since it seems the Department did this exact thing throughout its inspection.

Inspection Procedure I-08.08 has been admitted into evidence as Exhibit 14. It deals specifically with HTHA. It was made effective January 30, 2006 which is important because many of the temperature and pressure readings alleged by the Department occurred prior to this date and many of them occurred when Shell still owned the refinery. The basis for this procedure is API 510 which deals with inspections of pressure vessels. This code has been adopted by the State of Washington.

API 510 specifically sets out that the employer shall use a corrosion expert when determining potential damage mechanisms and when developing a plan for vessels that operate above 750 degrees and to identify inspections techniques.

The refinery hired outside consultants to perform corrosion reviews for the NHT in 1999, 2003 and 2008. They included the E6600 exchangers in the reviews. These reviews recommended inspecting the A and D exchangers for HTHA but not the B and E exchangers. the refinery followed these recommendations. the refinery's inspection procedure at Attachment A only recommended inspections for HTHA in those instances where it was found that the equipment was operating above the Nelson curve and required routine measurements of temperature and hydrogen partial pressure when the equipment operated within 25 degrees or 25 psia of the Nelson Curve. It also provided that if this occurred the equipment would be subject to periodic inspection in accordance with Attachment B of the procedure.

It is the Department's position that exchangers B and E did operate within 25 degrees of the Nelson Curve and the refinery should have continually inspected for HTHA. It presented the testimony of an expert witness who has a bachelor's degree in engineering and worked for 15 years in the petrochemical industry as an inspector through 1999 and has been doing riskbased inspections since that time, helping people implement them at their business. He explained that a risk based inspection is a technique that allows a company to look at the likelihood of a failure and the consequence of that failure to adjust inspection techniques. A company is looking to develop an inspection plan based upon risk.

As part of his work he has coordinated corrosion reviews and process reviews. As part of his assignment he reviewed the refinery' inspection procedure I-08.08. It is his opinion that the refinery did not implement the procedure for the E6600 B and E exchangers. His reason was that based on other documents he reviewed "it doesn't appear that there was any strenuous effort to come up with actual operating pressures, recorded operating pressures or any way of showing that the hydrogen partial pressures had been validated by actual data." He cited sections 7.1, 7.2 and 9 as areas where the refinery did not follow this policy.  He based his opinion on a number of documents including Exhibit 148 which has not been admitted and Exhibits 3 and 4 from a deposition. Exhibit 4 is a duplicate of Exhibit 148. He made certain calculations from these documents to assist him in reaching his opinion that the refinery knew that the B and E exchangers had temperatures high enough to reach within 25 degrees of the Nelson curve.

There are many problems with these calculations the major one being that no one really could testify as to what the numbers in Exhibit 48 meant not even the refinery employee that was called to testify. There are calculations at the bottom of Exhibit 4 of the deposition that had been added by someone after 1971 but no one knows who made those calculations. Furthermore, it appears that the document was created in 1971 when Shell first set up the equipment and the document was a Shell document. These deposition exhibits appear to have been created at a time when Shell was increasing the operating temperature of the inlet to the B and E exchangers to 750 degrees. The bottom line is that these are design temperatures and not necessarily operating temperatures. There is also testimony that the feed is cooled as it moves through the exchangers so this does not convince me that the refinery knew that the exchangers were operating at these high temperatures.

His testimony has a number of flaws that became apparent in cross-examination. He admitted that he would refer to a corrosion expert to understand the significance of the numbers on the Deposition Exhibit 4 and that he relies on corrosion experts to advise him what damage mechanisms apply to specific equipment. He also testified that Exhibit 4 to the deposition did not have any bearing on whether the refinery complied with a 2006 HTHA procedure. He never performed an evaluation to determine if the refinery operated the B, C or E exchangers above the Nelson curve after the procedure was in effect. Nor did he ever try to evaluate whether the B or E exchangers were ever operated by the refinery within 25 degrees Fahrenheit or 25 psia of the carbon steel Nelson curve after January 30, 2006.24 He also testified that if the refinery determined that the B and E exchangers were not operating within 25 degrees of the Nelson curve none of the provisions he offered opinions on would apply to the B and E exchangers.

The Engineer testified that after the incident certain tests were done on the exchangers to determine the rate of corrosion. Based on these tests and measurements he concluded that the average temperature of the E exchanger would have been no higher than 450 degrees Fahrenheit.

Another problem the Department has is that the Nelson curve requires that the temperature and pressure reading occur at the same time to affect the curve. There is no evidence that if the exchangers were running a high temperatures that the pressure was also high enough to reach within 25 degrees of the curve. The preponderance of the evidence is that the partial pressure did not measure higher than 291 psia during the life of the exchangers.

A process engineer employed by the refinery testified that as the temperature goes up the hydrogen partial pressure will go down. He also testified that the calculation of hydrogen partial pressure after the incident was very close to the measurement taken at the outlet from the original design calculations. The engineer testified that it is not typical to regularly recalculate hydrogen partial pressure for purposes of evaluating corrosion issues.

I could relate other portions of the record that support the refinery's position but the bottom line is that they are cited for not following their procedure and the evidence is that they did. They were required to consult with corrosion experts and they did. They were required to follow those experts' recommendations and they did. This being the case these violations are vacated.


Violations Nos. 1-22 (a), (b), (c) and (d)/WAC 296-67-037(4) (c)

 

These were originally designated as Violation Nos. 1-22 through 25 but as a result of the summary judgment motion they were combined. The Department cited the refinery under the WAC alleging that the frequency of the refinery's wet fluorescent magnetic particle(wet H2S) inspection of exchangers B,C,E and F was not consistent with the applicable manufacturer's recommendations, good engineering practices and/or prior operating experience. This allegation mirrors the requirement of WAC 296-67-037(4) (c). The Department concedes that there are no manufacturer's recommendations dealing with this type of inspection so the Department burden is to show that the refinery's not inspecting the exchangers must be inconsistent with good engineering practices and/or prior operating experience.

The Department has failed to do so.

This testing is for the purpose of discovering if a piece of equipment has a damage mechanism known as wet H2S cracking. The exchangers were inspected for wet H2S in 1993 and 1998. Neither inspection found any damage. The two later reviews in 1999 and 2003 did not include the E6600 exchangers. I find that based on the evidence that the refinery was not required to continue to perform wet H2S inspections when their corrosion experts did not recommend that they continue.

The refinery's expert and not the former manager of engineering at the plant. He is a mechanical integrity and inspection engineer focused primarily on the petrochemical processing industry. He currently works as a consultant in the field of mechanical integrity and the inspection of pressure equipment. He has also done extensive work for the American Petroleum Institute as a master editor for various documents. He discussed the requirements of API 510 and noted that corrosion specialists should be consulted to help in inspections of pressure equipment. This is something that the refinery did regarding inspections for wet H2S damage.

He explained the history of refineries inspecting equipment for wet H2S. Due to an incident in 1984 the industry included various equipment into wet H2S inspection programs. As it became apparent that not all this equipment was susceptible to this they began removing certain equipment from their inspection programs. This has become something that is normal and accepted in the industry.

the refinery engineer stated that wet H2S depends on the conditions that exist in the stream and not necessarily something that occurs over time. Due to this fact prior inspection information is very important in determining whether a future inspection is needed. It is normal to not continue to inspect for wet H2S unless conditions in the equipment change. There is no evidence that the operating conditions in the E6600 exchangers changed between 1991 and 2007. The engineer agreed with the refinery's decision to remove the exchangers from the wet H2S inspection program. He also noted that there was no wet H2S damage found in the post incident inspection of the E exchanger.

The corrosion expert for the 1999 corrosion review at the refinery did not include wet H2S as a potential damage mechanism because he did not find it to be a potential degradation and it was so unlikely to occur in the exchangers.

