Since the installation of the Ekofisk Tank by Phillips Petroleum and Partners in 1973 there have been over thirty concrete fixed and floating structures installed in the world. These structures are constructed ashore, in dry docks and fjords, requiring a period of two to four years to build and are then towed to site and installed in a nearly complete basis. Concrete offshore structures are the largest structures ever moved by man and their cost can exceed 1.5 billion US dollars. Water depths for the fixed structures have reached 300 meters and floating structures are limited only by the anchoring system utilized. Engineers and constructors of multiple nationalities have contributed to this outstanding technology and because of the magnitude and diverse nature of these structures, in many instances they should be honored individually.
At this time the Oilfield Energy Center wishes to honor the first concrete structure built for a hostile offshore environment for the development of hydrocarbons, the Ekofisk Storage Tank and Flow Station, and the companies responsible for it, Phillips Petroleum Company, and Doris Engineering; and the individuals who made it happen.
Recognizing the following individuals and companies that contributed to the development of this technology:
Claude M. Bender, Ben C. Gerwick, Jr., Henri Marion, Jean Martin, Leonard Meade, Dominique Michel, J.L. Parat, F. Sedillot, C.G. Doris Engineering and ConocoPhillips.
Since the installation of the Ekofisk Tank by Phillips Petroleum & Partners in 1973 there have been more than 30 concrete fixed and floating structures installed around the world. Among these were the record-setting Condeeps: Gullfaks C, the heaviest object ever moved by man; the majestic Troll A, sitting on the seabed in 994 ft (303 m) of water; and the elegant Draugen. These giants were constructed using a unique process called continuous slip-forming, a process that is still in use today. The technique involves movable steel forms that are slowly slipped upwards on the structure as the concrete is setting, so pouring can be conducted continuously until the structure is completed. After they are built, usually in bays or fjords, the structures are towed out to sea and ballasted onto location, their massive concrete columns used for storage of oil and water.
Construction can take as much as 2 to 4 years can cost more than US $1.5 Billion. While hundreds of engineers and builders of multiple nationalities have contributed to the design and construction of these giant structures, the Oilfield Energy Center wishes to honor the early pioneers who, through their vision and determination, proved that concrete gravity-base structures could withstand the tests of time, waves and weather to become a practical solution for offshore production facilities.
Recognizing the pioneering efforts of the following individuals and companies who contributed to the development of this technology:
Claude M. Bender, Ben C. Gerwick, Jr., Henri Marion, Jean Martin, Leonard Meade, Dominique Michel, Hubert J.L. Parat, François Sedillot, C.G. Doris Engineering, dr.techn.Olav Olsen, and ConocoPhillips.
Suction piles were introduced in the late 1970’s and early 1980’s as a competitive alternative to less-successful permanent mooring systems. After several experiments, small-scale tests led to full scale open-sea tests.
The first 30 of several hundred suction piles were installed offshore Congo and in the North Sea in 1995. Beginning in the late 1990’s, the concept was expanded to deep-water mooring systems for drilling rigs.
A significant result is that an entire service industry has been established for the design and installation of suction piles and anchorages, with major Norwegian and USA companies involved. Suction anchor piles provide a cost efficient alternative for catenary, taut leg and tension leg moorings, compared to conventional piles or drag embedded anchors. This award recognizes the extremely important early pioneering development stage of suction pile technology which resulted in continued significant improvements in design, installation and effectiveness.
Recognizing the pioneering efforts of the following individuals and organizations that contributed to this technology:
Knut H. Andersen, Dr. Rune Dyvik, Asle Eide, Jan R. Hogervorst, Per Sparrevik, and Tor Inge Tjelta
Norwegian Geotechnical Institute, Shell, and Statoil
Floating Production Storage and Offloading (FPSO) systems are generally shipshape vessels stationed in offshore producing oil and gas fields that receive production from wells that is processed, stored and eventually offloaded to a transport vessel. The key advantage of this concept is that vessels can be mobilized with relatively little lead time to remote areas that have minimal infrastructure.
The first FPSO, with a storage capacity of 350,000 bbls, was installed by SIPM (Shell Oil) and Single Buoy Moorings, Inc. (SBM) in 1977 as contractor in the Castellon field, offshore Spain, using a single point mooring system in 117 meters of water. Shortly thereafter, Petrobras installed a similar FPSO in 122 meters of water offshore Brazil and after 1985, FPSO numbers started to grow. Capabilities and sizes evolved substantially in the ensuing 35 years. The number of operating oil companies employing FPSOs grew substantially, as did the number of contractors designing and building FPSOs.
