PEH:Offshore and Subsea Facilities

Publication Information

Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume III – Facilities and Construction Engineering

Kenneth E. Arnold, Editor

Copyright 2006, Society of Petroleum Engineers

Chapter 14 – Offshore and Subsea Facilities

Patrick O’Connor, BP America, Justin Bucknell, MSL Services Corp., Minaz Lalani, MSL Engineering Ltd.

Pgs. 525-564

ISBN 978-1-55563-118-5
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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. 14.1).

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  Fig. 14.1—Alternative hydrocarbon production systems [OPL Subsea Production Wallchart, Oilfield Publications Ltd. (OPL), Houston].

The concepts range from fixed platforms to subsea compliant and floating systems. This chapter presents an overview of offshore facility concepts including subsea systems and flow-assurance concepts.

Historical Review

14.2.1 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. 14.2).

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  Fig. 14.2—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. 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. 14.3, is being towed to site.

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  Fig. 14.3—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. 14.4 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. 14.5).

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  Fig. 14.4—Bullwinkle platform in service in U.S. Gulf of Mexico (Photographic Services, Shell Intl., London).

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  Fig. 14.5—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. 14.6.

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  Fig. 14.6—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. 14.7)].

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  Fig. 14.7—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. 14.8 shows a semi-FPS being transported to its final location in deep water offshore Brazil. Fig. 14.9a shows the global fleet of an installed/sanctioned semisubmersible-based FPS.

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  Fig. 14.8—Sea transportation of the Petrobras P40 semisubmersible FPS (courtesy of Petrobras Image Bank, Petrobras, Rio de Janeiro).

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  Fig. 14.9a—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. 14.9b shows the global fleet of installed/sanctioned TLP facilities.

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  Fig. 14.9b—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. 14.9c.

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  Fig. 14.9c—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. 14.10—Semisubmersible FPS planned for the Thunder Horse field (courtesy of BP).

In summary, 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. 14.11.

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  Fig. 14.11—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. 14.12 shows an example of subsea production trees used in conjunction with a host fixed jacket structure.

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  Fig. 14.12—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. 14.13) 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. 14.13—Mensa subsea development: world’s longest subsea tieback in 1997 (Shell U.S.).

Fixed Steel and Concrete Gravity Base Structures

As indicated in the historical review, many types of offshore structures are in service. Some are better suited to certain environmental and operational criteria; some are limited by availability of construction sites; and some are chosen simply by subjective preference of an owner/operator. Selecting a structure type is the first major structural design task after environmental and operational criteria have been defined and will sometimes require preliminary design of several concepts before a choice is made.

Fixed Steel Structures

The most common type of offshore structure in service today is the jacket (or template) structure, as illustrated in Fig. 14.14. The template was derived from the function of the first offshore structures to serve as a guide for the piles. The piles, after being driven, are cut off above the templates, and the deck is placed on top of the piles. The template is prevented from settling by being welded to the piles’ tops with a series of rings and gussets. Hence, the template carries no load from the deck but merely hangs from the top of the piles and provides lateral support to them.

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  Fig. 14.14—Conventional fixed steel-jacket structure.

Some companies prefer to place packers in the bottom of each template leg and to grout the annular space between the leg and pile from bottom to top. The structure and pile share the axial load from the deck and the compressive and tensile loads from the overturning moment produced by lateral wave loads. The grouted pile also provides additional strength to the tubular joints where horizontal and diagonal bracing is welded to the legs. Drawbacks to this system are the difficulty in ensuring that the grout is adequately placed and of sufficient strength to be counted in the analysis and the additional difficulty in platform removal.

Although both top-hung and grouted structures are loosely called templates, some prefer to call the latter a jacket to distinguish the difference in load path. This path is substantially different for the overturning moment as well as axial loads. The top-hung template requires that moment from lateral wave loads be transmitted up the structure to be resolved into axial pile loads. The grouted jacket has a direct downward load path for shear and moments. The novice designer would do well to learn this distinction early in his career.

