Sinclair Wyoming Refining Co. v. Pro-Inspect Inc.

          OPINION AND ORDER STATING FINDINGS OF FACT AND CONCLUSIONS OF LAW

          ALAN B. JOHNSON, UNITED STATES DISTRICT JUDGE.

         This matter is before the Court following a nine-day bench trial. At trial, the plaintiff Sinclair Wyoming Refining Company ("Sinclair") was represented by Patrick R. Day, Buck S. Beltzer, and Geraldine A. Brimmer. The defendant Pro-Inspect, Inc. (d/b/a Moody International Asset Integrity Services, Inc., a Texas Corporation) ("Pro-Inspect" hereafter for purposes of this order) was represented by Paul J. Hickey, O'Kelley H. Pearson, John J. Kenney, and Jules R. Cattie, III.

         Having carefully considered the testimony and evidence presented and the arguments of counsel, the Court makes the following findings of fact and conclusions of law.^[1]

         Introduction and Brief Summary of Contentions

         Sinclair owns and operates a refinery located at Sinclair, Wyoming, processing crude oil, including sour crude from Canada. Sinclair is a Wyoming corporation, with its principal place of business in Utah. Pro-Inspect is engaged by refiners to perform inspection services at their facilities. Pro-Inspect is a Texas corporation and its principal place of business is in Texas. Sinclair has asserted two claims against Pro-Inspect, breach of contract and negligence. Sinclair's complaint was filed August 30, 2012, seeking to recover approximately $7.5 million in property damages and $50 million in other "business interruption" losses it claims are attributable to the fire that occurred on September 1, 2011, when a pipe containing high temperature slop oil ruptured. Pro-Inspect has denied all claims and disputes that Sinclair is entitled to recover damages in any amount. This Court has diversity jurisdiction pursuant to 28 U.S.C. § 1332. Venue is proper in this district pursuant to 28U.S.C. §1390.

         Broadly, Sinclair contends that Pro-Inspect's inspector, Josh Kiss, was required by the parties' contract, and by the American Petroleum Institute (API) Codes governing piping inspections by API 570 certified inspectors, to review all the data gathered by technicians Malave and Hulsey and carefully consider potential risks to the piping circuit. Sinclair contends it hired Pro-Inspect specifically to provide a knowledgeable API 570 certified inspector to conduct inspections at the refinery. Sinclair contends the API Code obligates inspectors to, among other things: (1) review all ultrasound data; (2) consider prior inspection histories; (3) confirm that piping systems are properly classified for risk; (4) evaluate the need for, and determine the proper number of corrosion monitoring locations (CMLs); (5) ensure that CML locations are placed on a circuit and that thickness data at those locations are collected; (6) consider the data collected for the risk of failure; (7) calculate the remaining life of the piping in the circuit; and (8) immediately report thin pipe to the refinery owner for further evaluation and action. Sinclair contends these obligations are all components of a standard industry inspection and are spelled out in API 570, the applicable piping inspection code. Sinclair contends that Pro-Inspect's inspector, Josh Kiss, failed to do every one of these tasks, causing a significant stretch of paper-thin pipe to be missed, proximately causing the explosion and fire and resultant damages. The section of pipe involved in the fire has been lost or destroyed by Sinclair and as a consequence could not be inspected or tested by Pro-Inspect.

         Pro-Inspect denies Sinclair's allegations and denies any liability for the September 1, 2011 fire. It asserts that its employees, Josh Kiss and Michael Fitzpatrick, were directed by Sinclair to perform two assignments: one, to organize certain refinery piping systems into manageable circuits in order to facilitate the inspection process (i.e., to systemize and circuitize); and, two, to conduct an external visual inspection to look for external damage to the piping structure, which was wrapped in thick, non-transparent insulation. The only work that Pro-Inspect did on the circuit which is the subject of this lawsuit, 02-04-02, was external visual inspection of the piping by Kiss. Neither Kiss nor Fitzpatrick, nor any other person at Pro-Inspect, was asked or directed by Sinclair to make ultrasonic thickness ("UT") readings to measure internal corrosion of the pipes. Sinclair had hired a different contractor, TechCorr, to perform that service through its employees, Juan Malave and Russell Hulsey.

