First-Hand:One Engineer's Oilfield Journey from Wooden Derricks, Cable Tools, and Jack Plants on Land to Offshore Subsea Producing Methods

Submitted by John Kleinhans

1967 - 1970

I joined the U.S. Shell Oil Company after graduation from the University of Washington with a B.S. in Civil Engineering in April, 1967. My first Mechanical Engineering Trainee assignment with Shell was located in Bakersfield, California. I attended Shell’s Basic Training School, located in Houston in 1968, which was followed by my attending the Facilities Training School in 1969, also located in Houston. My specific initial assignment to the Bakersfield E&P office was for the Midway Sunset (MWSS) field with responsibility for helping to resolve the many lease production handling challenges that were impeding production from the recently started thermal recovery methods. I had many field tours during the first few years to become familiar with similar types of heavy oil fields that were undergoing the transition from primary production recovery to the tertiary thermal production methods. In addition to MWSS, these fields included Kern River, Kern Front, Coalinga and others.

I also toured the Ten Section field, which was discovered by Shell in 1934. This particular oilfield discovery represented an important technical breakthrough because it was the first time that an oilfield had been discovered when there was no surface evidence of the underlying oil accumulation. The tour came about because it was located on the highway that I was using for my frequent commuting trips between Bakersfield and the MWSS field. The Ten Section field was far along in its depletion stages, but still producing at a relatively low rate of light oil by the time of my visit. Between my Facilities Training, which was mostly about conventional oilfield methods, this Ten Section visit made it very clear to me just how much difference there was between the facilities that were used for producing light oil, and those that had been installed at MWSS and were being used to produce the increasing rates of heavy oil at MWSS, which was due the response to thermal stimulation methods.

Since I was a “blank page” about the Oil Industry when I joined Shell, I was learning about new matters at a rather incredible pace. During the Basic Training School, I was encouraged to join SPE as an additional way to learn and share about all technology, including this emerging and new thermal recovery technology. I was also meeting a large number of Shell personnel who ranged from exploration, production, drilling, operations and those who were involved at various Shell R&D locations. Much of the research work was directed to improving not just the new upstream thermal recovery methods for heavy oil, but also Transportation and Refining methods. In 1968 and when I was reviewing background information about MWSS, the reasons for the thermal recovery of heavy oil became clear to me. The field had been discovered in 1894, but by 1968, only 2% of the original oil in place had been produced, which also coincided with the time that MWSS field oil and the oil recovery to date was in excess of a billion barrels of oil. Although Shell was only operating several MWSS field leases, the prospect of these new thermal recovery methods to recovery of 20% or more of the original oil in place was enlightening. It also made clear why so many thermal recovery efforts were taking place by many other operators in the MWSS field.

Keeping this personal history brief, I had identified three serious constraints to production that already existed at Shell’s Northern MWSS leases, or collectively referred to as the Petrolia area, or that would become issues in the near future. The first constraint was that we could not consistently dehydrate the heavy oil to meet acceptable shipping specifications. The reasons for this included a combination of very tight emulsion characteristics and the very close together densities of the produced oil and water. The second constraint was that even though very large sumps were being used at each lease to manage the routine dehydration upsets, it was even more troubling that the increasing production rates sometimes exceeded even the normal handling oil rates. Collectively, oil accumulations in the sumps, whose primary function was supposed to be for produced water disposal, was steadily increasing to the extent that even further sump capacity enlargements were on the near horizon. This situation concerned me a lot, not just because of the environmental aspects, but because unless we could reverse this situation, the increasing thermal oil production rates could not be sustained in a meaningful way. Third, I had become familiar with the many complexities represented by oil shipment by truck. Although the leases were located close to one another, scheduling and shipping the large volumes of oil without disrupting producing operations in Northern part of MWSS field was barely keeping up, and sometimes not and this resulted in either oil production going to the sumps or causing production curtailment. The heavy oil in this area was even heavier and more challenging to handle than the oil that was located in the central and Southern parts of the field where Shell was also operating producing leases, but these leases were still being operated in the primary producing mode.

My initial specific efforts to try to help improve the situation in the Northern MWSS involved modifying the heater treaters that had been previously installed upstream of the primary production conventional wash tanks at each of the leases. The reason for modifying these heater treaters was that although not fully successful, the previous conversion of one of the heater treaters to be an electrostatic precipitator by the vessel manufacturer had resulted in somewhat better consistency for the dehydration duty. While doing the due diligence about the vessels’ designs and flow paths, I was also trying to understand why I had been observing an unusually wide temperature control dead band for the fluid and frequent burner on and off cycles as the fluid passed through a direct fired vessel. This temperature swing was significant enough that it could influence the vessels’ dehydration efficiency. I found that although the external thermostat controls were functioning properly, there was a vessel internal design flaw that was related to placement of the thermostat in the flowing fluid in the vessel. With design revision and placement of the thermostat in a better position inside the vessel, temperature swings were essentially eliminated and frequency of the burner on-off cycles was significantly reduced. With the conversion of all of the lease heater treaters to electrostatic precipitators, I had learned a lot about the subject of heavy oil dehydration, but it was still clear to me that technology improvements to date were not enough and still lagging the increasing heavy oil production rates.

Without knowing it at the time, the direct fired vessel frequent cycling issue that I resolved at MWSS was also occurring elsewhere, specifically at Shell’s Cook Inlet, Alaska operations. During an engineering information sharing session in Bakersfield, it was pointed out to the participants that the direct fired vessels in Alaska were experiencing frequent cracking failures in the direct fired burner’s Inconel liners. To date, no obvious explanation had been determined, but it was believed that the most likely causes were due to flaws in the Inconel liner material or potential Inconel welding procedure inadequacies. Given the much cooler ambient temperatures in Alaska, I asked if they had considered the possibility that a frequent burner on-off condition could be causing the early fatigue cracking problem and described the temperature control design flaw that we had identified in the same type of direct fired equipment at MWSS, even though no similar liner failures had occurred at MWSS. This frequent burner cycling possibility was subsequently investigated at Cook Inlet and the same type of temperature control design flaw was identified and corrected. After which there were no further liner failures of this type with the Cook Inlet direct fired equipment. Regardless, due diligence was done for the MWSS direct fired burners because the vessel temperatures were being kept at much higher levels than anywhere else, and determined that the probability of burner liner failure due to fatigue cracking was very low and within normal engineering design practice criteria.