When steel structures are designed for deeper water (in excess of 250 ft), pile-leg grouting is prevalent. Lateral wave loads that produce high base shear and overturning moments heavily influence deepwater jacket designs. Piles placed through the legs of the jacket are not always sufficient to transfer these loads to the soil; so "skirt piles" are added, normally in clusters around the corner legs. This adds a new dimension to the installation procedure. Pile guides are required up to water level, and a removable "follower" must be used during pile-driving operations. Grouting procedures for the skirt sleeve-to-pile must recognize that grout placement and inspection will be done remotely.

The template or jacket structure is a steel space frame that supports, above water, a superstructure comprising one or more decks for production equipment and facilities needed to support and maintain production. The production tasks may include separation of oil, gas, water, and sand; treatment and measurement of oil and/or gas for sales; and treatment of water and/or solids for disposal.

The facilities include utilities (i.e., electricity, fuel, instrument gas, power gas, water, and sewage); cranes; accommodations for personnel; workshops; control rooms; and safety systems for hazard detection, protection, and escape. Further, a helideck is usually provided. Often, a drilling derrick forms part of the equipment for drilling and maintenance of the wells. Sometimes, a flare boom is necessary for gas flaring. The accommodation/helideck facilities are situated as far from the potentially dangerous hydrocarbon process area as is physically possible. The production equipment and facilities are often called the topsides. To simplify installation and hookup at sea, the equipment and facilities are often placed in modules, which may weigh several hundreds to many thousands of tons. The modules are completely prefabricated and tested onshore prior to transportation and lifting onto the jacket deck(s) by offshore crane vessels.

The offshore structure shown in Fig. 14.14 is a modern example of a jacket structure designed for operation in 350 ft of water. The jacket structure is first placed on the seabed, and the foundation piles are driven through the pile sleeves (often called skirt piles) and grouted to form the support system for the structure. Often, it is only necessary to provide piles through the legs, depending on the environment and soil characteristics. In these cases, the piles are either grouted or welded to connect the piles to the jacket and permit the topside and jacket loads to be transmitted to the piles and into the soil.

The design of a jacket structure is a matter of determining overall dimensions based on water depth and functional requirements, evaluating hydrodynamic loads caused by waves and currents; evaluating topsides and wind loads; sizing of the structure to meet the state requirements for strength, fatigue, and serviceability; and sizing of the appurtenances. Design forces on jacket structures, shown as arrows in Fig. 14.15, can be calculated with specialized computer software available to the industry. The horizontal force from waves consists of drag forces from the kinetic energy of the water and inertia forces from the water-particle accelerations. An appropriate wave theory is used to calculate the water-particle velocities and accelerations. The total horizontal force is calculated by multiplying the projected area of the structural members with the water pressure. Jacket design is an iterative process because a number of design cycles are gone through before achieving the optimal sizing for a particular member to bear these horizontal forces. Most of the horizontal loads are directly related to the diameter of the tubular members and their locations within the structure.

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  Fig. 14.15—Typical design forces on conventional-jacket structures (courtesy of MSL Engineering).

The design of the foundation piles is also critical. There is significant interaction between the response characteristics of the jacket structure, its foundation piles, and the soil, such that pile-soil-structure interaction is explicitly catered for in the design recipe for jacket structures. Over the decades, the piles have grown in size (number, diameter, and length) in line with the jacket structures. Therefore, pile weight is an important part of total structural weight. For example, the Bullwinkle jacket structure weighed 44,800 tons, and the pile weight was 9,500 tons (i.e., the pile weights are a significant portion of the jacket weight, in this case, nearly a quarter of the structure weight). For small structures in shallow water, the pile weight may approach the weight of the jacket structure. The need for heavy hammers to drive large jacket piles has contributed to the development of semisubmersible heavy lift crane barges. Hydraulic hammers that operate underwater have superseded the early steam-driven hammers. A modern, high-energy hammer for 8-ft-diameter piles typically weighs around 160 tons.