         Pro-Inspect maintains that its inspectors performed all of the tasks that Sinclair directed them to perform, and that they did so, with no complaints or other instructions from the Sinclair personnel overseeing their work. Pro-Inspect asserts that it fulfilled its contractual obligations to Sinclair and cannot be held responsible for the fire. Furthermore, Pro-Inspect urges that any acts and omissions Sinclair complains of were the acts of Sinclair or TechCorr, the employer of Malave and Hulsey, and not Pro-Inspect. Pro-Inspect asserts that the proximate cause of the fire and resulting damages was Sinclair's poor management of its own refinery and not a result of anything Pro-Inspect did or failed to do.

         Standard for Non-Jury Trial

         Fed. R. Civ. P. 52(a) provides that in all actions tried upon the facts without a jury or with an advisory jury, the court shall find the facts specially and state its conclusions of law separately.

         Thus, the role of this Court in this action tried upon the facts without a jury is to find the facts specially and to state separately its conclusions of law thereon. OCI Wyoming, L.P. v. Pacificorp, 479 F.3d 1199, 1203 (10th Cir. 2007)(citing Fed.R.Civ.P. 52(a)). The Court's findings of fact "should be sufficient to indicate the factual basis for the court's general conclusion as to ultimate facts[, ] ... should indicate the legal standards against which the evidence was measured[, ]... [and] should be broad enough to cover all material issues." Id. (citations omitted). The Court is not required to undertake this task in excruciating detail. Id. at 1204. "The judge need only make brief, definite, pertinent findings and conclusions upon the contested matters; there is no necessity for overelaboration of detail or particularization of facts." Id. (citations omitted).

         Findings of Fact

         On September 1, 2011, there was a fire at the Sinclair Wyoming Refining Company, which occurred after a pipe ruptured in the refinery's 585 Vacuum Unit at Circuit 02-04-02. Fortunately, no one was injured in the fire. Sinclair's claimed damages include property and business interruption economic damages. Sinclair alleges that the fire and claimed resultant damages were caused by Pro-Inspect's breach of contract and negligence in the inspection of that same circuit in January of 2011, nearly nine months before the fire. Pro-Inspect denies these claims and asserts that the fire was the result of Sinclair's own failures and states that it fulfilled all contractual obligations owed to Sinclair and was not negligent in the performance of its duties.

         There are two main crude processing units in Sinclair's refinery: the 582 unit processes sweet crude and the 581/583 unit processes primarily sour crude. Raymond Hansen, who was the operations manager at the facility in 2011, testified about production at the Sinclair refinery. He explained there are a number of intermediate units which process oil from the crude units into marketable products, such as LPG, gasoline, jet fuel, diesel, sulfur, and other products for consumers. There are two components of the 581/583 unit including the 5 81 atmospheric distillation tower in which sour crude is heated and distilled into different fractions; reduced crude which is not distilled by the 581 unit is piped into the 583 unit, which separates reduced crude further in the 583 vacuum tower.

         A 2008 revamp of the refinery was intended, at least in part, to allow the processing of less expensive crudes. The 2008 revamp project involved a considerable investment by Sinclair, approximately $90 million. It included extensive pipe and heater replacements to allow production of the less costly Canadian crude oils. The pipe that ruptured September 1, 2011 in the 02-04-02 circuit and which is at issue here had not been replaced during the 2008 revamp, although some modifications had been made to the line during the revamp. The particular pipe that had been left in place during the 2008 revamp had been in service for 30 years at the time of the September 1, 2011 rupture.

         In 2010, less costly but more corrosive Canadian Cold Lake crudes were introduced into the refinery. Canadian Cold Lake and Western Canadian Select crudes were run in the refinery in 2010 and in 2011. Beginning in October 2010, Sinclair's refinery processed up to 40% Canadian Cold Lake Crude. Jt. Ex. 31, Ex. Z11. Crude oil coming into the refinery may be received from various sources, called a "basket of crude," which might include Canadian, North Dakota or Wyoming crude oils. Tr. Vol. I, Hansen, 94. Hansen testified "[w]hat we try to do is run really as smooth as we can because of the complexity of the refinery. There's a push and pull between all these different units and our incoming inventories, our outgoing inventories, and so we try to run a crude that's really a consistent sulfur on the sour unit, a consistent sulfur on the sweet unit, and that it's a consistent density. We refer to that as API gravity." Id. Hansen described equipment, noting that there are massive amounts of piping surrounding the units, with the piping and interconnecting piping described as very complex. All of the piping and equipment must be inspected periodically. After crude is processed, products for sale are temporarily stored in tanks and eventually transported out of the refinery through pipelines. The Canadian crudes, also known in the industry as "opportunity crudes," are poor quality, less expensive crudes that can increase a refinery's profitability. Ex. A12. Sinclair itself recognized that the corrosive nature of these crudes was a concern long before the September 1, 2011 rupture/fire happened. Ex. Q.