Topsides grew from being simple processing plants on part of the deck of a tanker to covering most of the deck and weighing as much as 30,000 MT or more. Gas compression, water injection and increasingly complex process plants have become common, now tackling sour gas removal and CO2 removal.
Initially FPSO length of service was seen to be a few years and their use often was for early production testing or small short-life fields. That has now grown to as much as 20-30 years. After starting with converted tankers, the industry grew to employ new “intercept” tankers and, most recently, specially built tankers just for FPSO service. In a departure from the tanker tradition several newbuild round hull FPSOs entered service starting in 2007.
FPSO hulls have developed in an evolutionary fashion from standard tankers converted to FPSO service, rather than pioneering radical new floating production concepts such as the Spar and TLP. About half of the world’s FPSO fleet is owned by producing oil companies and the other half is owned by contractors which lease to oil companies.
At the time of the first FPSO at Castellon, Singapore shipyards still used bamboo scaffolding. In the 2015 construction of the FPSO for the deepest water yet to use with disconnecting lazy wave SCR risers, Shell employed a Singapore shipyard that delivered workers at the FPSO in elevators, and only with prior safety briefings. These actions achieved big advances in safety with lost time accidents occurring only after several million man-hours – this for a project of unprecedented technical and management sophistication.
In 2020 more than 175 FPSOs are installed and operating with 25 more available for redeployment and another 25 on order, representing the most popular and versatile of the floating production concepts. These figures do not include FPSOs that have completed their service life and are due to be scrapped.
FPSO storage capacities are now often up to 2+ million bbls of crude, serving complex processing trains handling up to 400,000 boepd of production from as many as 100 wells. LNG processing equipment has been a recent adaptation. A variety of station keeping systems are used: weather vaning single point moorings (turrets, yokes), spread mooring, and even dynamic positioning usually for single wells. Water depth ratings are up to 2,900 meters. FPSOs can operate worldwide and, with appropriate design features, even in severe environments such as the North Sea and Eastern Canada. The use of the FPSO concept continues to grow with wide industry acceptance as a viable economic alternative for quickly establishing production in both remote and developed areas.
Recognizing the pioneering efforts of the following individuals and organizations that contributed to this technology in the first ever FPSO and in the FPSO in the deepest water depth (installed in 2,900 meters of water in 2016 in the U.S. Gulf of Mexico) are shown below. Coincidentally, both efforts were accomplished by the same oil company and built by the same contractor:
The first ever FPSO at Castellon in 1977 in 117 meters water depth:
J. H. T. Carter, Frank Eijkhout, J. A. Foolen, Wim Jan van Heijst and Leon Vincken,
Shell International Petroleum Maatschappij (now Shell),
Single Buoy Moorings (now SBM).
Deepest water FPSO and one of most sophisticated, at Stones in 2016 in 2,900 meters water depth
Shell, Houston: Curtis Lohr, Project Director
SBM Offshore – Houston: Stein Rasmussen, President
In the early 1960s, the offshore oil and gas industry was in its infancy with regard to research and development of production systems for remote and deepwater locations (> 300 ft. of water depth at that time). In an effort that would continue over the next 30 years, Humble Oil and Refining Co. (now ExxonMobil) launched a development program for a submerged production system (SPS) that encompassed research and initial development of many of the ground-breaking systems, configurations and equipment that are still in use in today’s ultra-deepwater production systems.
Prototype systems were developed during the 1960s and 1970s and were largely done in secret for competitive reasons. In 1982-83 the first full-blown SPS multi-well template and manifold system was installed in the North Sea for the Shell-Esso Central Cormorant Project. The second installation occurred in 1991 at the Saga-Esso Snorre Project in the Norwegian Sea. Though it was an ExxonMobil project, dozens of other companies were involved and contributed to the effort. The ExxonMobil SPS had the most profound influence on remote deepwater subsea production of any of the large projects of its type, and it resulted in many “firsts” that led to the widespread success and use of subsea production systems.
Following is a list of major “firsts” developed by the project:
1. Multi-well developments using the template and manifold concept. For most developments, it was economically attractive to cluster wells at one location. Advances such as Mobile Offshore Drilling Units (MODUs) allowed for welldrilling, completion and services from a single location and production facilities could then service all the wells at one location.
- Through-tubing, pump-down workover and intervention. Since flow lines and wells were horizontal and lengthy, standard tubing and wireline workover and intervention was very difficult. The ability to pump down and retrieve tools was a break-through alternative.