Because the cost of piling is substantial, an alternative concept that has been developed is the suction pile, or bucket foundation, because its visual appearance is one of an inverted bucket. The suction pile is forced into the soil by the pressure difference over the bottom of the bucket as water is pumped out from within the bucket. While suction piles were originally developed to provide anchor points for single-point moorings, their use for jacket structures offshore Norway (Europipe 16/11E and Sleipner Vest) has encouraged their wider acceptance. The suction pile essentially comprises a plate, usually circular, and is surrounded and reinforced by a skirt. The Sleipner suction pile, for example, has a 45-ft-diameter plate with a 16-ft skirt depth.

Without exception, the construction and installation of a jacket structure plays a central role in its design. Steel jacket structures are prefabricated onshore prior to transportation to site by a barge. Although jacket structures can be, and have been, designed as self-floating for transportation (with subsequent systematic flooding for installation), the most popular installation methods are lifting or launching. Small jackets may be lifted in place by a floating crane vessel. Larger jackets may require flotation devices to assist in their installation. The flotation devices are subsequently flooded to enable the jacket to sink slowly into its final resting place.

A typical sequence of steps involved in the installation of a jacket structure by launching is shown in Fig. 14.16. A jacket structure being launched is shown in Fig. 14.17 and is consistent with Step 3 in Fig. 14.16. The jacket structure is placed horizontally on a flat-topped barge and towed to site. At location, the jacket is launched off the barge, uprighted using a crane vessel, and allowed to sink vertically to the seabed. Once located on the seabed, foundation piles secure the structure. An examination of the steps in Fig. 14.16 reveals that a number of critical factors must be considered as part of the jacket-design process:

• The weight of the jacket structure has to be less than the safe lift capacity at the construction facility if the jacket is lifted onto the barge rather than skidded.
• The jacket weight cannot exceed the capacity of the tow-out barge.
• The jacket has to be designed to withstand the loads involved during tow-out, transportation, and launching.
• The jacket has to be designed to float unassisted in the water following launch.
• The jacket is designed to be uprighted by a crane vessel, then sunk to the seabed with systematic flooding.

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  Fig. 14.16—Sequence for jacket installation by launching (courtesy of MSL Engineering).

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  Fig. 14.17—Jacket structure being launched (photographic Services, Shell Int., London).

An alternative to launching the structure is to lift it in position. Today, vessels with a lift capacity up to 14,000 tons exist, allowing most jacket structures to be lift-installed in a cost-effective manner. Use of twin cranes on a single vessel or use of two crane vessels is often deployed to provide the required lifting capability. Fig. 14.18 shows a jacket structure being lift-installed using two crane vessels. Once the jacket is secured with its foundation system, the topsides structure can be installed as separate modules or as a single integrated unit; see Fig. 14.19.

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  Fig. 14.18—Jacket structure being lift-installed (Photographic Services, Shell Intl., London).

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  Fig. 14.19—Topsides modules being lift-installed (courtesy of BP).

The benchmark design guidelines and standard for fixed steel structures is the American Petroleum Institute (API) RP2A, which was first published in 1969. In 2000, the 21st edition of API RP2A was released. This edition reflects good engineering practice, knowledge, and experience gained by the industry over the past five decades. Equivalent practices exist in other countries such as the U.K. and Norway. In following the development of the technology related to fixed steel structures and the historic achievements, two additional observations are worthy of note.

The first observation relates to the industry’s ability to manage and maintain the structural integrity of existing installations during the service life of the platforms. In this regard, in the 1980s, Amoco pioneered the "assessment engineering" approach for its fleet of platforms in the U.K. sector of the North Sea. Today, this approach is embraced by the industry worldwide and is reflected in recommended practices, design codes, and standards. The assessment engineering approach is integral to the integrity management of offshore installations. The process, illustrated in Fig. 14.20, ensures the cost-effective life-cycle management of offshore structures.

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  Fig. 14.20—Structural integrity management (SIM) process (courtesy of MSL Engineering).

