Offshore and subsea facilities

At the present time, more than 9,000 offshore platforms are in service worldwide, operating in water depths ranging from 10 ft to greater than 5,000 ft. Topside payloads range from 5 to 50,000 tons, producing oil, gas, or both. A vast array of production systems is available today (see Fig. 1). The concepts range from fixed platforms to subsea compliant and floating systems.

Historical Review

Supporting Structures

In 1859, Col. Edwin Drake drilled and completed the first known oil well near a small town in Pennsylvania, U.S.A. This well, which was drilled with cable tools, started the modern petroleum industry. In 1897, near Summerland, California, U.S.A., H.L. Williams extended an offshore oil field into the Santa Barbara Channel by drilling a submarine well from a pier. This first offshore well was drilled just 38 years after Col. Drake’s well. Five years later, more than 150 offshore wells were producing oil. Production from the California piers continues today.

In the late 1920s, steel production piers, which extended 1/4 mile into the ocean at Rincon and Elwood, California, were built, and new high-producing wells stimulated exploration activity. In 1932, a small company called Indian Petroleum Corp. determined that there was a likely prospect about 1/2 mile from shore. Instead of building a monumentally long pier, they decided to build a portion of a pier with steel piles and cross-members. Adding a deck and barging in a derrick completed the installation. By September 1932, the 60 × 90-ft “steel island” was completed in 38 ft of water. This was the first open-seas offshore platform and supported a standard 122-ft steel derrick and associated rotary drilling equipment. In January 1940, a Pacific storm destroyed the steel island. During the subsequent cleanup, divers were used for the first time to remove well casing and set abandonment plugs.

Meanwhile, the first offshore field was discovered in the Gulf of Mexico in 1938. A well was drilled to 9,000 ft off the coast of Texas in 1941. With the start of World War II, however, offshore activities came to a halt. Activity did not resume until 1945, when the state of Louisiana held its first offshore lease sale. In 1947, the first platform “out of sight of the land” was built off the coast of Louisiana in 20 ft of water.

Between 1947 to the mid-1990s, approximately 10,000 offshore platforms of different types, configurations, and sizes were installed worldwide. In the post-World War II era, the growth of drilling in the Gulf of Mexico intensified. As platforms were placed in deeper water, their functional requirements and structural configurations became more complex. For steel-jacket structures, the offshore engineering community delivered significant technology advances to permit jacket structures to be deployed in ever-increasing water depths and hostile environments (see Fig. 2).

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  Fig. 1—Alternative hydrocarbon production systems [OPL Subsea Production Wallchart, Oilfield Publications Ltd. (OPL), Houston].

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  Fig. 2—Water depth milestones for conventional jacket structures [Website Source Figure, Minerals Management Service (MMS), U.S. Dept. of the Interior, Washington, DC].

In the late 1960s, the development of the offshore fields in the North Sea commenced, leading to a step change with the advent of huge payload requirements in a hostile environment that did not permit intervention for de-manning in the event of a predicted storm event. Although steel-jacket structures dominated the development of North Sea fields, concrete gravity structures competed, for the first time, with their steel counterparts. In 1973, the first concrete structure was installed in the North Sea in the Ekofisk field.1 Twenty concrete platforms later, in 1995, the Troll field was developed using a concrete substructure sitting in 985 ft of water, weighing 1 million tons. The Troll structure, shown in Fig. 3, is being towed to site.

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  Fig. 3—Troll platform being towed to site (Photographic Services, Shell Intl., London).

While North Sea developments progressed rapidly from 1970 to 1990, exploration in U.S. waters ventured into deep water in the Santa Barbara Channel and the Gulf of Mexico. A number of water-depth records were set for steel-jacket structures. In 1976, the Hondo platform was installed as a two-piece jacket in 850 ft of water off the coast of California. Two years later, the Cognac platform was installed in three pieces in 1,025 ft of water in the Gulf of Mexico. As fabrication, transportation, and installation technology advanced, it became possible to install single-piece structures in deep water. In the early 1990s, the Harmony and Heritage platforms were installed single-piece in 1,200 ft of water off the coast of California. However, the record for the largest single-piece jacket ever installed rests with the Bullwinkle platform, installed in 1,350 ft of water in 1988. Fig. 4 shows the Bullwinkle platform in service in the Gulf of Mexico. The platform deck gives little clue as to the size of the substructure below (see Fig. 5).