Unfortunately, the reasons for the inconsistent MWSS dehydration results were still not yet clear. This lack of clarity led to my structuring a field pilot test using just one of the converted electrostatic precipitators, about which I was fully familiar due the conversion work that I had done, including complete verification of all manufacturer’s recommendations regarding the vessel internals functions, from the vessel inlet to the outlet. I discussed the potential use of a statistical experimental design technique that I had come across while investigating the dehydration issues with one of the E&P Research folks in Houston while I was there for the Training Program. I received considerable support for using this approach because using it could reduce the number of actual tests that would be required in the field from several thousand point-by-point changes in the independent dehydration variables to requiring only about thirty of these point-by-point changes to do the field pilot testing. With the necessary Management approvals, pilot testing and the analyses of results accomplished the objectives, which were to have a quantitative prediction method for % Basic Sediment and Water (B.S.&W.) that could be used with reasonable confidence in the predicted results.

One of these independent variables was the concentration of Ten Section light oil that was blended upstream of the pilot dehydration system with the heavy oil. Light oil blending, even at low concentrations, exceeded expectations during this field testing. Just based on normal analysis for density difference improvement between oil and water, some improvement in dehydration efficiency was expected, but actual results indicated additional dehydration efficiency benefit was being observed. This additional benefit was due to two additional items. The first was that the increased resistivity of the blended oil improved the electrostatic grid performance in the final dehydration section of the vessel. The second was that the blended oil reduced the fluid viscosity and this improved dehydration throughout the vessel. Figure 1 is a photograph of the type of electrostatic precipitator that was used during the field testing. Most importantly, we now had the type of information that was needed to begin meaningful evaluation of methods to consider for overcoming the production handling and dehydration issues that were the norm for the Northern MWSS producing leases. Since I was no longer seen as a ME Trainee, but a ME Facilities Engineer, I was able to begin discussing an idea that I had formulated for improved production handling for the Shell operated leases in this area of the MWSS field. Basically, the concept involved custody transfer of the emulsified oil from each of the leases to a consolidation point, shipping the emulsified oil through a new 26 mile pipeline to the Ten Section field, and installing a Central Dehydration Facility at Ten Section. The heavy oil emulsion would then be blended with light Ten Section oil, and then sent to a bank of electrostatic precipitators for dehydration to pipeline specifications. The oil would be shipped on to Bakersfield through this existing, but under-utilized pipeline. The Central Facility would include a water treating plant and exiting temporarily abandoned wells at Ten Section would be converted to water injection wells for underground water disposal. Applying a concept like this would require obtaining the support of not only Shell E&P and Shell Pipeline, and their respective Operations Groups, but the USGS, the Government Agency that was responsible for approving planned field development activities at that time.

I was tasked with investigating the potential interest from those whose approval would be necessary for the concept. I prepared the technical case for doing a system like this and reviewed it accordingly. Some important feedback suggestions were received and they were incorporated in to the concept as it was maturing. The potential cost benefits, which would come primarily through significant efficiency improvements to the existing problematic lease production handling and hot oil trucking methods, were left out of the early concept discussion. That would await actual project formulation matters if the concept were matured enough for requesting an actual Project Approval.

Concurrences with the concept occurred quickly and with agreement by all interested parties, including the USGS, it was time to define actual project details in a way that it could be raised to E&P and Pipeline Managements for further consideration and approvals. I was tasked with defining the E&P portions at MWSS and Ten Section, and Robert Ewing from Shell Pipeline Projects and Veet Kruka from Shell Pipeline Research, were tasked with defining the MWSS to Ten Section pipeline portions. Results, including definition of the costs, schedules, which included definition of contractors required and resource leveling, risks, along with identification of key permitting and long delivery items were compiled in to a joint E&P and Pipeline Project format and presented to the respective Managements. Following this, we were directed to prepare associated MWSS production information and the anticipated economic results, but to structure the project in a way that the MWSS production shut-in could be minimized, preferably eliminated, during execution of the project. This was done, including the decision that had been taken to use an emulsion core flow pipeline rather than a heated pipeline. The core flow pipeline approach offered significant cost benefit over a larger diameter conventional heated pipeline. The relatively high cost of a conventional pipeline was because about every five miles along the pipeline, a heavy oil emulsion heating and pumping station would be necessary. However, since the core flow pipeline would involve use of new technology, associated risks would be higher. Economic projections for the use of either of the pipeline methods were prepared accordingly. Also, a the use of a phased approach for modifying the MWSS and Ten Section Central Facility were incorporated and results presented to Management for further consideration. And by this time, Shell had received formal approval for applying the project from the USGS.

Shell Management then approved what had become named the “Petrolia to Ten Section Project”, or by today’s wording, the project was sanctioned. Project teams were formed and necessary project steps were initiated. In about two years’ time, this parallel E&P and Pipeline project was sanctioned and executed. At the time, this was the largest single project activity that was being done in Shell’s Western region. It was accomplished with minimal interruption to the MWSS production through the close coordination of Shell E&P and Pipeline Operations throughout. When fully up and running, the thermally enhanced oil production handling bottlenecks at MWSS were removed along with the need for using exceptionally large sumps, and the complex requirement for around the clock coordination of hot oil trucks eliminated. Figure 2 provides a photograph of representative MWSS adjacent lease wet oil shipping facilities and Figure 3 provides a photograph of the built-out Ten Section Central Dehydration Facility and associated Produced Water Treating Facility. I need to mention that because this was a very early activity that was just part of the evolving thermal recovery methods, that many changes from results of these early activities, in both methods and technology, would be expected over time.

After the Petrolia to Ten Section Project, my responsibilities were expanded somewhat to help with the design, build, installation and startup of numerous relatively small Shell operated thermal recovery projects that were to be located on various heavy oil properties within the more Central and Southerly part of the MWSS field. Also, another fairly large pilot project was being formulated for application within the recently consolidated Northern part of the field. It was to be directed by the Reservoir Group because it consisted of using a new Shell Reservoir R&D pilot concept called the Pressure Augmented Dip Soak (PADS) technique. It involved injecting steam above the thick oil column rather than using the more common approach where injected steam was placed near the bottom of the well. I was tasked to lead the surface facilities portion of this test. In summary, the plan was to heat up the oil column from above using steam, and allow gravity drainage to flow the resulting hot fluid, both condensed steam and heated heavy oil, into the surrounding 2-1/2 acre well spacing wellbores. Ultimate success of this activity would potentially slow the use of the steam “huff-and-puff” method that was typical for stimulating the individual wells one at a time. Subsequent to this pilot, various forms of steam injection, and even closer well spacing, became a more prevalent recovery method for heavy oil because the ultimate recovery efficiency was potentially much higher than using the previous methods.