- Metal-to-metal seals on piping and valves. Elastomers were (and are still) the standard for seals, but they age and are not as reliable in high pressure and high temperature environments. Metal-to-metal seals solved this problem and have become the standard for all subsea equipment today.
- Leak containment for the manifold. To address the unlikely event of a leak, a system was developed to contain minor leaks.
- Remote repair and replacement of components. In the early days, all repair and intervention used “hands on” methods which were not viable in the deepwater environment. Systems and equipment were developed for deepwater intervention, and valves, seals, subsystems and other components were designed for remote replacement.
- Remote Control Vehicles (ROV) used for manifold intervention. ROV development was not part of the SPS project, but the SPS was further incentive to develop ROV intervention technology.
- Aerospace-type quality control and construction techniques. When the SPS project began, high quality control and systemized construction were lacking in much of the oilfield. However, to achieve the very high degree of reliability needed, aerospace-type quality control was adopted for the SPS and carried over into other parts of the oilfield.
- Oil pressure compensation for hydraulic and electrical control pods. Due to deepwater conditions, atmospheric pressure was not acceptable for operation of hydraulic and electrical control pods, so pressure compensation was required. The SPS solution was to design equipment and technology to operate at ambient pressures.
- Inductive electrical signal and power couplers. It was found that contact electrical “make-and-break” connections had many problems including reliability, so inductive electrical couplers were developed.
- Water depth pressure compensated fail-safe valves. As water depths increased, use of underbalanced pressure valves was not possible, so compensated valve development was required.
2. MODU installation of large manifold production systems. Installation of relatively large manifolds had previously been done by derrick barges, but this was uneconomic for most projects, somanifolds and templates were adapted for MODU installation.
3. Remote installation of pipelines into the SPS module. Pulling of pipelines into the SPS with remote connectors was novel and untried before the SPS development.• Subsea production pump and oil/gas separation systems. The ability to pump gaseous crude oil and in some cases to do initial gas/oil separation was necessary for transportation of well fluids from wellheads and manifolds across long distances to the production facility
4. Articulated marine risers. Technology was developed to transfer workover and production marine risers from wellhead to wellhead.
The SPS was truly a significant concept and technological pioneer in the early development of subsea production systems for ultra-deepwater.
Principal Companies that contributed.
Humble Oil and Refining Co. (now ExxonMobil) TRW Subsea (now Ferranti) Vetco Offshore (now GE Oil and Gas) General Electric
Rockwell-McEvoy (now Cameron) Global Marine (now Transocean)
Principal Individuals that contributed:
Joseph A. Burkhardt (ExxonMobil), Daniel R. Tidwell (ExxonMobil), Thomas W. Childers (ExxonMobil), William D. Loth (ExxonMobil), J. Preston Mason (ExxonMobil), Roger J. Koerner (ExxonMobil), John A. Kopecky (ExxonMobil).
The beginning of the offshore oil industry was marked by three piled structures set off the coast of Louisiana in 1947 (out of site of land–about 10 miles offshore). The leases were owned by Kerr-McGee/Phillips/Stanolind, Superior, and Exxon. Prior work offshore involved wooden piles and structures which were generally connected to shore by trestles. The builders of early platforms anticipated that offshore construction work would be both dangerous and slow. Consequently, much thought was given to the possibility of doing some prefabrication onshore, to make the offshore effort easier. One such idea was that of M. B. Willey, Chief Engineer of J. Ray McDermott Co. Willey pioneered the concept of building a steel tubular space frame on land, transporting it to the offshore site, and setting it in position with a crane. The legs of the space frame extended from the sea bottom to above the water’s surface. Steel piling could then be driven through the hollow legs to “pin” the structure to the bottom. The bracing that tied the legs together helped to transmit the wave loading to the seabed. The jacket, as this space frame template came to be known, also served as a steel cage protecting the wells. As the industry evolved, the piled jacket became the standard support structure for the offshore industry. Many thousands of such jackets have been fabricated and installed in all parts of the world. As the industry advanced, jackets were designed and built for ever deeper water. Today there are a number of jackets in water depths over 1000 ft.