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  Fig. 4—Bullwinkle platform in service in U.S. Gulf of Mexico (Photographic Services, Shell Intl., London).

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  Fig. 5—Transportation of the Bullwinkle steel substructure (jacket) (Photographic Services, Shell Intl., London).

At the other extreme of the jacket/topsides payload milestones, the industry recognized that marginal fields could economically be exploited, provided the topsides structure was restricted to containing only the minimum facilities required for production, and a minimum substructure configuration was adopted to meet the functional specification and robustness requirements. In the Gulf of Mexico, a large number of minimum facility platform designs were adopted in the 1970s and 1980s to exploit marginal fields. As the North Sea industry matured in the 1990s, minimum facility platforms gained favor as flow assurance improved and as the need to minimize capital expense (CAPEX) for marginal fields was acknowledged. The Davy/Bessemer platforms installed in the mid-1990s and the Skiff/Brigantine platforms installed in the late 1990s demonstrated that minimum-facility platforms could be designed for service in the North Sea environment.

It became clear in the 1980s that the water depth limit for fixed platforms, from a functional and an economic perspective, was restricted to 1,500 ft. Exploration drilling was progressing in water depths beyond this limit, and offshore engineers began developing platform designs that circumvented the problems associated with fixed platforms beyond 1,500 ft. The Lena compliant guyed tower was developed and was installed in 1,000 ft of water in the Gulf of Mexico in 1982. This tower was designed to be more flexible than fixed jacket structures and, therefore, more “compliant” to the environment. The guys provided vertical and lateral stability for the structure. In 1998, the Baldpate and Petronius compliant towers were installed in 1,648 and 1,754 ft of water, respectively, in the Gulf of Mexico; Baldpate is illustrated in Fig. 6.

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  Fig. 6—The Baldpate Compliant Tower is one of the tallest free-standing structures in the world – Empire State Building (right) for comparison (Web Photograph, Amerada Hess Corp., New York City).

In the 1970s and 1980s, for discoveries remote from existing infrastructure, ship-shaped floating production, storage, and offloading systems (FPSOs) provided a solution to economic development as they offered oil-storage capability. In 1977, off the coast of Spain, oil was drawn from a subsea well in 370 ft of water into a tanker moored to an oscillating mooring tower. Other similar developments followed (e.g., the Nilde field offshore Italy in 1982). Because of the motions of the FPSO vessel, the concept required that the wellheads be located on the seabed, known as wet or subsea wellheads. A variant to this approach was the use of dry wellheads, located on a fixed steel platform, in combination with an FPSO [e.g., Hondo offshore California in 1981 and the Tazerka offshore Tunisia in 1982 (see Fig. 7)].

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  Fig. 7—FPSO and jacket structure at the Tazerka Field, Tunisia [Single Buoy Moorings Inc. (SBM), Marly, Switzerland].

The Tazerka FPSO, at 210,000 deadweight tons, was the largest FPSO deployed until 1985. Up to 1986, FPSOs were based on conversion of existing tankers. In 1986, Golar Nor demonstrated that a purpose-built FPSO, with oil, gas, and water separation, was economically feasible for production in the harsh North Sea environment. The development of FPSOs continued around the world, including offshore Australia and in the South China Sea, using a range of mooring designs. In 1993, the Gryphon FPSO was the first to be placed permanently in the North Sea; by 1998, the number operating in the North Sea had increased to sixteen.

An alternative concept in regions with an economically accessible infrastructure was the semisubmersible floating production system (FPS). This system consists of a buoyant floating facility moored to the seabed. The system offers reduced motions compared to an FPSO. In 1975, a production semi-submersible was used in the Argyll field in the North Sea in 254 ft of water. Two years later, the first production semisubmersible was placed offshore Brazil in the Enchova field. From that time, the use of production semisubmersibles gained increasing popularity, particularly offshore Brazil in water depths up to 6,000 ft. Fig. 8 shows a semi-FPS being transported to its final location in deep water offshore Brazil. Fig. 9a shows the global fleet of an installed/sanctioned semisubmersible-based FPS.