During this same time period, I was moving upward on a steep, but slow learning curve about the topic of heat as it applied to these types of heavy oil thermal production activities. To help accelerate this learning, I was designated to be a Shell representative to the Heat Transfer Research Institute (HTRI). This HTRI involvement did help me in this regard, including expanding my understanding of heat and its many useful attributes. HTRI activities, beyond those of R&D about heat, included a segment that was doing work applicable to the Known Geothermal Resource Areas (KGRA’s). At that time, Yellowstone Park was the most recognizable KGRA in the U.S. Also, there was one actual KGRA field that was located in Northern California (Geysers) where low pressure geothermal reservoir steam was being used to generate electricity. Also, there another geothermal field operating across the Southern California border in Mexico (Cerro Prieto). I participated with a Shell team that visited these geothermal fields and my responsibility was to identify the types of surface facilities that were being used at these locations for possible future reference. Following an assessment of the potential commercial application of geothermal energy, my personal opinion was that Shell should continue to improve the efficiency for the heavy oil thermal recovery activities before getting too involved with any KGRA power generation activities. This assessment was provided based on simple quantification of the costs of doing these types field developments and their expected types of end values.

Through the MWSS field observations that I was making, particularly around the design methodology that was being used for the heated and insulated wash tanks, end results were not consistent in providing expected results. Since I was already pretty busy performing my own assigned duties of improving production handling efficiency, I structured a heated tank investigation project that could be done by a college intern during Shell’s summer intern hiring program. This project was selected by the Intern Committee, and a summer intern did a very good job of bounding the nature of the problem and successfully executing it under my guidance. Results clearly identified why the normal design methodology that was being used for tanks of this type were giving non-conservative results. The information was documented and incorporated in to Shell’s heated tank design standard that was being used by both Shell E&P and Shell Pipeline. Collectively, these early activities taught me the importance of maintaining clear communications across organization boundaries, ensuring clear design basis documents, use of appropriate Codes, Specifications, and Practices, developing clear contracts, establishing means to meet safety needs, and the importance of providing early and clear communication of risks and hazards and potential ways to eliminate or minimize them. Learnings that I gained from the in-house personnel and through external communications with the involved contractors’ was imperative to a project execution that is to be delivered as expected. Doing so safely, from the standpoints of people, equipment, reservoir and the environment, which was a Shell internal expectation for all activities, and it had become a personal watchword for my activities. I was also gaining respect for the importance of developing meaningful economic projections for a project’s payout time, profitability, rate of return, and other wider, but directly related indexes that were also important to a given endeavor. Although these business related aspects were of critical importance, my personal interests remained primarily with understanding and applying appropriate technology that applies to conceptualizing and executing a project.

The Santa Barbara oil spill had occurred during early 1969. Consequences were having a significant impact across the State of California for all of the Oil Industry, both offshore and on land. From a personal standpoint, this became my first introduction to the reality of how severe the public perceptions towards the Oil Industry was, and how a problem in one area could cause difficulties for all Oil Industry Companies, and individuals who were employed within them. From my limited perspective, all implications were not yet clear, but Shell consolidated the E&P Division Offices that were located in Ventura and Bakersfield to Los Angeles, along with making significant personnel re-assignments and reductions. With the Bakersfield E&P office closure, I was transferred to the Los Angeles office from which I finished up the remaining MWSS field thermal projects that were still my responsibility. Then, I began working on activities that were located in the LA Basin.

1970 – 1972

Shell Management brought a challenging situation for an oilfield that was located in the LA Basin to my attention. The situation involved an aging oil field that was discovered by Shell in the early 1920’s. The photo in Figure 4 provides an impression of how the Signal Hill Oilfield would have appeared during the early field development. The closely spaced wooden derricks were used initially for the cable-tool well drilling, followed by well completion and subsequent well work. As time and technology progressed, all of the wooden derricks were removed and remaining wells were equipped with metal derricks by the mid-fifties. Signal Hill was named this because it had served mariners by a beacon light for a very long time, with the beacon being visible from the Pacific Ocean and Long Beach Harbor because it was the closest and most prominent land geologic feature in this area of the LA Basin. Shortly before the field was discovered, many of the land surface areas in the vicinity had been divided up in to town lot size parcels of property. City expansions and population growth in this area had continued as it was doing throughout the LA Basin.

Although Shell and other Firms had established significant positions in the area due to the oil discovery, some with both surface and subsurface mineral rights, there remained many individual owners of just surface rights to one or more of the town lot size parcels. Well spacing in the early days was based solely on right of capture considerations. And this is why the early well spacing was so close to one another. By the mid-fifties, well and reservoir producing efficiencies had begun to prevail along with removal of all wooden derricks and abandonment of many of the very early wells. Also, the field had been divided into three separate Units, and Shell was the Central Unit Operator, with Arco and Texaco Operators for the other two Units that were adjacent to each side of the overall field area. The Central Unit lies entirely within the boundaries of the City of Signal Hill, and it is in turn completely located within the boundaries of the City of Long Beach.

Shell’s efforts to further modernize the Signal Hill Central Unit had been in the evaluation stages for a very long time. But complications due to the need to obtain agreement from the many mineral interest owners and the other adjacent Unit Operators were significant. And there were City, County, State and other Regulatory Considerations that required approvals before anything new could actually be done. Nor were the adjacent Unit Operators very interested due to their own very large numbers of mineral interest owners. A further complication was the actual subsurface locations of the many wells that remained. This was because early well drilling was done without benefit of downhole well surveying technology, along with uncertainty about how much oil had really been produced from the multiple reservoir zones. Approvals for actually doing the downhole well surveys when this technology became available was finally done, but only after all mineral interest owners had agreed not to sue one another for damages when this type of information would finally become available. Regardless, the continuing rapid population growth and burgeoning environmental aesthetic expectations were causing many pressures for making changes to the field operations, especially since the surface areas held significant promise for real estate and commercial development possibilities.

I reviewed the preceding work that had been done during the most recent years. It was based on the possibility of Shell initiating a waterflood for the Central Unit portion of the field, including assessments for the potential risks about the way that the many subsurface reservoir zones might respond. The subsurface risks existed primarily because of the unpredictability of early day well placements and the withdrawals of uncertain volumes of oil from the many stacked producing zones. Regardless, sufficient work had been done to verify that both a source of sufficient power and water could be obtained if a project like this were to move forward. Based on the recent learning gained from the MWSS to Ten Section Project, I had some experience with making existing field modifications and sustaining existing production in the process. I prepared a potential field renovation concept for the field development such that a two pressure water injection system could be feasible, but more importantly, the concept included consolidating the existing surface facilities to just three locations within the Central Unit. These would include a Central Production Facility and two other remote drilling and production gathering locations. The significance of this was that all production or water injection wells would be handled entirely through the Central Facility and reduce the surface area footprint that would be needed for producing activities. I included a preliminary budget and schedule, with the schedule indicating that with the proper project organization, including the use of engineering and construction firms that already had experience with doing oilfield development projects within the LA Basin. Preliminary schedule information indicated that it would be feasible to do the Central Unit project in about 18 months. Due to the number of permits and number of mineral interest owners, the project team would also need to include full time a full time representative from Shell’s Land Department. This would be a key project role because it would help ensure timely communications, coordinate town hall sessions with interested parties, and coordinate the acquisition of the many permits that a project like this would require. To maintain the schedule this, the project delivery teams’ time and resources could not be diverted to the many permitting activities that would be necessary throughout project execution.