         The downside to using the cheaper opportunity crudes is that they are highly corrosive and place greater demands on refinery facilities, especially on piping systems. Heavy sour crudes contain high amounts of naphthenic acid which can cause extensive damage to refinery piping systems, and can cause localized, accelerated corrosion greater than that caused by sweeter crudes. With higher naphthenic acid content, opportunity crudes can cause pipes to corrode by as much as 100 mils to over 200 mils per year.^[2] There are different types of processes that might corrode and degrade a refinery's piping and equipment, much of which depends on the type and quality of the crude oil being processed. Sulfidation is one type of corrosion process that occurs inside a pipe as a result of a reaction between the pipe's surface and sulfur contained in crude oil. This is the generally expected corrosion mechanism that affects much of the piping in Sinclair's Crude/Vacuum Unit, including the vacuum tower slop oil 02-04-02 piping circuit at issue in this case. The characteristics of sulfidation are gradual thinning over time and fairly uniform thinning throughout a piping circuit. In other words, the various locations within a piping circuit are generally considered to corrode at similar rates by sulfidation. Sulfidation also results in an adherent sulfide coating on the inside surface of the pipe which acts like a barrier between the corrosive oil flowing through the piping system and the steel wall so that it effectively slows down the rate of corrosion. Sulfidation would have been the expected corrosion mechanism operative in the 02-04-02 piping circuit at issue here as all available information indicated a fairly uniform pattern of thinning throughout the circuit.

         Erosion corrosion is another corrosion process described in API 571 and is exacerbated by crude oils containing high levels of naphthenic acid. Erosion corrosion causes accelerated and generally localized corrosion because of the erosive actions of the oil flowing through a circuit. For this reason, API 570 directs placement of corrosion monitoring locations ("CMLs") at points on a circuit where flow changes, rather than straight runs. Crude oils that are more corrosive, such as those with more naphthenic acid, will increase the rate of erosion corrosion in a piping system.

         Vacuum-unit piping such as the slop oil circuit 02-04-02, when exposed to naphthenic acids, can suffer from severe erosion corrosion and metal loss, depending on the particular variables of temperature, velocity, sulfur content, total acid number ("TAN"), and the concentrations of naphthenic acid within the piping circuit. Naphthenic acid corrosion is another form of corrosion that does not occur uniformly throughout a piping circuit. Instead, it may occur at discrete locations within a piping circuit and can occur when crude oil containing naphthenic acids, such as Canadian Cold Lake crude, is put through the system. Naphthenic acid corrosion is not predictable even when the TAN, the temperature, and velocity are known. Naphthenic acid corrosion is episodic, sporadic, and localized and can occur at rates of 200 mils per year and higher. No. information was made available to Pro-Inspect that would have alerted it to any issues with this more aggressive corrosion mechanism.

         However, there is no disagreement that the particular piping that ruptured had in fact corroded and was thin pipe at the time and location that it ruptured in September of 2011. Whether that thinning and rupture in that location was caused by failures in performing the piping inspection nine months earlier was clearly contested. This requires the Court to consider what the parties' agreement for inspections encompassed in this case.

         James Eggleston was a corporate project supervisor at the refinery at the time of trial. Initially, he was hired by Sinclair as an inspector and eventually he became the supervisor of the piping inspection department, and was the supervisor at the relevant times at issue in this case. The American Petroleum Institute has published standardized procedures governing inspections, including API 570, entitled "Piping Inspection Code: In-service Inspection, Rating, Repair and Alteration of Piping Systems." Joint Ex. 4. Eggleston was certified in 2008 as an API 570 inspector employed by Sinclair; all other full time inspectors reported to him. He testified that various third party inspectors were also hired at the refinery to provide inspection services, including Pro-Inspect, among others. Eggleston was responsible for directing Pro-Inspect's activities at the refinery prior to and after 2010 during turnarounds and gave instructions to inspectors.