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  Fig. 8—Sea transportation of the Petrobras P40 semisubmersible FPS (courtesy of Petrobras Image Bank, Petrobras, Rio de Janeiro).

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  Fig. 9a—Worldwide fleet of installed and sanctioned semisubmersible FPS (courtesy of BP).

In the Gulf of Mexico, the pioneering application of a semisubmersible was at a Green Canyon field for extended well testing in 1,500 ft of water from 1988 to 1990. However, initial deepwater production from floating systems in the Gulf of Mexico was dominated by an alternative concept known as the tension leg platform (TLP). A TLP is a vertically moored, buoyant structure anchored to the seabed with vertical taut steel tendons. The system relies on the tension in the tendons for its stability. The advantage of the TLP is reduced motion compared to FPSOs or conventional FPS facilities. The reduced motions permit the use of dry wellheads. As with an FPS, a TLP has no storage capacity and, therefore, requires a separate storage tanker or a pipeline or shuttle tanker for export. Following large-scale TLP model testing offshore California in 1974 and 1975, the concept was adopted for the first time in the Hutton field in the North Sea in 1984. Located in 500 ft of water, the Hutton field could have been developed using a conventional steel-jacket structure, but the harsh North Sea environment was judged to provide the ideal test bed for the TLP design prior to venturing into deeper waters. Since 1989, a number of TLPs have been installed in deep water in the North Sea, Gulf of Mexico, and offshore Indonesia in water depths ranging from 1,000 to almost 4,000 ft. Fig. 9b shows the global fleet of installed/sanctioned TLP facilities.

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  Fig. 9b—Worldwide fleet of installed and sanctioned TLPs (coutesy of BP).

With the focus in the late 1980s and throughout the 1990s firmly on the development of deepwater production technology, a number of new concepts, or variants of established concepts, have emerged. Of these, the most widely used has been the deep draught caisson vessel (DDCV) or spar concept. The spar is a floating system comprising a deep draught cylindrical hull (caisson), which supports a topsides structure, and is moored using a system of mooring lines from the hull that are anchored to the seabed. Spars, like TLPs, reduce vessel motions compared to FPSO and FPS options, permitting the use of dry wellheads. Spars have proved a popular development choice in the Gulf of Mexico, where three classic spars and six truss-spars have been installed or sanctioned for installation as of 2002 in water depths up to 5,610 ft; see Fig. 9c.

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  Fig. 9c—Worldwide fleet of installed and sanctioned spars (courtesy of BP).

Other recent technology development efforts have focused on a variant of the semisubmersible FPS concept. This concept extends the draught of the hull structure of a conventional FPS to reduce motions. These systems also can be designed to be self-installing. Engineering is under way for a production semisubmersible for the development of the Thunder Horse field in the Gulf of Mexico in 6,000 ft of water, with a topsides weight in excess of 50,000 tons; see Fig. 14.10.

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  Fig. 10—Semisubmersible FPS planned for the Thunder Horse field (courtesy of BP).

the industry has achieved enormous success and shown admirable innovation to meet the challenges of producing oil and gas in the hostile deepwater environment. A variety of proven dry-tree and wet-tree solutions exists for water depths up to 6,000 ft; see Fig. 11.

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  Fig. 11—Alternative proven technology field development options (courtesy of BP).

Many other special, and often one-off, structures have been installed offshore. The commercial fields in the arctic offshore continental shelves of the U.S. and Canada have led to the development of production facilities that are able to resist ice loads. By 1968, 14 platforms were installed in the Cook Inlet of Alaska. In the early 1990s, the Hibernia field, off the east coast of Canada, was developed using a gravity-based concrete substructure capable of resisting ice-driven environmental forces. An alternative to this concept was adopted for the Terra Nova field off Newfoundland. In 2001, a purpose-built FPSO with a detachable turret was installed. If ice attack is predicted, the system is designed to permit the turret to detach and fall to the seabed. The FPSO can then be maneuvered away from the path of the ice. Once the danger has passed, the FPSO is returned to site, and the turret is re-attached to allow production to continue. Other special structures include a steel gravity oil-storage structure placed in the Gulf of Mexico in 1966 and the Maureen platform in the North Sea that was a steel gravity structure (as opposed to a concrete structure) with oil-storage capacity. The Maureen platform was successfully decommissioned in 2001.