This information was then presented to Shell Management. One aspect that was appealing about the proposed approach was that it allowed for winning over as many interested parties to the field modernization idea very early on and before any significant project monetary commitments would be made. This would be accomplished by making it clear that it would be in everyone’s shared best interest to go forward with a project like this because ultimate results could benefit essentially everyone, and that any anticipated production enhancements were primarily a side benefit of the undertaking. If it were done as proposed, the City of Signal Hill, and the property surface owners would gain a lot of new, prime real estate opportunities. However, I made it clear to Management that doing something like this would carry a high risk of getting stopped at some unpredictable point in the project execution due to the number of project delivery complexities, unusually large number of mineral interest holders, and the very large number of permits that would be necessary.

Following a relatively short soak period, Shell Management assigned me the opportunity as project lead. I helped form a project execution team, including both the in-house and the external resources that would be required. However, Management also stipulated that the project needed to be structured so that it could be executed in a “restore to previous conditions capability” until the project was essentially finished. This aspect added a little more challenge to the project planning due to the number of what-ifs, but because of the types of risks involved, it was certainly a sound approach to use.

Project execution was started on numerous fronts at the same time and delivery targets were closely monitored throughout the project. The change-overs were delivered to Operations during the 18 month project as planned. Figure 5 provides a photograph of the Central Site. Although the project was completed on time, it came in a little over the original approved budget. The cost overrun was primarily caused by the need to abandon many very old, unused, and undocumented buried lines and other undocumented obstructions that were encountered as the earthwork for the new sites, buried lines and utilities work was in progress.

Although this project did not involve any specific technical firsts, it did represent a number of firsts in the way that Shell upstream executed typical field development projects. Normally, development of all drawings and specifications were done using internal resources. In this case, there was going to be so much design, drafting, specifications and documenting work that Shell’s existing in-house personnel would not be able to sustain the schedule for a project like this. Thus, a contract consulting engineering firm was engaged at the outset and their work was done using Shell’s in-house specifications when applicable. The concept for doing the Central Facility approach and using two remote producing and drilling sites was relatively straight forward, but provision of all Signal Hill Central Unit power and controls from just this one location represented new challenges to traditional downstream lease operating methods. I coordinated sessions with Shell Downstream about Refinery and Chemical control methods, and met with the Shell Central Upstream Controls Group, where many new controls methods for new producing fields were being evaluated for potential application of the rapidly evolving controls technology advances. Out of these sessions, agreement was reached on the use of one Control Panel that would be placed in the Central Facility control room. It would be used to monitor and control all production and water injection functions, including first-out alarm monitoring in the event of a system shutdown.

Although the technology for using more sophisticated controls methods was evolving rapidly at that time, by staying with the use of ladder diagrams, relays and hard-wiring methods, the control system was within existing capabilities for the normal field electricians and their training. This project just consolidated a lot more of these controls functions at one location than normal. As a further aid, the field layout was mimicked in schematic form and the controls monitoring was displayed on the master control panel.

One technical matter that I did encounter was related to the water injection system design and the line sizing and pressure predictions that had been done using in-house main frame computer software. Although it was relatively new software, it had been available for some time and it was being used throughout the Company because it was very fast and easy to use. And in most cases to date, results had been found to be completely satisfactory. However, due to the many ups and downs that would be necessary to inject water routed from the Central Site to the many different well sites and elevations, I decided that I should do a bit of due diligence on the computer predicted results. Based on the hand calculated results and those predicted by computer were substantially different. I contacted the Computer Group in Houston that supported this software and discussed my concern about this observation with them. The software was reviewed, and it was discovered that during a previous software revision, an inadvertent elevation sign reversal had occurred. The necessary software correction was made, and similar results were obtained. The field water injection system was re-analyzed with the updated software, due diligence done again, and close agreement in results observed, and the rather large quantity of water injection pipe order was placed. After the sign reversal situation was corrected, the Computer Group revisited its previous application use and determined that the problem had not been recognized previously because those activities were performed when field elevation conditions were nearly the same.

Another technical area involved the air permit, which required the use of a totally closed system design for the Central Facility. Design of production facilities without use of the more common flare system, which accommodated both vented gas during emergency conditions and the small gas rates that were vented from atmospheric tanks, created equipment performance issues for the project delivery. Solution for emergency conditions was straight forward via the control system. However, maintaining very low gas pressure on the low pressure tanks by use of appropriate gas compression equipment was found to be problematic. Summarizing, considerable field testing was required before a reliable low pressure compression system could be provided. Although there were many potential equipment types available that could potentially meet the specifications for duty like this, many types were ultimately tried. They would actually work for a few hours or days before failing. Primary reasons for the rapid failures included the combination of a high temperature increase across the compressor and inadequate lubrication. Ultimately, this early compressor failure situation was resolved by a combination of using a forced cooling system and a very recently developed synthetic lubricant that was specifically designed for use with low pressure compression equipment.

From the project execution standpoint, the work responsibilities and interfaces between the major construction contractors who would need to be engaged to execute the project had to be in much more detail than normal. Since multiple contractors would be simultaneously be at the same work fronts at times, early contractor involvement and buy-in, including incorporation of their suggestions, was important to achieving trouble-free project execution. Also, a key part of the contractor selection process was to ensure that the contractors’ track record with avoiding union difficulties for this type of work had to be good. And the number of craft unions who would be involved was large. Once the actual work was started, a work stoppage due to a union problem or contractor dispute almost certainly would have triggered the “return to original condition” requirement and the end of the project. With work permits in place, all contractors were selected and the project work was started at all feasible fronts throughout the Central Unit. After the Project got started, it was not necessary to look back.