         Eggleston sought and received approval in 2010 to hire TechCorr and Pro-Inspect again for the update mechanical integrity (sometimes "MI" or "catchup") project because Sinclair personnel were unable to handle the big job presented by the catchup plan. Thus, contract workers were also used to help with the catchup inspections. Michael Fitzpatrick, a Pro-Inspect contract inspector at the time, was already onsite working at the refinery when the catchup plan began. Fitzpatrick was not then an API certified 570 piping inspector; he was certified for API 510 vessel inspection at that time. Fitzpatrick worked closely with and received instructions from Eggleston during this time period.

         Eggleston himself was an API 570 certified piping inspector and had a mechanical engineering degree from the University of Wyoming. He had inspection responsibilities in addition to supervisory duties. He arranged all piping inspections at the refinery. He was responsible for reviewing inspection reports for deficiencies, communicating deficiencies to the refinery's reliability engineers and unit inspectors, and for identifying and initiating corrective action. The inspection department at Sinclair was expected to develop and maintain the thickness monitoring program allowing for monitoring of internal corrosion in the piping systems at the refinery. Ex. A3, 6.3.1.

         To facilitate the catchup project, in addition to Sinclair's own inspectors, as stated earlier, independent contractors were also engaged. Eggleston outlined the scope of the work he wanted done in the crude units in the beginning of the project and assumed those instructions would be passed on to Kiss by Fitzpatrick or others. He defined the scope of what he wanted inspected. The scope of work was orally given to Fitzpatrick to systemize, correct, circuitize, and perform visual inspections. Eggleston maintained that he had not undertaken the detailed planning of the project and that his plan was simply to get the units inspected based on needs he had identified. Eggleston acknowledged and agreed that he was responsible for the inspection work performed on the 581 and 583 units. Eggleston, as inspection supervisor, had supervisory authority over contract inspectors in addition to Sinclair's inspectors and he was responsible for all inspection work done at the refinery. At all times, Sinclair retained supervisory authority over contract inspectors' work.

         Pro-Inspect was started as a family owned company in 1996, with its business described as the visual inspection of petrochemical equipment, including piping, pressure vessels, storage tanks in the refining and chemical plant industry. Pro-Inspect arranged for and coordinated contract API certified inspectors and licensed technicians for many refineries needing inspections for piping, equipment, vessels and other assets. Under the contracts between Sinclair and Pro-Inspect, it was understood that Pro-Inspect would be providing API 570 inspectors, charging its customers an hourly rate for the work performed by its contract inspectors, dependent upon the inspector's experience, skills, and certifications. The API 570 certified inspector is the highest qualified employee, with the requisite years of experience and passage of the API test demonstrating knowledge of the code. Pro-Inspect charged Sinclair $72.77 straight time and $99.39 per hour overtime, for Josh Kiss, the API 570 inspector working on this project. Josh Kiss was employed by Pro-Inspect and provided services as directed by Sinclair at the job site once he began work at the refinery in January of 2011.^[3]

         When the catchup project was beginning, Pro-Inspect's certified vessel inspector, Fitzpatrick, was onsite at Sinclair, working on other projects. Eggleston had worked with Pro-Inspect and Fitzpatrick previously during the 2008 upgrade to the 581/583 units. During that time, Fitzpatrick had developed and used inspection work requests (IWR) to recommend immediate repairs based on inspection findings. IWR forms were presented to Eggleston for further consideration, a standard process at the refinery. Because of their favorable prior work relationship, Eggleston agreed to Pro-Inspect's Fitzpatrick's request to participate in the catchup inspection project. Eggleston and Fitzpatrick met in late November 2010 to discuss and plan the work on the MI catchup project. Work on the project included external visual pipeline inspection, calculating and placing CMLs on piping circuits, consistent with guidelines under API 570 § 5.6.3, among other things. Eggleston asked Fitzpatrick to have Pro-Inspect bring another API 570 certified inspector on board. Fitzpatrick was a certified vessel inspector, but did not then have API 570 certification.