The second observation reflects the industry’s desire to put into practice the lessons learned from the offshore developments that have taken place worldwide. In the 1990s in particular, the industry undertook a "self-assessment," particularly in light of the large number of undeveloped marginal fields in existence worldwide. This led to the concept of minimum facility platforms (MFPs), which aim to restrict the equipment and facilities on topside structures to the minimum required for production, minimize or eliminate the need for manned installations in light of improved flow-assurance technology, and minimize substructure arrangements without compromising robustness or safety.

A large number of novel and innovative MFP concepts exists at the present time, and sophisticated platform selection tools have been created to permit the most appropriate development options to be considered. Shell’s Skiff and Brigantine structures in the southern North Sea, for example, were designed to be installed using a jack-up rig with conductors placed through the legs and exploited as part of the foundation system. These platforms were also designed for sea access rather than helicopter access, thereby reducing the topsides facilities. The use of MFPs is set to grow over the next decade. The big prize for the industry is to develop MFPs that are self-installable, thereby removing the need for installation vessels.

Concrete Gravity-Based Structures

While the vast majority of fixed offshore structures utilize steel-jacket substructures to support the topsides facilities, a number of offshore installations utilize a substructure manufactured from reinforced concrete. As the name implies, concrete gravity-based structures rely on their own weight to resist the lateral environmental loads. These types of structures were pioneered by Norway, consistent with their design expertise, construction facilities, and construction skills that leaned heavily toward concrete rather than steel. Norway’s fjords provided the ideal sites to permit construction of these large substructures. Further, these substructures provide the advantageous option of using the gravity base for oil storage.

Fig. 14.21 shows an illustration of a concrete gravity-based structure (GBS). The topsides structure is similar to that for steel-jacket structures (i.e., it is either an integrated steel-deck configuration or is of modular construction with a module support frame). GBSs are constructed with reinforced concrete and consist of a cellular base surrounding several unbraced columns that extend upward from the base to support the topsides superstructure above the water surface.

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  Fig. 14.21—Concrete gravity-based structure.

The construction and installation of GBSs is entirely different from that employed for jacket structures. Fig. 14.22 shows a typical set of construction and installation steps for a GBS. As illustrated, the concrete bottom structure is constructed in dry dock. Once constructed, this is floated out and moored in a deepwater protected harbor. Completion by slip-forming of all the cellular base walls is undertaken in the harbor, followed by slip-forming of the towers in a continuous process; see Fig. 14.23. Once the towers are constructed and topped off, the whole structure is ballasted down to receive the topsides deck and modules. The completed platform is de-ballasted to a minimum draft for towing and is towed using tug boats to its final location and ballasted onto the seabed. The ballasting permits the skirts to penetrate into the seabed. Grouting is undertaken to fill any voids under the base. It can be observed that offshore hookup is minimized because most of the topsides equipment and facilities are commissioned onshore prior to placement on the deck.

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  Fig. 14.22—Concrete platform construction and installation (courtesy of MSL Engineering).

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  Fig. 14.23—Construction of the Troll platform (Photographic Services, Shell Intl., London).

An offshore GBS is large. Its size, and the large environmental forces, can cause design problems. The structural design requirements include the categories of material quality, strength, and serviceability. Most GBSs are designed for several functions, namely combined drilling, production, and oil storage. The design is targeted to offer least resistance to environmental loads while providing adequate support for the topsides structure. Typically, using a range of standards, the structure is designed to meet the criteria laid down for the ultimate progressive collapse, fatigue, and serviceability limit states. Prestressed concrete, as used for GBSs, provides good resistance to fatigue and corrosion. Prestressing is essential because it permits the concrete to act in compression at all times. Temporary loading conditions may very well govern the structural design. These temporary cases include construction in dry dock, construction in protected harbor, ballasting for deck installation, towing, and installation. Often, the cellular base walls are not pressurized; consequently, they must be designed to resist the substantial hydrostatic pressure imposed during immersion. Coincidentally, the ballasting of the GBS for deck installation prior to towing to site is often regarded as an effective, full-scale, inshore pressure test prior to offshore installation.

From a geotechnical standpoint, the parameters considered in foundation design include the type/extent of contact between platform base and seabed; stability against overturning and sliding; skirt penetration and grouting, to provide lateral sliding resistance and protection from scour; settlement; effects of cyclic loading on the soil; and soil-structure interaction.