One of the interesting permit requirements that the project was committed to do, beyond color-coordinating buildings, above ground level equipment, adobe brick fencing and doing road work to City specifications, and the City approved Central North and South site landscaping, was to demonstrate that the existing local ambient noise level was not exceeded by the end results of the project. I was pretty sure that this could be done by putting the two relatively large multi-stage centrifugal water flood pumps inside of the Central Unit main building, which was to serve as the control center and Central Site switchgear area, office space for the lease operators running the Central and Remote site equipment, and space for the laboratory testing equipment. The reason for requiring two water injection pumps was that one was a high pressure and low volume unit requiring 2,250 HP. It was to be used for injecting water into the deeper reservoir zones. The second pump was a lower pressure and higher volume unit requiring 3,000 HP. It was to be used for injecting water into the shallower reservoir zones. This Central Unit building was fully enclosed and placed well within the boundaries of the Central Site. Selective sound-proofing was done inside the building. The multistage pumps were manufactured on the West Coast, the motors manufactured on the East Coast, and packaged together by the pump manufacturer. The reason that the 4,160 V motors were manufactured on the East Coast was that the motors and their noise abatement specifications could only be met at that time by the East Coast manufacturer. This particular manufacturer’s primary business was to supply low noise level motors to the U.S. Navy. Since I was not too sure just how we could do this before and after ambient noise level demonstration to meet the permit expectations, I decided to contract an acoustics firm with proven experience of doing acoustics noise level studies for other large cities that also had established ambient noise level criteria. The Firm selected to do the project ambient noise level work was also located on the East Coast. They did an initial on-site baseline acoustics investigation before the project execution work started by using specific acoustic monitoring points that were located within the Signal Hill area. Acoustic measurements were again taken at these same points after project start-up and the before and after acoustic results compared. Based on these results, it was conclusively demonstrated that the pre-project ambient noise levels were not exceeded by the Signal Hill Central Unit Project.

During the project period, I was also requested to perform two actual Civil Engineering tasks for Shell. The first task came immediately after a major earthquake had hit the LA area. The five stories Shell building, which had been designed and built during the 1920’s, had sustained considerable internal damage due to the earthquake. Shell Management tasked me with doing a structural review of this reinforced concrete building and report back immediately about whether it was still safe for occupancy and continued use. Review of available drawings and inspection of the building structure showed that it was amply safe from a structural standpoint, but that this same rigid structure design would respond similarly to any other large earthquakes that might occur and create considerable internal damages like those that had occurred during this earthquake. Fortunately, no one had been injured because the primary earthquake had occurred early in the morning and before the building was occupied. If it had occurred while the building was occupied, injuries would have been a high probability due to large numbers of tall bookshelves and their contents that were knocked to the floor and the large quantities of architectural marble veneer that was dislodged from walls throughout the building. Results of this review were provided to Management and the building was re-occupied for initial clean-up and subsequent repairs that were done before the building was put back into normal use.

The second task came when I was requested to do the foundation design for a drilling rig that was going to be used near a mountain top that was located within the Taylor oil field. Since this was to be an exceptionally deep test and conducted by the Drilling Department, it would require the use of an unusually large drilling rig, for which there was only one drilling rig in the U.S. that was capable of drilling the well. This particular drilling rig was under contract to the U.S. Government Energy Department, but available for a time between its planned uses for drilling very large diameter holes in the remote desert areas where the resulting large holes were then used to detonate nuclear explosion tests. Shell had contracted to use this drilling rig long enough to drill the deep exploration test. Since conditions and drilling operations on the mountain were much different from those for which the existing rig foundations had been designed, I was requested to design a drilling rig foundation that would meet the deep test requirements. The resulting rig reinforced concrete foundation design was a success, but the deep well test results were not. The contracted drilling rig was demobilized back to the desert for its intended use. Since removal of the rig foundation was not required as part of the drilling permit, I’m confident that it still remains in place at the drill site.

Conclusion of the Signal Hill Project coincided with closure of the Los Angeles Western Region office, and Shell personnel levels were again relocated or reduced. In my case, it was relocation to Houston, with assignment to the new Western Region office. This included the reality that we would now be covering a much larger geographical area because the closure of additional Shell Division offices was necessary. Also, I had become a Senior Mechanical Engineer along with the added responsibilities that this required.

1974 – 1975

My first assignment in Houston was to investigate some production handling issues that were occurring in the Shell operated portion of the Cedar Creek Anticline field, which is located in the far Eastern area of Montana. During this visit to the field, it did not take very long to identify the reason for the producing issues. The tankage volume of a single production gathering point was quite small. The multiple and remote producing sources and their varying rates that entered it had changed considerably over time. The collective individual producing sources were severely exceeding capacity of the single gathering point at unpredictable, but short periods of time. This was causing overflow of the excess fluid from the gathering point facility into the overflow sump and unacceptable from an environmental standpoint because in turn, the sump would overflow into a natural waterway. After defining the statistics of the configuration, it was clear that three potential solutions to the problem could be considered. One was to impose considerably more control over the multiple producing sites, which were located at very remote sites and a long distance away. Uses of microwave communications and controls were feasible, but it would require a long study period to identify the location and number of new towers that would be necessary. Also, there was the possibility that controlling production at the many remote sites could be quite challenging and expensive. A second method would be to increase the size of overflow receiving sump, but this was a challenge because this approach had already been used over a long period of time and nearly all of the available ground space to do more of this was impractical and environmentally risky. The third method, and it was the one suggested, was to just increase the size of the tank at the receiving point. It was shown that a relatively modest increase in the receiving point equipment size would essentially eliminate the potential for any continued overflow to the sump arrangement to a statistically remote possibility. Most importantly, it was an inexpensive and fast fix that would last throughout the remaining life of the field. The option to increase the equipment size was selected and executed by others. Expected resolution of the single point gathering system overflow issues were eliminated.

Following this, I was assigned to a primary field development activity that was in the early development activity stages. This Central Utah activity was based on results of a many year Exploration land play that culminated in the Uinta Basin. A successful exploratory discovery well was drilled in 1970 and a new oilfield, which was named Altamont field after a nearby City, had been discovered. The rights to retain many of the lease mineral interests were going to expire fairly soon because the discovery well was not drilled until very late in the play assessment. In fact, the exploratory well drilling was viewed as having much higher probability of failure than success when it was actually drilled. With the success, protecting the lease mineral rights were more a priority during early field development planning than other more traditional drivers. For this reason, it was not feasible to do the step-out drilling to prove-up field boundaries. Normally, one section at a time and emanating outward from the discovery well would be drilled until field boundaries were confirmed. Doing it this way for this situation would have put large numbers of Company held mineral leases at risk due to the long drilling times. Thus, concerns about the extent of the field boundaries became secondary and field development planning started, as well as continued prioritized prove-up drilling, Shell personnel were brought in from land locations across the country and from offshore Gulf of Mexico, and execution activities began moving forward on the most probable subsurface assessment that the field development would ultimately cover about five miles wide and 25 miles long.