         Kiss was contacted initially by Brad Wells, of Pro-Inspect, regarding a job in Sinclair in January of 2011. Wells outlined the basic details of the job and asked if Kiss would be interested, with Kiss responding yes. Kiss did not recall specifically sending a resume to Pro-Inspect directly, and indicated that he had used different websites, some with recruitment companies, to learn about upcoming work. Kiss was later telephoned by Mike Fitzpatrick, who outlined the job in more detail saying that Sinclair was going to systemize and circuitize three different units in a six month long project, with two months per unit, and to perform any external visual inspections as needed. Kiss was interviewed telephonically by Fitzpatrick about work on the catchup project at Eggleston's request. After that interview, Kiss was called back by Brads Wells of Pro-Inspect about the job, and met with Wells and possibly others in Pasadena, Texas to discuss the job working at the Sinclair refinery. In January 2011, Kiss went to the Wyoming Sinclair refinery and reported for work as a Pro-Inspect API 570 contract inspector on the catchup project. He first reported to the safety council in Rawlins for a safety training course and clearance before he could begin work at the refinery. After that, Kiss went to the refinery, met with Fitzpatrick at the construction trailer and was given information about the scope of work. Fitzpatrick introduced Kiss to the TechCorr technicians and to Eggleston. To Eggleston, Fitzpatrick introduced Kiss as the inspector who would be picking up on systemizing and circuitizing and performing external visuals as needed.

         Separate contracts were entered into with TechCorr and Pro-Inspect, with TechCorr charged with drafting isometric drawings and taking UT readings of the pipe. UT readings provide a snapshot of a particular piece of pipe at a particular location. Alone, UT readings are not singular tools for identifying troublesome corrosion, but the data gathered with UT readings can be used to determine rates of corrosion over time by comparing earlier or previous UT measurements to newer, more recent UT readings. A corrosion rate is a predictive tool but is not designed to identity locations that are in the most urgent need of repair. UT readings are taken at designated locations and intervals and are used to calculate how much pipe wall is lost over time through corrosion. The same CMLs are used for repeat or subsequent measurements to generate meaningful corrosion data. Corrosion rates aid in estimating the remaining life of any particular piping system. This is calculated by determining how long it takes for a thickness reading to reach a predetermined minimum thickness, with the goal being replacement of piping prior to reaching that minimum thickness. Minimum thickness is defined by API 570 as the greater of pressure design thickness or structural minimum thickness, but a refinery may elect to utilize a higher thickness minimum value instead of code-defined minimum thickness values in determining useful life of piping, depending upon whether the policy at the refinery is conservative and how much risk is acceptable. In this case, Sinclair established a minimum thickness value for all piping systems equal to the piping pressure design thickness, which is the point where internal pressure would cause the pipe to rupture. For the 02-04-02 circuit, this is 0.004 inches.

         Other tools are available, including radiography, that are also used to monitor piping system health. Radiography samples a larger area of a piping circuit than standard UT measurements and may be more effective when evaluating localized corrosion, such as that seen with the use of sour crude oil with high concentrations of naphthenic acid in heavy Canadian crude oil. Sinclair did not use radiography to monitor its piping systems.

         In addition to visual inspections, an API 570 inspector might be expected to locate and determine the number of necessary CMLs, and after inspection, to submit a report. TechCorr and Pro-Inspect worked hand in hand on the catchup project. Eggleston reported to John Rosacker, who was in charge of the Sinclair Process Management/Inspection Department. Eggleston was responsible for the refinery's inspection program and directed Sinclair's technicians and all of the refinery's contract inspector technicians. Eggleston directed Sinclair's refinery unit inspectors, the employees responsible for managing inspections of the crude units, and the activities of third party contract inspectors, including Pro-Inspect among others.

         On January 1, 2010, Sinclair and Pro-Inspect entered into a written contract, which was subsequently extended through Pro-Inspect's work in 2011. Joint Ex. 3. The 2011 contract described the scope of work simply as follows:

Pro-Inspect will provide API Certified Inspectors NDE Techs to access [assess] piping and vessels as directed by Sinclair.

         Joint Ex. 3, PI-1656. The scope of work language was copied by Pro-Inspect's Misti Jones in her own handwriting from a previous 2009 contract that had been entered into between Sinclair and Pro-Inspect. Jt. Ex. 2 ("Pro-Inspect will provide API certified inspectors & NDE technicians to assess piping & vessels as directed by Sinclair.") Jones was authorized to sign contracts on behalf Pro-Inspect. Jt. Ex. 2, PI-1558.