Dr. XXXXXX was the corrosion expert for the 2007 corrosion review. He also did not inspect the exchangers for wet H2S in the B and E exchangers. His reason was the temperature in those exchangers was too high for the presence of free water which is necessary for this damage mechanism.

This testimony further supports the refinery's position that it did not violate these cited violations and they are vacated.


Violation Nos. 1-27(a) and (b)/WAC 296-67-037(5)

These violations were originally 1-27 and 1-28 but I combined them in my summary judgment order. They allege that the refinery did not correct deficiencies associated with the effluent exchanger E6600 A, B, D and E companion flanges and temporary clamps before further use or in a safe and timely manner when the necessary means are taken to assure safe operation.

The basis of these alleged violations is WAC 296-67-037(5) which requires the employer to correct deficiencies in equipment which are outside acceptable limits (defined by the process safety information in WAC 296-67-013) before further use or in a safe and timely manner when necessary means are taken to assure safe operation.

There is no dispute that leaks occurred from the exchangers through the years. A maintenance machinist for 25 years for Shell and later at the refinery, testified that he often worked on the valves leading to and from the exchangers due to leaking. He said that the leaks were due to the operators attempting to close the valves and they would break. A long-time operator at the refinery, discussed leaks in terms of the startup process for the exchangers and that they came from the valves. He described leaks in a bunch of different areas, not just the flanges. Another operator who worked on the NHT unit also discussed leaks from the east end dollar plates or the heads. Many other witnesses also discussed leaks but that is not what the refinery has been cited for. The Department has cited them specifically for failure to correct deficiencies with the companion flanges and temporary clamps before further use. This narrows it to that point in time when the refinery responded to the reported leaking by repairing the flanges.

A unit reliability engineer at the refinery in Zone A at the time of this repair testified at length about the process. In the fall of 2009 the refinery changed the valves from orbit valves to a metal-seated ball valve which was more durable. the refinery also upgraded the gasket to one that had better sealing capabilities in August 2009. These were the gaskets between the shell body flange and the tube sheeter channel flange which appear to be the subject of this alleged violation. The upgrade was due to reported leaks at that location.

He was also involved in the installation of the temporary clamps that were installed on the companion flanges that is also cited in this alleged violation as well as dealing with corroded bolts within the exchangers that the Department has discussed in this litigation and I assume are part of this violation though as I previously stated we do not have the testimony of any Department employees to verify that.

It appears that the process involved began with him and others observing a startup where they saw leaks. After investigating the issue they decided the gasket upgrade or revision was the way to deal with the problem. The gaskets were replaced and clamps installed between the E-6600 D and E exchangers. The reason they installed the clamps was that they were unable to replace all the corroded bolts because that would have necessitated a complete shutdown of the equipment.

The clamps were not meant to be permanent. He also testified that the clamps were later pumped with sealant to further insure that they did not leak. He stated that he was unaware of any leaks from the companion flanges after the exchangers were started up in March and April 2009 and before the clamps were pumped with sealant. He also testified that there were no further leaks up to the incident in 2010 and that the clamps and companion flanges were still intact afterwards.

The metallurgist testified that leaks had become very minimal after the various upgrades. A reliability engineer remembered startups of both banks of exchangers in August 2009 where there were no leaks.

Worker, who has worked for a number of years for Shell and the refinery and is an inspector also recalled that there were no leaks during the August 2009 startups and he testified that he understood that the leakage issue had been successfully dealt with.

An expert witness, degree in industrial engineering and has been working in the fire protection and risk engineering field since 1973. He had his own company for a number of years and is currently employed by Baker Risk. He has been involved in various aspects of process safety management in the petroleum industry including inspection programs, operating procedures, mechanical integrity, risk management as well as many others. It is his opinion that the installation of the clamps on the exchangers provided a timely solution to the leakage issue that would allow the equipment to be operated until the corroded bolts could be replaced. He stated that they added an additional layer of protection against any leaks that might occur. He also testified that the refinery's decision to use the clamps was not unusual and that it was common in other refineries.

As to the Department's allegation the refinery should have shut down the equipment immediately rather than use the clamps he stated that there was a significant risk in that case because they would have to unstack the exchangers and he cited examples of the types of events that have and could occur when the procedure is taking place.

He also believed that a reported leak that occurred after the clamps were installed did not show that the exchangers could not be operated in a safe manner. the refinery was able to pump the sealant into the clamps assuring subsequent safe operations.

When reviewing this record and carefully reading the alleged violation and the cited code section I find that the refinery did not violate WAC 296-67-037(5). There is no evidence that the refinery did not correct the deficiencies that were causing the leaks and there is no evidence that the exchangers were not operated safely after the repairs were completed. Though the testimony is somewhat confusing as to when the specific repairs were done and if there were any leaks after the clamps were installed it is undisputed that the pumping of the sealant into the clamp stopped future leaks.

This is very convincing evidence to me that the refinery did not violate the WAC and these alleged  violations are vacated.

 

Violation Nos. 1-29(a) and (b)/WAC 296-67-021(1)(a)(vii) and 296-67-021(1)(c)

 

These alleged violations are related to the refinery's startup procedures for the NHT unit.

Procedure NHT-03, Exhibit 79 was the procedure that is the subject matter of the violations.

 

Violation No. 1-29(a)/WAC 296-67-021(1)(a)(vii)

In Violation No. 1-29(a), the Department alleges that the refinery did not develop and implement written procedures for startup following turnaround, or after an emergency shutdown of the exchangers that provided clear instructions for safely conducting activities involved in the process.

WAC 296-67-021(1)(a)(vii) is the regulation that was allegedly violated. The Department's basic argument in its closing brief is that NHT-03 was vague especially using the word "slowly" to describe certain actions the operators were required to take for startup.

The testimony does not support the Department's position.

An operator for nine years was able to describe the use of the word "slowly" in the start-up procedure without any difficulty. He stated that it was difficult to put the term into "verbiage" but he understood the term based on his training. He described it as a "feel thing". He and his co-workers are "highly qualified" operators who "through experience and training, know when we have established a flow." An operator at the refinery from 1995 through 2014. He testified that "slowly" meant slow based on his experience and training. Another operator and has been training coordinator/supervisor for the past 12 years. She was asked if the procedure informed the operators how many turns per minute an operator was to do to comply. Her response was that was not required based on the operators' knowledge of the process. They are trained on it so they need no further information.

This testimony is consistent with the testimony of Mr. XXXXX, Mr. XXXXX and Mr. XXXXX.

The only witness who testified to problems with the term was an operator at the NTH during his tenure at the refinery. He testified that the word was so subjective that it "really had no meaning at all to the operator." This testimony is not supported by any other current or former employees. I also note that in 2004 he signed Exhibit 196 which was a revision to the start-up procedure. Part of what he agreed to by signing the document was that he understood the procedure which included the word "slowly".

He believed the term was sufficiently clear to allow a trained operator to "safely implement the procedure." In most cases the operator needs the latitude to respond to the conditions at that time.

The Department also makes a brief mention of the procedure being deficient because the start-up lines could not heat up properly. There is no testimony that any of the operators had a problem with this part of the procedure. He stated that this part of the procedure referred to the "dry point" which is an operating limit. This is part of the operators' training and an activity they deal with every day and they are able to adjust to reach the temperature.

The three experts discussed this part of the procedure and did not have a problem dealing with the target temperature. Mr. Moore testified that he had problems reaching the target temperature and the procedure had instructions how to reach it. He also knew what to do when he had problems reaching the temperature and described it in his testimony.

They did not believe there was a need to have instructions because they were trying to reach an operational temperature and not a safe operating procedure. He also agreed that a trained operator would not need more specific instructions, something borne out by the testimony of the refinery's operators.

There is no support for the Department's allegation that the refinery's start-up procedure instructions were vague and created a safety hazard. I would think that if this was such a problem the Department would have found more than one present or former operator who would support that allegation.