The Altamont field was characterized as a fractured carbonate reservoir with well depths of about 13,000 feet. Drilling was a challenge due to the many thief zones that were occurring along the way to the reservoir, with an unusually large and persistent thief zone that was located just above the reservoir. During the development drilling, four well control issues occurred due to this thief zone. It was clear from the outset that production from the reservoir was coming primarily from the fracture systems because other than occasional very thin sand zones, the reservoir rock matrix measured in the pico-Darcy range. This situation was challenging to the Reservoir and Production Engineering personnel because there had not been opportunity for developing history matching. The wells would flow after they were completed, but most of the time a well would stop flowing and need to be equipped with artificial lift to keep the well producing. Also, rapid paraffin build-up in the well tubing was a continuous problem that had to be addressed.

Another part of the challenge of this field development opportunity was that the terrain was not only quite high, but it was located mostly in quite rugged surface area conditions and with nil in-place access. Most of the non-rugged terrain was devoted to subsistence farming. Thus, some of the area was located on privately owned land, some of which had sold mineral rights, some of which had not sold mineral rights and some of which was located on Indian Reservation and for which mineral rights had been obtained. Winters were long and very cold, summers were short, and the area was quite arid. When it did rain, gully and dirt road washing was commonplace. Then, there was the crude oil challenge itself. Crude oil was very light at about 40 degrees API and with a GOR that was above 1,000. But the oil contained about 20% wax content, sometimes a little more or less. At room temperature, the crude was essentially a semi-solid and very similar to shoe wax. To prevent untenable blockage of surface equipment and lines, everything that was to be located above the frost line, which was at about 5 feet below ground level, and above ground lines needed to be insulated and/or heat traced. As previously mentioned, drilling was being carried out with each section of land defined by the State of Utah as a drilling unit. The number of drilling rigs that were working was being ramped up as quickly as possible, limited only by availability of people, rigs, permitting and the materials logistics that were associated with this very remote area. At the peak of drilling activities, a total of 14 drilling rigs were running.

Development teams were formed to execute the field development, which was based on production facilities located at each drill site, a central gas plant, a South gas gathering compression facility, and a North gas gathering compression facility. Rights-of-way acquisitions for the major facilities components had started as early as feasible and this was not a simple part of the field development planning activities. Shell Pipeline executed the initial gas gathering pipelines connecting the gathering compressor stations to the central gas plant and the export pipeline from the gas plant to an existing gas pipeline tie-in point. Also, Pipeline was also responsible for trucking the oil from each producing site and the gas liquids that were extracted from the central gas plant. All other field development activities were to be handled by Shell E&P, including construction of the gas gathering compressor facilities and the central gas plant as well as the typical individual lease production facilities at each drill site. These included the flowline from the well to a gas-oil-water separation vessel, power and utilities, two stock tanks, and the separated wet gas, metering and gas tie-in flowline to the nearest point on the gas gathering system. As matters continued to develop, the addition of non-integral gas compression equipment was required at some locations.

My specific area of responsibility was to provide the gas tie-in flowlines that were to be connected from the individual drill site producing locations to the gas gathering systems. This job included considerable coordination, route selection, surveying, rights of way acquisition, gas contracts with the gas plant for non-Shell operated leases. Line designs, sizing, procurement of materials, contracts for construction contracts to install, test and start-up each gas tie-in was included within my responsibility. Also, some unexpected wet gas handling issues that were encountered in the gas gathering systems from the compressor stations to the central gas plant became part of my responsibility to resolve.

In summary, the original plan was to operate the three-phase, heated separators located at each drill center producing facility at a pressure that was high enough to allow metering the separated gas and flowing the gas on through the gas tie-in line to the gas gathering system. However, the separator operating temperature that was required to keep the oil above the wax appearance temperature as it moved through the system resulted in a very wet gas entering the gas handling system. Thus, as the wet gas moved along the buried tie-in flowline, the gas would cool down and significant quantities of light condensate would begin to drop out along the line. In many cases, the separator pressure was not sufficient to overcome the gas gathering line back pressure that was imposed on the production facilities. In turn, this resulted in venting produced gas to the facility flare pit so that oil production could continue. This condition of significant liquid drop out from the wet gas also extended on into some portions of the gas gathering system, which was made worse because these gas gathering lines were significantly over sized for these early gas rates. Thus, gas liquid sweeping velocity would continue to be an issue until the field was fully developed and the gas gathering system rates were much higher. Given the extensive hilly terrain features that were involved, resolving the excessive gas back-pressures became a serious issue because the State of Utah had filed notice of a produced gas no flare order. Timing for this no flare order was imminent. I became closely familiar with the multiphase in-house software that was routinely used for the sizing of gas lines like these. I also became familiar with the fact that the existing software was not adequate for predicting pressures for the types of hilly terrain conditions that existed at Altamont, especially when used with the volatile liquids. To help improve the gas gathering system predictions, I involved Shell Research personnel, and a field trial was structured to identify the prediction problem areas and ways to overcome them. Suitable in-service line sections were rigorously surveyed for both distance and elevation and monitoring points for continuous recording of temperature and pressure were installed along the lines, as well at the gas gathering tie-in point. Also, continuous metering and sampling was done at the start of the gas tie-in line to ensure true knowledge about the wet gas properties throughout planned test periods. Results of this pilot test and analyses of results comparisons provided a clear picture of the problems that existed with predictions, and more importantly, methods that could be used to improve the prediction results. As well as helping to resolve the prediction issues in the Altamont field, these collective results became a training module at Shell Development for training purposes and it was in use for many years.

During this assignment, I developed a case for gas flaring from selected oil-tie-in prospects that was focused on the technology of gas tie-in requirements. I then presented the information to the State of Utah Energy Board, as a Company Expert witness, the reasons why some oil leases that were remote from gas tie-in infrastructure should be granted a waiver from gas flaring of small quantities of associated gas. This information successfully became the basis for some much needed waivers for Shell and other operators who also held leases in very remote areas of the field.

Given the size of the field and many new features that were related to hydrate inhibition, I began moving up yet another learning curve that was new to me because the risk of hydrate blockages throughout any parts of the gas handling system could have serious consequences. I designed a robust, yet easy to operate and maintain, methanol injection system that was installed at each wet gas entry point. I also prepared the operating guidelines and provided operator training for this equipment. Expected results were achieved. As I was doing due diligence on the installed gas handling systems, I determined that a new type of gas metering device for lease operations like these had been selected and installed as part of the original production facilities. It was a turbine meter design that had many advantages for an application like this, in particular was the meter range ability over the more familiar and standard method of orifice metering. To prevent potential gas custody transfer issues, I developed a portable meter proving design and associated procedures that could be used throughout the field with the turbine meters and which would meet gas custody transfer expectations. With the Altamont field primary development activities becoming somewhat more normal, I was invited to relocate from Houston to New Orleans to work in the Offshore Division. The invitation came from an acquaintance that I had made when I was working on California thermal recovery activities, but it was not very clear to me just why this invitation was being made. However, working on offshore developments had been an important part of the reason for my joining Shell in the first place, and this would be an opportunity to do so.