Recognizing the pioneering efforts of the following people and companies who contributed to the development of this technology:
Francis P. “Pat” Dunn, Arthur L. Guy, Ferdinand R. Hauber, Griff C. Lee, Ralph Thomas “J. Ray” McDermott, Frank Motley, Jay B. Weidler, M. B. Willey
Brown & Root, Exxon (ExxonMobil), J. Ray McDermott Co., Kerr-McGee, Phillips Petroleum (now ConocoPhillips), Shell, Stanolind (BP), Superior (ExxonMobil)
Seafarers have recognized the inherent floating stability of spars. From ancient technology, new ideas are often derived. So it was that hollow steel spar-shaped tanks were proposed for use as floating storage and offloading terminals. The first such spar was installed at Shell’s Brent Field in the UK North Sea in 1976. What should be remembered about the Brent Spar was its astounding success as a floating marine facility in one of the harshest sea environments in the world.
Now the technology is routinely used, with 15 installations worldwide in water depths to 5,610 ft (1,710 m). Since the original Brent Spar, which was a classic cylindrical tank design, significant improvements have been made. First was the Truss Spar, which substituted an open truss structure for the bottom half of the vessel to add stability. Eleven of these were in service by 2005. The newest design is the Cell Spar, whose unique design is achieved by welding hundreds of cylindrical tanks end-to-end. The first Cell Spar was installed in 2004 in the Gulf of Mexico in 5,300 ft (1,616 m) of water by Kerr McGee. Engineers see no maximum depth limit for spar technology.
Recognizing the pioneering efforts of the following individuals and companies who contributed to spar technology:
Eddie Goldman, Ed Horton, Frank West, Deep Oil Technology Company (now separately owned by McDermott International and Technip Offshore Inc.) Royal Dutch Shell (Holland) Shell.
Submersible Mobile Offshore Production Units (MOPU) are non-shipshape, bottom founded mobile type structures and the first of a number of classes, shapes and kinds of MOPUs. MOPUs have the ability to mobilize quickly into a production field, have oil and gas processing equipment on them, store processed crude and have the ability to offload the crude to a tanker and/or pipeline. Today, the use of MOPUs is an accepted means to effectively develop offshore oil and gas fields.
The economic advantage of a MOPU was and is its ease of mobilization, installation and redeployment to a new field. The first unit was a submersible type unit built by The California Company (now Chevron) in 1960, that produced and stored oil in the Gulf of Mexico. In the same year, Bethlehem Steel Company patented the design, which was a non-jacking version of their mat type jackup MODU. Another early example, completed in 1961, was the purpose-built submersible by ODECO, called the OBM for the initials of ODECO, Burma Western (later part of British Oil then BP) and Murphy Oil. The OBM was similar to and a takeoff of ODECO’s drilling units such as the Mr. Charlie. These early units proved the concept of the MOPU that later led to the development of the jackup and semisubmersible type MOPUs.
Recognizing the pioneering efforts of the following individuals and organizations that contributed to this technology:
John C. Estes, W. E. Foster, Tom Graham, Ray E. Lacy, Jr. and J. C. Sparkman. Bethlehem Steel Company, The California Company (now Chevron), Murphy Oil Corporation and ODECO (now Diamond Offshore Drilling).
The first use of TLPs (Tension Leg Platforms) represents a very significant step in the advancement of floating platforms for the offshore petroleum industry. The basic concept for a TLP-type floating platform was being discussed in the early 1970s, driven by the perceived needs for such technology to produce the expected deep water developments. In 1973 Deep Oil Technology (DOT) formed a Joint Interest Project (JIP) funded by 12 companies. The JIP was basically the testing of a one-third (1/3) scale model TLP offshore California and being successfully completed in 1975.
While most JIP participants did not show a great interest, Conoco, under the direction of L. B. “Buck” Curtis and N.D. “Scotty” Birrell recognized the potential for the technology and continued studies within Conoco. This eventually led to the decision by Conoco to form an engineering group in the UK to design and install a TLP in the North Sea in Conoco’s Hutton Field. While the Hutton Field was in 485 feet of water, conventional type sea floor based structures could have been used. However, Conoco recognized the need for floating platforms for eventual deepwater production. The decision was made to develop the Hutton Field by developing the first major TLP. It was successfully installed in 1984—approximately 14 years after first becoming interested in the concept. The Hutton TLP proved to be very successful and subsequently several other major TLPs have been installed in the North Sea and the Gulf of Mexico – a very significant enabling technology.
Recognizing the pioneering efforts of the following individuals and companies who contributed to this technology:
Norman D. “Scotty” Birrell, L. B. “Buck” Curtis, Thomas O. Marr, John A. “Jack” Mercier, David Vories, Brown & Root/Vickers Offshore (Halliburton) and Conoco (ConocoPhillips)