Violation No. 1-29(b)/WAC 296-67-021(1)(c)

This alleged violation is very similar to 1-29(a) but cites a different part of the code. The Department alleges that the refinery's policy did not contain safety and health considerations as required by this WAC.

Its brief states that the refinery did not identify hazards presented from the chemicals and fires and did not describe all the safety and health considerations involved.

It does not specify which safety and health considerations are omitted from Exhibit 79 and there is really nothing in the record presented by the Department to go beyond its general allegation. The Department inspector testified that an employer is in compliance with the code if a safety and health procedure is referenced in other procedures. the refinery has done this at page 1 of Exhibit 79. The industrial engineer agreed that this was enough to satisfy the code and that it is a common practice.

The Department has failed to show by a preponderance of the evidence that the refinery violated either of these two regulations. There is very little evidence to support the allegations and they are vacated.


Violation No. 1-30/WAC 296-67-045(1)


The Department alleges that the refinery did not establish and implement written procedures to manage the change made to the warm up steps during the March 2009 start up and those conducted in February and March of 2008 on the E6600 exchangers. It found that this was a violation of WAC 296-67-045(1) that requires the employer to establish and implement written procedures to manage changes to process chemicals, technology, equipment, and procedures; and, changes to facilities that affect a covered process. In its brief it limits the violation to startups in March 2008 and March 2009.

The refinery's response is also limited to these dates and I will only deal with them based on the record before me.

This alleged violation, as well as Nos. 1-31 and 1-36 deal with the refinery's management of change procedure. Exhibits 31, 223 and 224 are the policy, Miscellaneous Operating Procedure No. 2 (MOP-02) that was in effect at various times when these start-ups as well as the two following violations took place. The Department inspector testified that if the written standards comply with the regulatory requirements, written management of change standards, and if the employer follows the procedure they have properly implemented the management of change requirements. He also did not think that the written Management of Change (MOC) procedures had any deficiencies. The citations were based on the failure of the refinery to implement the procedures.

The process safety management coordinator at the refinery since 2007 duties include overseeing the management of change process and having the "care and custody" of the guidance document for the refinery. He makes sure that the company is compliant with regulatory requirements, the corporate standard requirements and he collaborates with refinery personnel on the conduct of change management.

He testified that Miscellaneous Operating Procedure No. 02 (MOP-2) was the refinery's procedure for management of change. He also testified that MOP-4 and not MOP-2 applied to deviations during the implementation of operating procedures.

Nor did MOP-2 apply to one-time changes to operating procedures.

This testimony is supported by the industrial engineer based on his review of the refinery's policies. The Department alleges that the changes to the startup procedures for the NHT in March 2008 and March 2009 required an MOC because those changes became permanent. The problem with the Department's position is that there is no evidence that the refinery deviated from its startup procedure during those times. The Department cites Exhibits 26-29 in support of its argument were admitted by agreement of the parties.

There is no testimony regarding these exhibits. The dates on Nos. 26 and 27 are in 2006 so I don't know if this is evidence of the procedure in effect in 2008 or evidence of a deviation. There is no evidence in this record that I have been able to find that shows that the refinery deviated from its written procedures. This being the case it really doesn't even get to the point if the changes were permanent or temporary since there are no changes to consider.

This being the case the allege violation is vacated.

 

Violation No. 1-31/WAC 296-67-045(1)

 

This violation cites the same code section as 1-30 but it is for a startup on April 1, 2009. The same testimony concerning when the refinery used a MOC is relevant to this citation item. There is testimony about a deviation to the startup procedure on that date. Exhibit 29 was created to deal with that event.

Worker was one of the persons who signed that document. He testified that they deviated from the usual procedure as shown by the handwritten notes on the exhibit to try and reduce leaks. Due to the circumstances of the startup which was a one-time instance a MOC was not necessary.

This testimony was confirmed by an engineer.

The Department has failed to show that this startup was a continuation of earlier deviations or that it became permanent. It followed the refinery's MOP-6487 which deals with one-time events and deviations and a MOC was not required. This violation is vacated.


Violation No. 1-33/WAC 296-67-045(1)

 

The same section of the code is cited but the basis for this alleged violation is the refinery's failure to prepare a MOC when it placed the clamps on the companion flanges between the effluent exchangers E6600 A and B and D and C in March 2009. This change was a subject of another alleged violation which has been vacated in this order.

In its brief the Department alleges that the clamps fall within MOC policy because it was an equipment change that would last for at least three years. This statement is made without a citation to any exhibit or evidence. The only evidence presented in this appeal, some by the Department is that an MOC was not required. the refinery prepared two documents under MOP-64 that have been admitted as Exhibits 90 and 91. The unit reliability engineer who was responsible for the procedure testified that an MOC was not necessary in this instance.

The clamps were not meant to be permanent. They were going to be changed at the next outage or unit shutdown. There is no testimony that this would take until at least 2012 as alleged by the Department.

The correct procedure in these circumstances was to use MOP-64 for temporary repairs. The MOC procedure was for documenting change for something that wasn't managed or managing change.

The inspector agreed that the MOP procedure was the one to follow in this instance. The employee in charge of these various procedures testified that MOP-64, not MOP-2, the MOC procedure applied to the installation of the clamps and he also concurred because the installation of the clamps was not a change to process equipment as set out in MOP-2.

A review of MOP-2 confirms his opinion. the refinery was not required to follow the MOC procedures in this instance based on this record and the violation is vacated.


Violation No. 1-36/WAC 296-67-045(1)

 

Once again the refinery is cited for violating the WAC section dealing with the requirement to establish and implement procedures for management of change. The Department alleges that the refinery failed to use the management of change process when it suspended the WHIP inspection process which deals with wet hydrogen sulfide inspections. The Department cited the refinery for not having frequent enough inspections in another alleged violation that has been vacated in this order.

The Department incorrectly states without citation that there were indications of wet hydrogen cracking in 1998 and 2003. I have not found that in this record. The only testimony of any cracking and that involved the cat cracker. In my previous discussion about wet H2S the evidence was that there was not even any cracking in the exchanger that had been destroyed after it was inspected following the explosion. But this is really not the crux of this alleged violation.

The real question is if the refinery was required to follow the MOC procedure when it decided not to inspect the exchangers. The Department does not cite any specific section of the procedure that would apply to the WHIP inspection program. Exhibit 31 lists what refinery changes require a MOC but my review does not show that inspections are covered and none are cited by the Department. Mr. Hering testified that MOP-2 did not apply to changes in inspection procedures. Ms. Zimmerman stated that changes to the inspection procedures were not subject to the management of change process under MOP-2. The inspection department had its own process for changing its procedures.

The testimony of Mr. Hering and Ms. Zimmerman is not disputed. There is no evidence in this record that supports the Department's position and this violation is vacated.


Violation No. 2-1/WAC 296-67-037(6)(b)

 

This violation is based on the refinery's failure to ensure that the appropriate checks and inspections were performed to assure that certain equipment was installed properly and consistent with the design specifications. The citation mentions the E6600 warm up lines and replacement tube bundle. The Department brief specifically mentions an installation of tube bundles and lines in 2004. The cited violation mirrors the requirement of the code section under the heading "quality assurance".

As in many of these violations it would have been very helpful if the Department had called some of the Department employees who participated in this inspection. I find it difficult to find in this record any evidence that the refinery failed to ensure that the appropriate checks and inspections were performed. There does not, in fact, appear to be any such testimony or documentation in support of this violation.