1975 – 1979

The Company was serving as the Operator for a multi-company, multi-year Consortium referred to as the Shell-Lockheed Joint Industry Program (JIP). The Marine Technology Group MTG), which had been re-located from Los Angeles to New Orleans after the Santa Barbara oil spill, was the core group for developing “far horizon” deep water field developments, i.e. those fields that could not be done using the traditional bottom founded structure methods because the water was too deep and conventional methods too expensive or technically not feasible to use. The person that had invited me to New Orleans was a Section Lead in this Group. In the year before I moved to New Orleans, the MTG had started installing the center-piece of the JIP, which was the world’s first dry subsea manifold center (MC) prototype. I was personally humbled by the invitation to join the MTG because its membership consisted of Shell personnel who were not only much more senior than me, but each person was a recognized expert within their respective areas of technology, both within Shell and within the Industry. For example, they had developed the technology for the first floating drilling system, first applications of robotics for subsea equipment, including use of nuclear power generation for subsea equipment, early use of dynamic positioning for holding a vessel on station at fixed positions on the ocean surface, first application of designs and methods for drilling, completing, and producing subsea oil and gas wells to a host location. In addition to the MC program, the MTG was also doing conceptual designs for bottom founded compliant towers (CT’s) and tension leg platforms (TLP’s) that would allow keeping well drilling, completing, and producing duties at the surface, i.e. the above water portion of the system would be similar to the use of conventional platforms (PDQ’s), and the use of subsea wells in conjunction with floating production and storage offloading systems (FPSO’s) and semisubmersible drilling and producing systems, semi PDQ’s. Also, once the MC pilot testing was under way, MTG would start the next and final phase of the JIP, which was to expand the MC design to handle many more wells, i.e. to be more consistent with handling actual deep water field developments and to increase the water depth capability of the MC concept to 3,000 feet of seawater.

The MC system is shown in the Figure 6 photograph. The MC is located at the center of the integral barge, the manned entry point is located on the top and at the end of the MC, and the upper portion of the well test separator projects out of the top of the MC as well. Hard tanks and manned entry points are located on each side of the integral barge. The large vessels that project from the top of the four corners are trim tanks that are used to submerge the MC system into the water column and to keep the system level as it self-deploys through the water column to the seabed. The two hard tanks are used to assist the flowline, gathering line, service line, power umbilical, hydraulic umbilical and controls umbilical pull-in connections that are made after the MC is resting on the seabed. After the subsea connections are made and integrity checks done, the hard tanks are partially flooded down with seawater to provide on-bottom stability for the system, with the integral barge now serving as the gravity base foundation.

Remaining portions of the subsea MC system are represented by the photographs that are shown in Figure 7. Figure 7(a) is the deployment vessel and personnel capsule that are used to gain access to the MC system. This same service equipment was also used for access in to the dry wellheads that were used on the two satellite subsea oil wells that were connected to the MC. Individual well production was either commingled or directed to test and produced on to the host platform. The seabed flowlines, service lines and gathering lines were installed using the horizontal reel barge that can be seen in the background. Figure 7(b) shows the personnel transfer capsule as it is being winched down through the water column to dock on the MC entry point. This docking and undocking technology was developed by the U.S. Navy as an emergency method for people to get in or out of a disabled submarine. It was called a McMann docking system and modified by Lockheed for the capsule duty. In summary, once the capsule and MC mating face are aligned with one another, submersible pumping is started from inside the capsule and with the start of removal of the water that is contained in the space between the bottom of the capsule and that in the mating face on the MC, pressure difference between ambient seawater pressure and the lower pressure created inside the connections results in a very large downward force that holds the capsule on the MC during personnel access to the MC, where pressure remains at atmospheric pressure. Access to MC winch line is obtained by acoustic release of a buoy attached to a light material tag line that is in turn attached to the winch line. This assembly is refurbished after each series of the capsule deployment. To release the capsule from the MC to begin winching it back to the surface, the space between the capsule and MC capsule is flooded down from inside the capsule. As seawater enters this space, the holding force acting downward on the buoyant capsule is reduced until there is no longer any force holding the capsule down except the attached winch line.

Figure 7 (c) shows the host PDQ to which the two subsea wells and the MC were connected. The PDQ also included one platform well that was completed as a simulated subsea well for risk mitigation of the possibility that one of the two subsea wells would not be capable of producing to the three well MC for any reason. Since both subsea wells were in service, this platform simulated subsea well was ultimately commissioned as a normal platform well.

This was a full-scale pilot test for producing up to three subsea wells through the MC and on to the nearby production, drilling and quarters (PDQ) platform. My specific assignment to the MTG was to help complete the MC hook-ups at the platform, help recruit and train operators for the system, over-see start-up of the subsea wells, the MC, platform subsea related equipment and to direct the system operations during the targeted four year MC pilot test program. As I learned more about the system, it became increasingly clear why I had been invited to join the MTG. Subsea and thermal projects both require that the systems be defined successfully from reservoir and on through the topsides. It is like a chain in which all links must work together and the whole system can be no stronger than its weakest link. Also, in my previous activities, I had become familiar with designing production equipment, operator training and starting-up many of the types of production equipment that was contained within the MC system, as well as the production equipment that was located on the platform.

Although I was already familiar with the normal E&P operations control systems, the MC system included the Company’s first use of a micro-processor based system that would control the entire system via hydraulics, remote terminal units, and the to-from communications for monitoring and controlling solenoid valves via communication lines that were similar to sound powered phone lines that were common at that time. This aspect represented another very steep learning curve for me, but with the help that I received from others about how to use binary code software programming, the keyboard and associated screen, I was able to quickly learn how to use it, and provide operator training for others to use it as well.

My initial work, along with learning about the MC system, involved completing installation of all of the platform based subsea equipment that integrated it into the normal platform equipment, testing it, and starting it up. Along with operator recruiting, training and these other many activities, this was an unusually intense time period for me. The Operations Supervisory personnel, including the Production and Maintenance foremen, were exceptionally helpful in this regard. I also had to learn the many normal offshore PDQ well and producing system safety systems, procedures and associated Company and Federal Rules and Regulations that were involved in activities like these.