         The contract further provides "Contractor shall perform the Work diligently and carefully in a good and workmanlike manner according to accepted standards of construction" and is an independent contractor with "full power and authority to select the means, methods and manner of performing the Work, being responsible to Company for all materials delivered and for the results contracted for." Joint Ex. 3, 1634. Excerpts from the deposition testimony of Steve Wells, employed by Pro-Inspect between June 2006 and April 2012, were read into the record at trial. Wells was employed as coordinator and manager of field services for Pro-Inspect, coordinating and sending inspectors to refineries. He testified as to his expectations of API certified inspectors, to the professionalism expected of them, and to the expectation that they will exercise the judgment and expertise that accompanies API certification. They are expected to understand the API code, know where to find answers necessary to implement the code, and to work independently in a refinery.

         Sinclair's Eggleston explained that he was responsible for arranging all of the inspections during 2011. Def. Ex. A3. Once the project began, Eggleston claimed he was not involved in the actual on the ground inspection of each circuit and that he received progress reports from Fitzpatrick in morning meetings. Eggleston claimed that he provided no additional direction about the project. Minutes of morning meetings discussing the project and its progress were received and are included at PL Ex. 13. However, at the refinery itself, Eggleston for Sinclair usually gave oral instructions to Fitzpatrick (who was then with Pro-Inspect) outlining the scope of work on the project and work that was to be accomplished. Oral instructions were shared with API certified inspectors daily or weekly, but those instructions were not written down. In other words, details as to the exact scope of inspection work to be accomplished were as provided and as directed by Sinclair.

         The parties have disagreed about the scope of work for this project. Sinclair asserts its inspection supervisor, Eggleston, specifically told Pro-Inspect's lead supervisor, Fitzpatrick, that Sinclair wanted a "full API 570" inspection. Sinclair contends this would include review of ultrasound thickness data (UT data), placement of CMLs, calculation of the remaining life of piping circuits and verbally reporting problems that might be found. Pro-Inspect has asserted Sinclair only directed it to conduct external visual inspections of the exterior of the piping systems and related supports and says that review and analysis of UT data was Sinclair's responsibility, working separately to review data collected by the TechCorr technicians. The Court agrees with Pro-Inspect.

         GP Amerispect worked at the refinery from 1999 to 2004 and did some inspections in 2002. Between 2002 and 2008, there were no inspections on the 583 unit. Inspections were conducted by TechCorr in 2008; no corrosion rates were calculated from the 2008 inspections. The 2008 revamp of the 583 unit was completed in August of 2008. As explained briefly earlier, in 2010, Eggleston began planning for the 2011 catchup inspections, also called the MI (mechanical integrity) project; his plans anticipated several phases of work, and his catchup plan was approved by Sinclair. Joint Ex. 21. Eggleston stated in his November 17, 2010 email to Sinclair's Jim Larscheid, regarding the mechanical integrity catchup plan (Jt. Ex. 21):

As you know, we have several phases of work to be completed for the Mechanical Integrity program to become functional.

The first step is to start using the information that has been gathered. I would like to move the Sinclair personnel currently employed to a status of "Run and Maintain" where SWRC personnel will begin re-surveying areas of the plant and entering data into MaxiTrak on a daily basis. This would not only move the MI program forward, but allow scheduled time for SWRC's API certified inspectors to obtain the necessary on the job training for certification in NDE. Initially, I have stated a goal of one piping circuit or pressure vessel external inspection per day from each inspector not in the "Rover" position. This would include gathering the UT data and field walkdown, analyzing the UT data with past history and writing the inspection report in the MaxiTrak program. Issuing IWR's for repairs would be part of this process as well. Initially the unit priority will be based on the Shutdown schedule for 2011 in an effort to get data prior to shutdown on these units.

Another phase is to get the units that have been radically revamped since the initial survey re-circuitized. The units included here are 581/583 Crude, 582 Crude, Reformer, and Hydrocracker units. Additionally, we have two small subsections of the alky complex that were skipped over in the initial survey effort, such as the cat-poly unit and the GRU. I would like to utilize contract personnel to perform these baseline surveys, consisting of one API 570 inspector, and three to four technicians based on workload. These areas will require revision to existing sketches and in many cases complete new sketches, along with baseline UT data.

Both of these efforts will require support from insulation and scaffold personnel. The main support will be from the insulation personnel to install inspection ports in the piping, every effort will be made to place insulation ports in relevant locations that will be accessible without scaffold on a long term basis. I am sure that I can coordinate the scaffold support through the maintenance department, but it might be a smoother process if I had control of a subset of insulation personnel that can be coordinated by my department to facilitate workflow of the new systems.