Warmup Piping

Ms. Zimmerman is the only fact witness who testified about the installation of permanent warmup piping for the E6600 exchangers. The Department alleges that improper materials were used but does not state which materials would be proper. Ms. Zimmerman testified that the refinery followed its process to assure that the materials used for fabrication of the piping matched design specifications. Exhibit 214 is a construction package for the E6600 A and D shell inlet piping that was the warmup lines. The document shows that positive materials identification was performed on the materials. the refinery practice was to create a "blue book" that contained a document with the results of the testing that was required during the fabrication and this was sent to the field for construction. There was a bluebook data base that could be referenced by a number assigned by a document control person. Exhibit 216 is a bluebook tracking record. This is the particular bluebook for the project. Ms. Zimmerman confirmed that the completed bluebook would have the results of the testing and the inspection department would have reviewed it and verified that the equipment was installed properly.

Ms. Zimmerman's testimony is not disputed. There is no evidence that the process as described by her does not comport with the requirements of WAC 296-67-037(6)(b).

 

Tube Bundle

In this instance the Department asserts that the refinery violated the code because it installed a replacement tube bundle with one that was 14-gauge rather than the original 13-gauge. Once again there is no testimony from a Department inspector. the refinery agrees that they used the wider gauge but denies that this violates the cited regulation. The only fact witness to testify regarding this violation was Ms. Beard. She began working at the refinery when it was owned by Shell as a laborer and continued to work there until she retired in 2009. She inspected pressure equipment and tanks. Beard Exhibit 2 is an email exchange between Ms. Beard and the fabricator for the tube bundle. This as well as the other exhibits introduced at the deposition were not offered. Because of the relevance to this violation I have remarked it as Exhibit 278 and it is admitted to the Board record but not the handwritten notes that no one could identify. The purpose of the email was that Ms. Beard was inquiring about the size difference of the bundle. The fabricator assured her that it was the same thing as the smaller gauge.

Exhibit 217 contains various inspection activity reports. The tube bundle replacement is at 19-21. This exhibit was admitted not for the truth of the matter asserted but as a document the refinery had and maintained in its records. It shows that the topic was recorded and kept and the record includes information allegedly from the fabricator which is consistent with Ms. Beard's testimony.

The industrial engineer testified that the difference between a 13-gauge tube and a 14-gauge tube was about the thickness of 1/10 the thickness of a dime. He stated that this difference was not significant. His review of the refinery records showed that they did a review, found the discrepancy and communicated with the fabricator. It was determined by the refinery that there was no material difference and it was satisfactory to place the exchangers back in service.

I also note that the refinery did all this while the exchanger was not in service and it did not place them back into service until it was assured the difference was negligible. The testimony of Ms. Beard and the engineer is not disputed and the violation related to the warmup piping and tube bundle is vacated.

 

Violation No. 2-4/WAC 296-824-50010(2)

 

The Department alleges that the refinery did not ensure that all emergency responders and their communications were coordinated and controlled by the Incident Commander the night of the explosion. It cites a code section that requires the refinery to make sure that all its emergency responders and their communications are coordinated and controlled by the incident commander. The Department brief does not mention specific incidents where the code section was not followed, it makes general statements most of which are not supported in this record. The testimony of the Department inspectors who worked on this violation, is that it is based on statements made by refinery personnel.

This being the case I will focus on their testimony but will include other testimony to supplement my decision. Even if the evidence would show that the refinery did not violate the code based on these three employees I could still find a violation if the general evidence supported it but it does not.

An incident commander "is an employee that is designated by their employer to act as the sole overseer, command and control, of an emergency incident on their particular premises." The incident commander "will typically be controlling a maximum of seven people below him, and they in turn will be controlling people below them." He or she will be relying on subordinates to be in contact with emergency responders. There is no dispute that when the explosion first occurred XXXXXX took the role of incident commander. He set up a post and delegated assignments for the first responders and fire brigade members. This was confirmed by the testimony. There is no evidence that disputes this testimony. He was replaced a bit later by XXXXX who assumed command and began to select other employees to perform specific roles. He chose people to be operations chief, operations liaisons, medical logistics and scribes. The testimony of two others is also not disputed that an operations post was set up and communications were made in a variety of ways including radios, flashlights and hand signals depending on the circumstances. He did not testify but there is ample undisputed testimony that shows what he did that night. He was the operator on duty at the NHT unit that night. This creates its own problem in that I don't think he could be technically found to be an emergency responder but I will continue as if he were. Another operator, came to the field operating center soon after the explosion. At first he tried to help the operator with the board as well as comfort a worker who had been severely injured. He put on his bunker gear and went into the unit to assess the situation. Soon thereafter the operations liaison appeared.

There is no testimony that the responders had any difficulty communicating with the incident commander or anyone in the chain of command. In fact Mr. XXXXXXX, who was part of the chain, was in the control room directing them from soon after the incident until the fire was controlled. He testified that he was in constant communication with Mr. XXXXXX throughout the incident response. Mr. XXXXX also testified that he was in constant communication with the Incident Command post. He also commented how he observed the shutdown coordinator doing an excellent job leading the operation directing the fire brigade members and others through the process.

An operator felt the explosion from her house and drove to the refinery. She checked in at the front gate and first went to the centralized control room (CCR). She explored other areas of the building and eventually got her radio, hard hat, safety glasses and ear plugs and called the board operators in the CCR to inform them that she was going to check the other units which she did by bicycle. While she was doing this she received a call on the radio asking her to check the old control room which she did. She didn't find anyone and called to say she was going to check the other old control room. She didn't find anyone until she entered the new control room where she saw XXXXXXXX and XXXXXXXX. She stayed there until the paramedics took XXXXXX away and while a number of other employees, including Mr. Hargu and Mr. Colvin arrived. She was called and asked to stop the mud wash in the crude unit for the desalters which she did. Throughout the night she continued to perform various tasks, none which included fighting the fire. She did not testify that she had any problems communicating with anyone.

As I previously stated I am not bound by the Department's basing the violation on only three employees. I have reviewed the entire record and it appears the only testimony which supports some of the Department's allegations is that of XXXXXXX, in fact, he was the witness who said it was "chaos" at the scene, a phrase used by the Department in its brief. He was working the night of the incident and he was also a designated first responder. He heard the explosion and put on his bunker gear. As he was walking he observed people fighting the fire and a person who was obviously injured walking toward him. He stayed with her and tried to get someone to assist him. He called someone who was unable to assist him because he was working on a board. He tried to call someone on the emergency channel and when he was unable to do that he started using his flashlight to signal for help. Someone came to help who left and eventually people came with a stretcher to take the injured worker. He then assisted with another injured worker and eventually a supervisor appeared and they went to the fire hall to get air pack bottles and a van and drove to a place where he distributed them. He testified that there was not an incident command structure at the site "in the beginning". This testimony is not supported by any other witnesses and is contrary to much of the evidence. Another employee was also working on the night of the explosion and fire. He, a fire brigade member, heard the explosion and immediately grabbed his truck and went to the fire hall. He and another employee were also there and proceeded to the scene. They met at the top of the hill and began to set up the incident response.

I find it hard to believe that the witness responded any quicker than these two employees which means that the incident command was set up and operating soon after the incident. He eventually reached the incident command post but by that time the IC had taken charge. He did not check in with the incident commander for some time so he really was unaware of the activity and directions and communications that were being conducted from the early stages of the response.

An early responder testified that XXXXXXXXX was already coordinating the response from the fire hall when he first arrived. Seven other employees all testified to being in contact with the incident commander and being able to perform their duties that night as directed by radio, hand signals, flashlight or whatever.

The industrial engineer testified that it is typical for an emergency response to feel chaotic with an event as large as the one that occurred at the refinery. His review of the evidence showed that after the initial shock and confusion the employees reverted to their training and responded in appropriate ways to the disaster.

Even with Mr. XXXX’s testimony the Department barely made a prima facie case relative to this violation. Even the three employees they specifically named testified that they were in constant contact by radio with the incident commander, a supervisor or someone else in authority to direct their actions. The overwhelming testimony is that the refinery set up an incident command that operated throughout the night and that its emergency responders were directed through the chain of command set up by the incident commander. This violation is vacated.