The final new technology area that I will mention was the use of through flowline (TFL) well servicing methods that were being incorporated in all Shell operated subsea wells. TFL hydraulic methods, along with the use of tool strings that were equipped with hydraulic pistons to transport the tool string to or from a well, and equipped with a suite of tools to be used in a flowline or well bore. Thus, the tool string could be used to cut paraffin deposits from the subsea flowlines and do well downhole operations like setting and retrieving the storm chokes that were placed near the bottom of a well. These devices were mandatory as a safety measure against uncontrolled flow of well fluid if the seabed well equipment was damaged for any reason. During start-up of one of the two subsea wells, sand control failed on one well and essentially sanded up the wellbore and flowlines connecting it to the platform. A well workover project for recovering the well was in the planning stages, but I had learned enough about the TFL system to request permission to see if I could use the TFL system and flowline hydraulics to remove the sand from the system. Since this would not cost anything to try, I was given permission to see what could be done in this way. In summary, it took me about three weeks from start to finish with these efforts. End results were that the system was cleared of all sand, the storm choke was recovered for inspection, and this revealed that the choke size that had been used during the well completion activities was not correct. Further, the choke spring that had been used was much too weak for the application. Collectively, these matters were the reason for the sand control failure that led to loading the system up with sand during well start-up. The choke manufacturer technician retrimmed the choke size, installed a stronger spring and verified its correct operation, including the device locks. The storm choke was rerun successfully. This was followed by using careful ramp up stages for returning the well to production so that the gravel pack sand control system could properly be formed to perform its sand control function.

A well workover was no longer required and these preparations were terminated. This well actually became one of the best, perhaps best, oil well producers in the Gulf of Mexico at that time. Also, due to the close monitoring of the system during TFL operations and the well ramp up rates, two important new subsea technology aspects were learned. The first one was related to the importance of the fact that there was a time lag associated with the pressure pulses that were the primary detailed item that was used along with the normal volume information that was routinely used with TFL operations to determine tool string location. When the well was completed, polish bores of a smaller inside diameter than the tubing string inside diameter were placed at a known distance from a downhole device’s landing and locking position. Thus, as TFL tool transport pistons passed through the polish bore, a pressure pulse was generated. The pulse would be transmitted back to the surface through the TFL hydraulic fluid to provide a more accurate location of the tool string than the one that was based on the volume of TFL fluid pumped and as the downhole device was approaching its final landing position in a remote well. This bit of pulse time lag observation revealed why in some previous subsea well TFL operations; the devices had been overrun past their locking position. In some instances, devices had become broken up, in others; they were jammed into their landing position so hard that they could not be retrieved from the well. The second important observation was due to close system monitoring during the well ramp-up period. At the low producing rates, paraffin build-up in the flowline occurred quickly, requiring frequent TFL paraffin cutting. As production rates were ramped up, this flowline paraffin cutting frequency reduced, and at the final, and highest production rates, the paraffin removal frequency was extended from the lower producing rates’ frequencies of hours and days to a frequency of a month or more. This became the first “proof-positive” of paraffin deposit build-up rate sensitivity to the oil flowing velocity in a subsea flowline. Regarding the technology of downhole safety valves at the time, it helps to recall that the use of storm chokes was the norm at the time for many offshore wells, and for all subsea wells. Wireline set tubing safety valves not only suffered from reliability issues, but they also represented a significant obstruction in the tubing string. This was acceptable for platform wells, because wireline operations were routine for platform wells. Plans for developing full opening, tubing retrievable and hydraulically operated downhole safety valves were on drawing boards, but routine and reliable application of these types of devices did not come until several years later.

During this period, I maintained multiple reporting lines and was responsible for both engineering and operating assignments. Shell provided Management and Technical support to our small subsea team throughout the pilot testing program. Once MC operations were “normal”, i.e. predictable on the platform, we began sharing our learnings at other sites where Shell had also used satellite subsea oil and gas well tiebacks to platforms. Within the MTG, I was beginning to have a reputation as the “go-to” person about subsea production matters. Specifically with respect to the MC system performance, in a very short period of time, we had finished the hook-ups, system start-up and we were routinely producing about 10 percent of the host platform’s production. This was confirming the fundamental validity of original JIP’s MC designs and the JIP production objectives were being met.

I became the Shell “Company Man” for the MC re-entry activities. In this role, I was responsible for planning MC re-entry activities, preparing the necessary procedures, mobilizing personnel and equipment, over-seeing the activities, conducting some MC maintenance activities myself, preparing the MC for return to production and returning it to normal production, as well as coordinating the de-mobilizing activities as needs were phased out. Safety of all activities was a priority consideration throughout and there were no safety issues, nor were there any near misses throughout the MC pilot test period.

Coincidental with conclusion of the MC pilot test period, all but one of Shell’s thirteen oil and gas subsea wells in the Gulf were producing normally. This one well contained mechanical downhole failures and it had encountered sand control failure that had loaded the wellbore with sand. Ultimately, this particular well was to be abandoned, during which a diver’s previous intervention at the well, had somehow resulted in making a cross-over between the tree’s swab valve and tree wellhead connector release hydraulic control lines. When the initial step to gain access to the wellbore was taken to open the swab valve, the tree connector was released and the tree moved upwards due to pressure that was trapped in the well casing. This unfortunate situation, which resulted in hydrocarbon release to the ocean, had a serious dampening within the Company about subsea well activities in the Gulf of Mexico due to the time that was required to re-connect the tree to the wellhead and to finally abandon the well. Even though I was personally learning about this situation second-hand, I could surmise that a situation such as this would not bode well for my own prospects and the very high interests that I had developed for the prospects of a future in subsea engineering within Shell.

Once the MC pilot testing was finished, I oversaw the MC system shut-down, including modifying the hard tank flowline piping so the two subsea wells could continue producing directly to the platform. Some components were recovered from the MC and diagnostics were performed on both the equipment to remain in the MC and equipment that was to be recovered. I prepared the associated MC close-out reporting for Shell and the MC JIP. Also, I reviewed and commented results of the design work that had been on-going while the MC pilot test was in progress and done as the final part of the Shell-Lockheed JIP to extend system capabilities to 3,000 feet of water. This timing had been preceded by a necessary Shell business decision to disband the MTG and to defer any further new subsea work in the Gulf of Mexico for an uncertain, but very long period of time. The reasons were twofold. First, the conventional platform approach to field developments would continue to be the norm for many more years. Second, the problems that had occurred with the above described subsea well abandonment would continue to cloud subsea well considerations for many years to come.

From my personal perspective, I had found that these technically challenging offshore and subsea activities were the areas in which I wanted to spend the remainder of my working career. Also, I had acquired my Civil Engineering Professional Engineering (PE) licenses for Louisiana and Texas during this time period, so I decided that my personal objectives could best be attained by resigning from Shell, move to Houston, and begin the challenge of performing consulting work. Preferably, not just for one company, but for those companies that continued to have interests in subsea methods as they pertained to potential commercial use of these methods. I was truly privileged to have worked for U,S. Shell, and I will always be appreciative of the Company and the many opportunities and acquaintances that I had while working there.