The foundation aspects are considered individually and collectively as part of the design process for a GBS. The design and construction of the huge concrete gravity base structures represent a remarkable achievement by the offshore industry. However, the development of fields in the future using this technology may be limited, primarily in light of the trend toward subsea wells with long tie-backs and floating production systems.

Compliant and Floating Systems

As previously discussed, the majority of offshore fields have been developed with conventional fixed steel platforms. One common feature of fixed steel structures is that it is essentially "fixed" (i.e., it acts as a cantilever fixed at the seabed). This forces the natural period to be less than that of the damaging significant wave energy, which lies in the 8- to 20-second band. As the water depth increases, these structures begin to become more flexible, and the natural period increases and approaches that of the waves. The consequence of this is that the structure becomes dynamically responsive, and fatigue becomes a paramount consideration. Additional steelwork is required to stiffen the structure. From an engineering and economic perspective, cost-effective steel-jacket structures are extremely difficult, if not impossible, to design beyond 1,500 ft.

To circumvent this problem for water depths beyond 1,500 ft, the industry has developed concepts that work on the other side of the damaging significant wave energy (i.e., structures that have natural periods of greater than 20 seconds). These concepts include the following compliant towers for water depths up to 3,000 ft; tension leg platforms (TLPs) for water depths up to 5,000 ft with the potential for application to 7,000 ft following further development effort; floating production systems for water depths up to 7,000 ft; and deep draft floaters for water depths up to 10,000 ft.

Compliant Towers

Compliant towers are three-dimensional (3D) steel truss arrangements, which are slender and have a seabed footprint substantially less than an equivalent steel-jacket structure; see Figs. 14.6 and 14.24.

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  Fig. 14.24—Guyed tower concept (Photographic Archives, ExxonMobil).

The guyed tower concept (Fig. 14.24, adopted for the Lena platform in the Gulf of Mexico) and the freestanding compliant tower concept (Fig. 14.6, adopted for the Petronius platform in the Gulf of Mexico) are sized on the principle of "compliance" to wave attack. Vertical and lateral stability is assured through the use of either guys (Fig. 14.24) or flotation devices (Fig. 14.6). The dynamic response of a compliant tower is crucial, and dynamic analyses form part of the design process for this structure. Another design and engineering focus relates to the foundation pile design. As the structure deflects, significant tension-compression coupling forces are introduced in the piles. Locating the piles near the center of the tower, limiting the maximum tower deflections, and selecting piles of sufficient length to absorb the imposed loads can limit the resulting stresses in the piles. Compliant towers can be constructed using techniques that have evolved for steel-jacket structures. A two-piece construction and installation can be adopted, as was used for the Petronius platform installation.

Tension Leg Platforms

Fig. 14.25 illustrates the TLP concept. The topsides equipment and facilities are not dissimilar to those usually deployed for fixed steel structures. The platform comprises a deck structure and a buoyant hull that is composed of a series of vertical cylindrical columns, horizontal submerged pontoons, and, in some instances, tubular member bracing. The platform is tethered to the seabed by a number of tendons that are kept in tension at all times by the excess buoyancy in the hull. These tendons suppress the heave motions, and the tension ensures that the platform remains virtually horizontal even at lateral excursions of up to 10% of the water depth. Lateral excursions are controlled because the tendons develop a restoring force as lateral movements take place.

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  Fig. 14.25—TLP concept (Photographic Services, Shell Intl., London).

The tendons are secured in a foundation template piled into the seabed. The foundation system is subjected to cyclic loads superimposed on a high-tension load. Therefore, care is required in the analysis and design of the foundation system. Nevertheless, while the foundation system may appear elaborate, the advantages are considerable. The restriction on vertical movement permits the use of fixed-steel-platform-type wellhead equipment and rigid steel riser conductor assemblies.