Violation No. 2-5/WAC 296-811-30010

 

The Department has cited the refinery for not assuring that all fire brigade members were fully trained prior to the incident response the night of the explosion. It alleges that the first response crew was deployed to battle a complex incident beyond the scope of their training. The citation also alleges that a fire brigade member did not receive live fire training and participate in any fire brigade drills. The code section is WAC 296-811-30010 which deals with firefighting training. It requires that an employer provide training for brigade members once per year, that it is documented and having been received by the employee and that the training is provided frequently enough to keep brigade members able to do their functions satisfactorily and safely. The rule has a table that sets out what training is required and when it should be given. The training should be appropriate to the members' assigned duties and functions, appropriate to special hazards in the workplace, be similar to that of reputable fire training schools, be a combination of hands-on and classroom experiences and suited to the industry, in this case oil refining. The training should take place before taking any fire emergency activities and repeated every year after initial training.

I note that there is no specific requirement that a firefighter receive live fire training or if it is required what it would include. The Department did not provide any evidence of what the appropriate training should be or the type of specific training the rule requires other than that from two witnesses who have some experience in civilian firefighting but no special training in emergency response or fighting oil refinery fires.

The Department brief cited firefighters whose training and experience were the bases for this violation. One of them did not participate in any firefighting activities so I will not even consider that allegation. I will review the testimony of the other two as well as other first responders and fire brigade members in reaching my decision regarding this citation violation.

XXXX is a first responder. He explained the difference between his duties and that of the fire brigade. The first responder job is defensive firefighting, surround and drown. The fire brigade is designed for offensive firefighting, hose team management and aggressive firefight team. As a first responder Mr. XXXXXX would begin to put water on the fire. It would not be offensive but the purpose was to quelch or quench the fire and cool equipment surrounding the fire. He described that part of his training included fighting a live fire as part of a hose team. He testified that it was more of an offensive type firefighting. His training as an employee was yearly and always included live firefighting. This training included the use of a turret nozzle. He also received first responder training quarterly.

On the night of the incident Mr. XXXXXX was working and heard the explosion while he was in his truck. He went to the fire hall to get his bunker gear and met XXXXXXXX. He drove to the incident command where XXXXXX was coordinating the emergency response. He went to the scene with Mr. XXXXXXX where there was a turret nozzle which he got and began putting water on the fire which he did for the rest of the night. Mr. XXXXXXX did state that Mr. XXXXX told him that he didn't know what a blitz was and he then set him up with the monitor which he was trained to use. He testified that none of his actions constituted offensive firefighting. He also testified that he didn't do anything on the night of the incident that he felt was outside his abilities.

XXXXXXXXX was a first responder on the night of the incident. He got his gear and reported to XXXXXXXX. He assisted in getting the hose cart secured and getting hoses and nozzles out. He then took a back position with XXXXXXXX on a hose and nozzle and directed water on part of the fire to cool it. He did state that to his understanding everyone was going beyond first responder training trying to put the fire out or to contain it rather than defensive turrets. He was not specific and other testimony from first responders does not support this statement. He confirmed that he had been trained to use the types of hoses that he was using that night. He added that the training never dealt with a situation of the intensity that they encountered that night but I am not sure that this rises to the activity that would lead to a violation of the code.

XXXXXX was a first responder working that night. He rolled out hoses and started cooling the equipment. He and XXXXXXX stayed on the hose cooling the fire the entire time they were there. He testified that his training included acting as a nozzleman on a hose.

XXXXX is another first responder who helped with the response. He went to the fire hall where he saw XXXX. He and XXXXX began to set out hoses from the fire truck including a blitz nozzle. He stayed with the blitz nozzle spraying the fire until he was relieved two to three hours later. He had been trained on using the blitz nozzle on one or two occasions. He testified that he was also trained on how to use fixed firefighting equipment and that he did defensive firefighting that night.

XXXXXXX was a member of the fire brigade. He checked in with XXXXXXX and helped set up a blitz nozzle and took over on a hose from a first responder. As a member of the fire brigade he went to fire training in Elko, Nevada that was geared towards refinery fires. He was very critical of the first responder training though his testimony is not supported by any other witness. He also said the first responders were doing activities beyond their training. He described this as throwing water on the fire which he said was dangerous.

XXXXXXXX is a senior safety specialist at the refinery, is a member of the fire brigade and acts as a corporate fire school instructor for the company. He has attended a number of fire schools in other parts of the country. He has taken part in teaching the annual all-employee health, safety and environment training, first responder training and fire training. This training has included fixed equipment, hose handling, foam application and fire ground safety. It includes defensive fire training which is cooling and protecting exposures160 as well as offensive firefighting techniques.

On the night of the incident he was assigned the job of operations chief which entails having an overall view of the response and making sure people are able to do their jobs. He checked on the people in the field after leaving the incident post. He continued to do that through the night using his radio as well as supervising hose team members. He confirmed that the firefighting technique the the refinery employees were using was defensive, reaching and cooling.

Mr. XXXXXXX is a safety superintendent at the refinery. He is a past member of the fire brigade and has conducted training for first responders and fire brigade members. His testimony echoed Mr. XXXXX’s describing the training to include hose handling skills, fire truck skills, master stream skills, HAZWOPER and rescue. Specifically for first responders they were taken to different zones to identify emergency response equipment, how to operate machinery response equipment, the difference between fixed fire equipment which are turret nozzles as well as portable master streams. They would try to set up real situations where the first responders would respond to be followed by the fire brigade. They would set fires to carry out the training and the first responders would practice both defensive and offensive firefighting.

XXXXXXX was a fire brigade member. The training he received was more intense than that received by the first responders. It included being sent to corporate fire schools, training on how to fight or respond to fire in buildings and how to control hydrocarbon fires. On the night of the incident he heard the explosion and drove to the fire hall to get his gear. He then drove the fire truck to the incident where he met XXXXXXX. He and XXXXXX got a monitor and XXXXXX began to spray water on the fire. His intent was not to put out the fire but to cool and protect.

This is classic defensive firefighting. He testified that they were never closer than 120 feet or so upwind and that they only did cooling.

XXXXXXXX was one of the people cited by the Department for not being properly trained. He testified he was a fire brigade member but the only training he had received was the yearly health, safety and environmental training that all the employees got. He was called to the refinery the night of the incident and he checked in at the firehouse and then with the incident commander. He eventually relieved someone on a hose team. He did not recall what he did while a part of a hose team. He also walked around after the fire was out with XXXXXXXX to check if there were any more
leaks.

XXXXXXXXX testified that XXXXXX was working as a kinker on a hose team. This position does not require any specialized training.

XXXXXXXX also remembered that XXXXXXX was either a thruster or kinker. The kinker is the third man on the team who makes sure the hose doesn't get kinked or they would lose water. XXXXXX described the job as someone who is behind the nozzle man and the thruster and works from the hydrant or supply point to the nozzle making sure there are no kinks or they are not dragging the hose over obstacles. He stated that the person acting as a kinker does not need any special training and is just acting as labor. He also testified that the the refinery employees who responded to the fire were only engaged in defensive firefighting.

The Department presented a prima facie case that the refinery violated this regulation through the
testimony of Mr. XXXXXXX and Mr. XXXXXX. Mr. XXXXX, who is a member of the XXXXXXXX, Washington fire department, stated that he witnessed first responders participating in activities that were beyond their training. He described this activity as throwing water on the fire which could reignite the fire. This testimony is not consistent with other evidence. The overwhelming evidence is that the first responders were trained in defensive firefighting which included putting water on the fire and the surrounding area to cool it off.