The workflow has the following steps:

1.) Systemize the P&ID's and break into circuits.

2.) Send technician to sketch circuit.

3.) The API would calculate the number of CML's, and assign on drawing with input on accessibility from Technician.

4.) Assign package to technician to mark areas with paint on piping.

5.) Assign package to insulation crew for inspection port installation.

6.) Assign package to technical to gather UT data.

7.) The final step is data entry in to MaxiTrak. This can be accomplished two ways:

a. By direct entry one circuit at a time, or b. By entering multiple circuits into a spreadsheet and sending to Canada for bulk entry.

I also envision a clerk to help put the information packages together.

Jt. Ex. 21.

         Collected data was never entered into MaxiTrak system in a timely manner by Sinclair. The purpose of the program was to organize data and make information easily accessible and retrievable. The program was also intended to perform corrosion rate and remaining life calculations on piping circuits. The program had been purchased in 2007, but inspection data had not been entered into the program in 2011. The data management program was never implemented for Unit 583 for any time period relevant to this litigation, with Sinclair explaining it lacked manpower resources to do so. Sinclair inspectors were the only inspectors with access to the MaxiTrak program; contract inspectors did not have authority to use that program.

         From his earlier work at the refinery, Fitzpatrick was familiar with the 2008 581 and 583 unit upgrade project. That project had altered some piping circuits that previously existed when an earlier inspection was performed by GP Amerispect. For inspections of the pre-2008 upgraded piping, including the circuit in this case, Eggleston instructed Fitzpatrick to use the prior 2002 GP Amerispect inspection data when conducting the 2011 inspections. Fitzpatrick did not agree with Eggleston on the number of CMLs and had suggested instead that a CML calculation form he had used in work at other refineries be used during the catchup project. Eggleston said he thought GP Amerispect's placement of CMLs on the circuits was not adequate and said he told Fitzpatrick he wanted more CMLs placed on the circuits. Eggleston recognized that the code really did not provide a specific guideline on how many CMLs there should be. Eggleston stated that he had "developed a CML calculation form to, urn, to settle that argument, I guess, to define a number of CMLs for each circuit based on the characteristics of the circuit, urn, taking into account the length, the number of fittings, the corrosion rate, the number of deadlegs, all of these are factors in determining the appropriate number of TMLs for a particular circuit." Tr. Vol. II, 378.

         So, Eggleston instructed that the CML Excel spreadsheet calculation form that Eggleston had developed be used to decide the appropriate placement and number of CMLs. There was no training on use of the form. Thereafter, the workflow for the catchup project began by segregating piping into manageable circuits, then moved to creating an isometric drawing of each circuit, locating CMLs, taking UT readings, analyzing the UT readings and expanding the scope of the inspections if so indicated by those readings, and preparing an inspection report for the circuit. Eggleston required the use of his CML calculation form by everyone on the project, including UT techs and inspectors, such as Fitzpatrick and Kiss. Interestingly, during trial Eggleston made mistakes himself when he discussed how calculations were to be made when trying to demonstrate proper use of this CML calculation form. Subsequent to the fire at issue in this case, Eggleston began to hold specific training classes for inspectors to make sure that they understood how Eggleston wanted the form to be used. Eggleston said the calculation form was based on API 570 factors, including classification and material codes, total length, number of fittings, deadlegs and corrosion rates. PI. Ex. 138. The CMLs GP Amerispect had previously placed on a circuit were to be entered on that form and retained so as to reflect corrosion between 2002 and 2011. If required, additional CMLs would provide baseline readings for future inspections.

         API 570 5.6.1 states:

CMLs are specific areas along the piping circuit where inspections are to be made. The nature of the CML varies according to its location in the piping system. The selection of CMLs shall consider the potential for localized corrosion and service-specific corrosion as described in API 574 and API 571. Examples of different types of CMLs include locations for thickness measurement, locations for stress cracking examinations, locations for CUI^[4] and locations for high temperature hydrogen attack examinations.

         Joint Ex. 4.

         To accomplish this part of the project, at trial Eggleston said he wanted the form to be filled out by an API 570 certified inspector, which he testified required judgment calls and input of the inspector. In practice, the form was used by everyone on the project with information obtained during external visual inspection, new UT ...