In summary, the offshore industry, for the past 55 years, has come a long way since the first offshore platform was installed in 1947. Although most of the offshore structures constructed to date have withstood the test of time, there have been several failures that led to loss of life, loss of facility, and/or pollution. The industry has embraced the lessons learned from these failures, and the assurance of health and safety and the protection of the environment are of primary importance in the design of offshore structures.

As exploration and production encroaches into deeper water and harsher environments, the challenges of structural design increase. Environmental load predictions, transportation analyses, and installation procedures are as important to understand as the more obvious structural-frame analysis. Seldom is a designer afforded the luxury of optimizing a structure on the basis of in-place stress analysis; more often, the transportation and installation (lasting a few weeks out of perhaps a 20-year structure life) will dictate the major framing patterns.

Subsea systems

Subsea production wells have been around for more than 40 years. A subsea well consists essentially of a wellhead assembly and Christmas tree (sometimes referred to as a wet tree), which is basically identical in operation to its surface counterpart, with the primary exception of reliability refinements, to permit operation at the seabed. Subsea wells have been used in support of fixed installations as an alternative to satellite or minimum-facility platforms for recovering reserves located beyond the reach of the drillstring or used in conjunction with floating systems such as FPSOs and FPSs. Fig. 12 shows an example of subsea production trees used in conjunction with a host fixed jacket structure.

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  Fig. 12—Subsea production trees used in conjunction with a fixed jacket structure (Intec Engineering, Houston).

The first subsea completion system was installed in the Gulf of Mexico in 1961 for the West Cameron field in a water depth of 55 ft. Since that time, hundreds of subsea systems have been deployed and are in operation. Complex multiwell subsea systems have been installed, and ROV intervention has become an integral part of the subsea completion system. The 1997 Mensa subsea development (see Fig. 13) holds the longest tie-in record of 63 miles in 5,400 ft of water in the Gulf of Mexico. The current water depth record of 6,000 ft was set offshore Brazil in 1998.

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  Fig. 13—Mensa subsea development: world’s longest subsea tieback in 1997 (Shell U.S.).

Types of offshore and subsea facilities

The major types of shore and subsea facilities are grouped as:

• Fixed steel and concrete gravity base structures
• Compliant and floating systems
• Subsea systems

Future Technology Requirements

In the next decade, it is expected that the industry will increasingly focus on deepwater and ultradeepwater developments, with water depths up to 10,000 ft and beyond. As water depth increases, many technical challenges emerge, the solutions for which will drive the decision-making process for sanctioning new developments. Fig. 14 describes some of the deepwater facilities and subsea technology issues.

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  Fig. 14—Vertical-sided structure (Brian Watt Assocs., Houston).

A number of technology development targets are being, and will continue to be, pursued. Some of these targets include:

• Development of project-ready subsea systems and floating production platform concepts with storage capability for water depths up to 10,000 ft.
• Mooring system concepts and options, including polyester and composite moorings.
• Minimum-facility, dry-tree platform concepts for deepwater marginal fields.
• Steel catenary riser capabilities, including large-diameter risers.
• Advances in large-diameter top-tensioned dry-tree riser arrays, including designs that permit riser contact and clashing.
• Long-term integrity assurance for intact and damaged flexible risers.
• Novel riser systems and arrays, including use of hybrid and composite risers.
• Long-distance tiebacks for subsea systems.
• Seabed-processing technology.
• Topsides reliability and optimization.
• Float-over of complete topsides for deepwater concepts, to avoid heavy offshore lift and offshore hookup and commissioning.
• Metocean data capture and assessment for deepwater sites.
• Development of self-installing minimum facility jacket structures.
• Development of self-installing deepwater development concepts.
• Flow assurance at ultradeepwater depths.

Much has changed in the industry since the first steel-jacket structure was placed offshore in 1947. The industry today is truly international, quality-conscious, and highly professional. Offshore technology challenges have been met over the past decades; much in the same manner will the challenges be met in future years with new innovations and breakthroughs.

Noteworthy papers in OnePetro

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External links

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See also

Offshore production operations

Offshore arctic operations

Fixed steel and concrete gravity base structures

Compliant and floating systems

Subsea systems

Flow assurance for offshore and subsea facilities

PEH:Offshore_and_Subsea_Facilities