He was also very critical of the first responder training and called it a waste of time. On cross-examination he admitted he received live fire training which included learning how to operate 1 1/2 inch hoses as well as fixed fire equipment. The training also included the use of equipment to put out live fires. He also testified that the training absolutely does not in any way make someone feel comfortable to attack a fire appropriately and safely. Once again this testimony is not supported by the evidence of the other witnesses. The testimony that Mr. XXXXX did not receive live firefighter training is also prima facie evidence of a violation. Mr. XXXXXX himself testified that he had live training during his yearly health, safety and environmental training.

Based on the evidence this included defensive firefighting techniques and the use of various hoses in fighting fires. On the night of the fire he acted as a kinker which did not include duties that were beyond what he had been trained for. The code section cited by the Department only requires that firefighters receive training that is appropriate to their assigned duties and functions, appropriate to special hazards in the workplace, that it be similar to that taught at reputable fire training schools, that it be a combination of hands-on and classroom experiences and that it is suited to the oil refining industry. The Department did not present any evidence that Mr. XXXXXXX’s training, or for that matter, any of the first responders or fire brigade members training did not fall within these requirements.

In fact, Mr. XXXXXX testified that the kind of training a particular fire brigade member receives depends on what tasks the person is expected to perform. Mr. XXXXXX the inspector who drafted this citation item testified that he doesn't recall what training he thought the first response fire crew should have had.

The Department has not shown by a preponderance of the evidence that the refinery violated the requirements of the code and this section of the citation is vacated.

 

Penalties

Since the entire Citation and Notice has been vacated there is no need to discuss the proposed penalties or any of the ancillary issues that are raised by the refinery in its appeal.

 

DECISION

The employer, XXXXXXXXX Corp., filed an appeal with the Board of Industrial Insurance Appeals on January 21, 2011. The employer appeals Citation and Notice of Redetermination No. 314251315 issued by the Department on December 29, 2010. In this notice, the Department alleged that the refinery committed 47 violations of the Washington Administrative Code. The corrective notice of redetermination is vacated.

 

FINDINGS OF FACT
1. On January 21, 2017, an industrial appeals judge certified that the parties agreed to include the Jurisdictional History in the Board record solely for jurisdictional purposes.

2. XXXXX Company operates a refinery in XXXXXXXX, Washington. Its basic function is to refine crude petroleum into various useable forms of oil-based products, including diesel fuel, gasoline and propane.

3. The naphtha hydrotreater unit (NHT) is located in Zone A of the refinery. It removes nitrogen and sulfur from the naphtha feeder. The reactor treats the feed so it can be moved to the reformer.

4. Hydrogen gas is added to the liquid feed and moves to the reactor feed effluent exchangers. The feed stream enters the tube side of both banks of reactors at the bottom of the banks. After the feed enters the exchangers it exits as effluent on the shell side. They exchange heat as they go through the reactor, the feed being heated as it travels through the exchanger.

5. There are six exchangers, A, B, C, D, E and F in the unit. The feed exits at the bottom, the C and F exchangers and goes to the inlet of the B and E exchangers and exits the B and E and enters the inlet to the A and D exchangers on the top. It goes through the same process on both sets of exchangers and the two feed streams join at the outlet of both banks and then enter the NHT furnace where it is heated to achieve the desired reactor inlet temperature.

6. The reaction takes place and the effluent returns to the exchangers at the top of the inlet of the A and D exchangers on the shell sides. The heated effluent then goes through the exchanger from A to B to C and D to E to F and begins to lose heat. From the heat exchangers it goes to the cooler.

7. During the early morning of April 2, 2010 the refinery employees were preparing to start-up a bank of exchangers in the NTH following a cleanup of the equipment.

8. Soon after starting the process the shell of the E-6600E exchanger ruptured resulting in an explosion and fire. Seven employees died due to the explosion.

9. The explosion was caused by high temperature hydrogen attack (HTHA). HTHA occurs in equipment that is operating at high temperature and at a high hydrogen partial pressure. It is a degradation mechanism that can take place in material commonly used in refineries. The hydrogen is originally in the form of gas and it decomposes at the metal surface at high temperature and high pressure into atoms. Once it is in atom form it goes through steel and if the steel is not resistant enough it can combine with carbon within the steel and form bubbles of fissures and cracks.

10. Item Nos. 1-1 through 1-7. The personal protective equipment provided to the seven employees that died during the explosion was appropriate for starting up the exchangers. There is no appropriate protective
equipment that the refinery could have provided them for the explosion that occurred on April 2, 2010.

11. The pleadings and evidence submitted by the parties demonstrate that there is no genuine issue as to any material fact related to Item Nos. 1-1 through 1-7.

12. Item Nos. 1-8 through 1-13. There is no evidence that [the deceased employees] were performing any duties that they were not trained to do on the night of April 2, 2010 during the start-up of the
exchangers in the NTH.

13. The pleadings and evidence submitted by the parties demonstrate that there is no genuine issue as to any material fact related to Item Nos. 1-8 through 1-13.

14. Item Nos. 1-14 through 1-17. the refinery procedure 1-10.05 and not 1-06.04 applies to written procedures for inspection and testing of the four effluent exchangers. This procedure follows recognized and generally accepted good engineering practice.

15. The pleadings and evidence submitted by the parties demonstrate that there is no genuine issue as to any material fact related to Item Nos. 1-14 through 1-17.

16. Item Nos. 1-18(a) and 1-18(b). the refinery inspection procedure 1-08.08 deals with inspections of equipment for possible HTHA. The basis of the procedure is API (American Petroleum Industry) 510 which deals with the inspection of pressure vessels. This code has been adopted by the State of Washington in WAC 296-104-102(4). It requires the employer to use a corrosion expert when determining potential damage mechanisms and when developing a plan for vessels that operate above 750 degrees and to identify inspection techniques.

17. The refinery hired outside consultants to perform corrosion reviews for the NHT in 1999, 2003 and 2008. The E-6600 exchangers were included in these reviews. The reviews recommended inspecting the A and D exchangers but not the B and E exchangers. the refinery followed these recommendations.

18. The refinery's inspection procedure only recommended inspections for HTHA if it was found that the equipment was operating above the Nelson curve and required routine measurements of temperature and hydrogen partial pressure when the equipment operated within 25 degrees or 25 psia of the Nelson curve.

19. The Nelson curve is contained in API 941 and is the recommended practice for the oil refinery industry to determine if a particular steel is susceptible to HTHA. The curve represents three variables, the material, carbon steel, hydrogen partial pressure and temperature. It also contains reported incidents of HTHA and where there were reported exposures where the mechanism did not occur. You cannot plot conditions on the Nelson curve if the temperature and partial pressure are not taken at the same time. After the explosion at the refinery new incidents were reported that led to a taskforce at the API which issued a new Nelson curve which lowered the required temperature ninety degrees.

20. There is no evidence that the temperature and partial pressure inside the exchangers were ever calculated at the same time or that they operated within 25 degrees or 25 psia of the Nelson curve in existence prior to the explosion.

21. The refinery implemented and followed inspection procedure 1-08.08 in its inspection procedures for exchangers B and E.

22. Item Nos. 1-20 and 1-21. the refinery's Corrosion Awareness and Management Program (ACAMP) was a subject of an earlier appeal at the Board of Industrial Insurance Appeals in In re the refinery West Coast Co., 01 W0964 (2004). The order in that litigation has become final. In the Board's Decision and Order it made a finding that the refinery's ACAMP document was not a written procedure to maintain ongoing integrity of process equipment as required by WAC 296-67-037 (2).

23. The issue related to ACAMP in the prior litigation is the same as in this litigation. The judgment has become final and was made on the merits. The parties are the same and the application of collateral estoppel in this appeal does not work an injustice on the Department of Labor of Industries.

24. Item Nos. 1-22(a) (b) and (c). Wet fluorescent magnetic particle (wet H2S) is a damage mechanism that causes cracking in equipment. The industry first began requiring inspections for this mechanism after an incident in 1984. After determining that not all equipment was susceptible to it they began removing it from inspection programs and it has become a normal and accepted practice to do this. the refinery removed it from the program after 1998.

25. Wet H2S depends on conditions that exist in the stream and is not something that necessarily develops over time. It is normal to not continue to inspect unless conditions in the equipment change. There is
no evidence that operating conditions in the E-6600 exchangers changed between 1991 and 2007.

26. The exchangers were inspected for wet H2S in 1993 and 1998 and no damage was found.

27. The corrosion expert for an inspection in 1999 did not inspect for wet H2S because he did not find it to be a potential degradation and was unlikely to occur in the exchangers.

28. The corrosion expert for the inspection in 2007 did not inspect the exchangers for wet H2S in the B and E exchangers because the temperature in those exchangers was too high for the presence of free water which is necessary for the mechanism to occur.

29. After the explosion an examination of the damaged exchanger did not find any wet H2S damage.

30. Item No. 1-26. the refinery had a compilation of written process safety information for the E-6600 shell and tube side warm up lines. There were no deficiencies in the warm up lines that were outside acceptable limits as defined by WAC 296-67-013 in the refinery's process information material that should have been corrected. None of the target temperatures for the tube outlets and furnace inlet were designated as safe limits by the refinery, only as operating limits which are not required to be included pursuant to WAC 296-67-013.

31. The pleadings and evidence submitted by the parties demonstrate that there is no genuine issue as to any material fact related to Item No. 1-26.

32. Item Nos. 1-27 (a) and (b). Leaks had occurred during the operation of the E-6600 exchangers for a number of years which usually came from the valves.

33. In 2009, the refinery changed the valves from orbit valves to a metal-seated ball valve which was more durable. It also upgraded the gasket to one that had better sealing capabilities that same year. These were the gaskets between the shell body flange and the tube sheeter channel flange. This upgrade was in response to the reports of leaks. the refinery also installed temporary clamps on the companion flanges and repaired corroded bolts.

34. the refinery installed the clamps because they were unable to replace all the corroded bolts because that would necessitate a complete shutdown of the equipment. The clamps were later pumped with sealant to further insure that they would not leak. There were no further leaks up to the startup procedure on April 2, 2010. The clamps and companion flanges were still intact upon inspection after the explosion. the refinery's decision to use the clamps was not unusual and was a common practice in other oil refineries.

35. Item No. 1-29(a). the refinery's start-up procedure for the NHT (Exhibit 79) provided clear instructions for safely conducting activities involved in the process. The operators understood what the term "slowly" meant when they participated in the start-up procedure. They also did not have any problems in reaching the appropriate temperature during the procedure.

36. Item No. 1-29(b). the refinery's start-up procedure for the NHT contained all the required safety and health considerations that were needed by the refinery's employees during start-up including referencing those considerations that were contained in other procedures. This is all that is needed to be in compliance with the code.

37. Item No. 1-30. the refinery's management of change (MOC) procedures found in Miscellaneous Operating Procedure No. 02 (MOP-2), in effect in 2008 and 2009, did not have any deficiencies. MOP-2 did not apply to one-time changes in operating procedures. Miscellaneous Operating Procedure No. 04 (MOP-4) applied to deviations during the implementation of operating procedures.

38. The refinery did not deviate from its operating procedures during the start-ups of the NHT in March 2008, February 2009 and March 2009. the refinery was not required to implement its management of change procedure during any of these start-ups.

39. Item No. 1-31. The start-up of the NHT on April 1, 2009 required a deviation from the normal start-up procedures. This was a one-time instance which did not follow earlier deviations nor did it become
permanent. the refinery followed its MOP-64 procedure which is used for onetime events and deviations. A MOC was not required under these circumstances.

40. Item No. 1-32. the refinery changed the minimum hydrogen-oil ratio for the NHT in 2009. MOP-2 requires that management of change procedures are required when changing an upper or lower critical or safe operating limit, establishing a new critical or safe operating limit or the intentional operation of a process outside the previously established critical or safe operating limit. This action did not change the actual operation of the NHT. The change the refinery made to minimum hydrogen-oil ratio did not
affect the critical or safe operating limits and the refinery was not required to establish or implement written procedures to manage these changes and MOP-2 did not require a management of change procedure under these circumstances.

41. The pleadings and evidence submitted by the parties demonstrate that there is no genuine issue as to any material fact related to Item No. 1-32.

42. Item No. 1-33. The placement of clamps on the flanges of the NHT in March 2009 was not a permanent change that was to last up to three years. MOP-64 was the correct procedure for the refinery to use when making this change because it was used for temporary changes and the refinery correctly followed this procedure. the refinery was not required to use MOP-2, the management of change process when it installed the clamps.

43. Item No. 1-34. Charles Bowers, the refinery's inspection supervisor, placed a note on the first page of the ACAMP in 2004 that he would defer conducting corrosion reviews and the updating of the corrosion control documents because the refinery was intending to implement another program for corrosion reviews. Another corrosion review was completed in 2008 which was within the three to five year requirement set by
ACAMP. The deferral of corrosion reviews and the updating of corrosion control documents is not listed in MOP-2 as changes that require management of change procedures. ACAMP does not fall within either the operating limits or operating procedures that are listed in MOP-2 or any other categories requiring a MOC.

44. The pleadings and evidence submitted by the parties demonstrate that there is no genuine issue as to any material fact related to Item No. 1-34.

45. Item No. 1-35. A process safety hazard analysis (PHA) was conducted for the NHT in 1996, 2001 and 2006. the refinery used a mechanical integrity checklist and reviewed and tracked action items related to corrosion control in 2001 but not in 2006. These were done during corrosion reviews and the refinery determined that they were not necessary during the 2006 PHA. the refinery's procedure for PHAs, SR-67, does not require the refinery to use the checklist or to review corrosion control action items so there was no change in the procedure as covered under MOP-2. The hazard review referred to in MOP-2 is not a PHA as stated in that document. Management of change procedures were not required when the refinery decided to not use the checklist and not track the corrosion control items.

46. The pleadings and evidence submitted by the parties demonstrate that there is no genuine issue as to any material fact related to Item No. 1-35.

47. Item No. 1-36. The decision to end inspections for wet H2S was not a change that required a management of change procedures under MOP-2. The inspection department has its own process for changing its procedures and it is not a part of MOP-2. the refinery was not required to use the management of change process to stop conducting wet H2S inspections.

48. Item No. 1-37. WAC 296-67-017(6) requires that every five years after the completion of the initial PHA it should be updated and revalidated by a team meeting the requirements of this section and assure that the PHA is consistent with the current process. The 2006 PHA revalidation team met the requirements of this code section. the refinery considered the increase to the reactor outlet temperature, a change in the minimum hydrogen-oil ratio for the NHT, the introduction of more reactive feed from the cast gas splitter and the risk of excess heat during the operation of the E-6600 exchangers.

49. The increase to the reactor outlet temperature occurred after the 2006 PHA and the increase to the minimum hydrogen oil-ratio did not occur until sometime in 2008. the refinery completed a project PHA for the increase of the reactive feed from the cast gas splitter and the revalidation team could rely on that PHA in its own process. The revalidation team could rely on the 1999, 2003 and 2008 corrosion reviews that considered operating temperatures and potential corrosion mechanisms for the E6600 exchangers and does not have to perform an independent evaluation of corrosion issues.

50. During the time the 2006 PHA revalidation was being performed there had not been any changes to the NHT process since the 1966 revalidation.

51. The pleadings and evidence submitted by the parties demonstrate that there is no genuine issue as to any material fact related to Item No. 1-37.

52. Item No. 1-38. the refinery increased the safe and operating limit for the reactor outlet temperature in 2006. the refinery did not increase the actual temperature going into the exchangers. These changes were documented and process safety information was updated accordingly. The refinery did not change the original 1971 design temperature gradients and profiles for the E6600 exchangers. The exchangers did not have any safe upper and lower limits for temperature. This being the case, the refinery was not required to update information for the original 1971 design temperature gradients and profiles for the E6600 exchangers, the temperatures listed for the E6600 B,C,E and F exchangers in the inspection department's HTHA database and the operating exchangers temperatures for these exchangers. This is not the type of information that is required to be updated in WAC 296-67-013.

53. The pleadings and evidence submitted by the parties demonstrate that there is no genuine issue as to any material fact related to Item No. 1-38.

54. Item 1-39. There were leaks in the NHT unit during start-ups in March and April, 2009. There is no evidence that either leak was a major uncontrolled emission, fire or explosion involving one or more highly hazardous chemicals that presented a serious danger to the refinery's employees at either time. There is no evidence that either leak could reasonably have resulted in a catastrophic release.

55. The pleadings and evidence submitted by the parties demonstrate that there is no genuine issue as to any material fact related to Item No. 1-39.

56. Item No. 2-1. the refinery installed permanent warmup piping for the E6600 exchangers in 2004. the refinery created a blue book that contained testing of the materials that would be used that was sent to the field during installation. the refinery followed its usual practice to assure that the materials used for fabrication of the piping matched design specifications. Positive materials identification was performed on the materials. The inspection department reviewed the blue book and verified that the equipment was properly installed. By using this process the refinery ensured that the appropriate checks and inspections were performed to assure that the equipment was installed properly and consistent with the design specifications.

57. the refinery installed a replacement tube bundle in 2004. The original tube was 13-gauge and the replacement was 14-gauge. The difference between the two gauges is about the thickness of 1/10 the thickness of a dime. Ms. Juanita Beard, a the refinery employee, contacted the fabricator about the difference and was assured it was the same as the replaced part. Based on its review, inspection and contact with the fabricator the refinery determined there was no material difference and it was permissible to use the new bundle. the refinery did not put the exchanger back into service until it was assured that the difference was negligible. The actions of the refinery were reasonable under the circumstances. the refinery ensured that the appropriate checks and inspections were performed to assure that the bundle was installed properly and consistent with the design specifications.

58. Item No. 2-2. It was necessary for the refinery to modify spare E6600 bellows assemblies prior to installing them. the refinery performed some machining, heating and bending of some of the parts prior to installation. After this was done the bellows fit and were used. There is no evidence that the bellows have not performed as well as the bellows that they replaced. After the adjustments the spare bellows were suitable for the process application for which they were to be used.

59. The pleadings and evidence submitted by the parties demonstrate that there is no genuine issue as to any material fact related to Item No. 2-2.

60. Item No. 2-3. [Six of the deceased employees] did not need to be trained in starting up the NHT. The refinery was not required to provide this training so it was not required to document this training or that the employee understood the training.

61. The pleadings and evidence submitted by the parties demonstrate that there is no genuine issue as to any material fact related to Item No. 2-3.

62. Item No. 2-4. On April 2, 2010 after the explosion, XXXXXXX took the role of incident commander. He immediately set up a command post and assigned duties to the the refinery first responders and fire brigade members. Within a short time XXXXXXX, the designated incident commander took over and continued to assign duties to various employees. Certain employees were designated to be operations chief, operations liaisons, medical logistics and scribes. XXXXXXXXXX and XXXXXXXX and their designees communicated with the emergency responders by phone, radios, flashlights, hand signals and oral communications.

63. [Three responders] were in constant contact and communication with the incident command as well as other supervisors who directed their activities. None of these employees acted as first responders or as members of the fire brigade.

64. On April 2, 2010 after the explosion at the the refinery refinery the company and its employees, specifically XXXXXXXXX and XXXXXXXXX, ensured that all emergency responders and their communications were
coordinated and controlled by the incident commander and his designees.

65. Item No. 2-5. All the refinery employees received yearly health, safety and environmental training that included live fire training and the use of hoses and defensive firefighting techniques. First responders received additional quarterly training that included more intensive and complete firefighting training including defensive firefighting, offensive firefighting and the use of various hoses and equipment. Fire brigade members received more training that included training by outside trainers at sites in other parts of the country. They were taught offensive firefighting techniques.

66. Defensive firefighting is putting water on the fire and surrounding area and is intended to provide cooling and protecting exposures. Offensive firefighting directly attacks the fire with intent to put it out. All the first responders were trained in defensive firefighting methods which included using fixed equipment, hose handling, foam application and fire ground safety.

67. XXXXXXXX was a member of the fire brigade and had received live firefighter training that was included in the annual health, safety and environmental training. On the night of the incident his job was to act as a kinker, the third person on a hose team. He was to work from the hydrant or supply point to the nozzle making sure there are no kinks and that the team was not dragging the hose over obstacles. This job does not require any special training.

68. On the night of the explosion, April 2, 2010, the first responders and fire brigade members were assigned duties and functions that were appropriate for their functions and appropriate to the special hazards in the workplace. There is no evidence that the training they received was not similar to that taught at reputable fire training schools. The training was a combination of hands-on and classroom experiences and was suited to the oil refining industry and was at least annual and in most instances quarterly as well as outside training provided to fire brigade members. the refinery documented the training and was provided frequently enough to keep the first responders and fire brigade members able to do their functions satisfactorily and safely. None of the first responders or fire brigade members were injured on the night of the explosion while performing their emergency response activities.

CONCLUSIONS OF LAW
1. The Board of Industrial Insurance Appeals has jurisdiction over the parties and subject matter in this appeal.
2. The refinery is entitled to a decision as a matter of law as contemplated by CR 56 for Item Nos. 1-1 through 1-17, 1-20, 1-21, 1-26, 1-32, 1-34, 1-35, 1-37 through 1-39, 2-2 and 2-3.
3. The Department is collaterally estopped from finding that the refinery violated WAC 296-67-037(2) in regards to its corrosion awareness and management program. (ACAMP).
4. Item Nos. 1-1 through 1-7: No violation of WAC 296-800-16015(1) has been established.
5. Item Nos. 1-8 through 1-13: No violation of WAC 296-67-025(1) has bee established.
6. Item Nos. 1-14 through 1-17: No violation of WAC 296-67-037(4) has been established.
7. Item Nos. 1-18(a) and 1-18(b): No violation of WAC 296-67-037(2) has been established.
8. Item Nos. 1-22(a) through 1-22(d): No violation of WAC 296-67-037(4) (c) has been established.
9. Item Nos. 1-26, 1-27(a) and (b): No violation of WAC 296-67-037(5) has been established.
10. Item No. 1-29(a): No violation of WAC 296-67-021(1) (a) (vii) has been established.
11. Item No. 1-29(b): No violation of WAC 296-67-021(1) (c) has been established.
12. Item Nos. 1-30 through 1-36: No violation of WAC 296-67-045 has been established.
13. Item No. 1-37: No violation of WAC 296-67-017(6) has been established.
14. Item No. 1-38: No violation of WAC 296-67-045(4) has been established.
15. Item No. 1-39: No violation of WAC 296-67-049(1) has been established.
16. Item No. 2-1: No violation of WAC 296-67-037(6) (b) has been established.
17. Item No. 2-2: No violation of WAC 296-67-037(6) (c) has been established.
18. Item No. 2-3: No violation of WAC 296-67-025(3) has been established.
19. Item No. 2-4: No violation of WAC 296-824-50010(2) has been established.
20. Item No. 2-5: No violation of WAC 296-811-30010 has been established.
21. Corrective Notice of Redetermination No. 314251315, issued by the Department of Labor and Industries on December 29, 2010, is vacated in its entirety.

 

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