The production risers may suffer from vortex-induced vibrations (VIV) caused by the current, especially in high-current regions such as the Gulf of Mexico and the West of Shetlands. Riser spacing design is therefore of prime importance; see Fig. 14.26. If the design principle were for no contact between the risers, a cost penalty in ultra-deep water would be expected. If contact between risers is the accepted design principle, then it is important during design to predict their dynamic behavior, predict the impact energy during contact, and define acceptance criteria.

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  Fig. 14.26—Riser spacing and contact considerations (courtesy of BP).

The TLP is not dissimilar to a semisubmersible, and construction techniques developed for semisubmersibles can be deployed for TLPs. However, the buoyancy requirements for a TLP may be two to five times that of a semisubmersible, and, therefore, construction facilities used for semisubmersibles may be too small for TLP fabrication. A TLP deck may be fabricated separately from the hull and mated in a manner similar to that adopted for concrete gravity base platforms. The benefit here is reduced construction time. Alternatively, a single-piece construction can be adopted for the deck and hull with equipment and facilities placed on the completed platform. In this instance, intermediate structural bracing can be accommodated because barge clearance is not required.

A number of options exist for the placement of the template(s) and piling. A single template for the foundation and well system can be adopted, or separate templates can be specified. Tendons may be attached to the template or directly to the piles. The advantages and disadvantages for each option are considered at the design stage from both engineering (redundancy, robustness, etc.) and economic standpoints.

Deep-Draft Floaters

A deep-draft floater is a floating system that is provided with a deep-draft hull designed to minimize heave motions. An example of a deep-draft facility designed by CSO Aker is shown in Fig. 14.27. This particular concept is more commonly known as a truss spar. Other forms of deep-draft floaters include deep-draft semisubmersibles and hull arrangements other than the arrangement shown in Fig. 14.27.

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  Fig. 14.27—A typical truss spar (courtesy of BP).

The concept shown in Fig. 14.27 has successfully been deployed for the Horn Mountain field and has been chosen for the Holstein field, both in the Gulf of Mexico. The upper section of the hull is a conventional cylindrical shell and provides the required buoyancy for the platform. A center well within the cylinder protects the production risers and their tensioning system. The lower section is a braced truss system with heave plates to achieve the desired heave motion characteristics. In common with all spars, the vertical risers support the dry trees at the topsides, thereby providing continuous access to the wells for re-entry. A keel section at the base of the truss is specified for buoyancy during towing and contains fixed ballast.

Mooring is achieved using a taut system of mooring lines composed of chain and wire or polyester. The lines are moored to the seabed using a vertically loaded anchor. The mooring system is designed to accommodate a platform offset of several hundred feet for drilling or workover purposes.

Typical fixed platform design practices are applicable for the topside configurations with the exception that, because the spar is a floating system, lateral accelerations are higher. A payload of up to 50,000 tons can be accommodated, including drilling or workover rig and full production equipment.

Deep-draft floaters, either of the cylindrical arrangement (such as spars) or of the semisubmersible configuration, are likely to find increasing favor in deepwater applications in the future. The systems can be designed for storage capability as well. The choice between these two and other floating production systems depends on the fundamental decision on the need for dry-trees or wet-trees, as discussed next.

Wet vs. Dry Trees

All the concepts discussed and described allow for the wellheads and Christmas tree valve systems to be above the waterline (i.e., in the dry). Dry trees allow direct and continuous access to the wells for maintenance and re-entry. The alternative is "wet trees," so-called because the wellheads and Christmas trees are placed on the seabed. These are sometimes referred to as subsea completions.

The size and type of reservoir and the anticipated extent and cost of well intervention often dictate the selection of dry vs. wet trees. The type of field development concept utilized, in particular the choice between wet and dry trees, significantly affects all aspects of the development, from the appraisal strategy and development concept to reservoir and field management.

A number of offshore platform concepts exist that meet the dry tree requirement. These include conventional jackets, spars, and TLPs. For wet trees, possible development concepts include all of these plus ship-shaped floating production systems and semisubmersible production systems.

Floating Production Systems

A floating production system (FPS) is effectively a floating rig. It contains all the equipment associated with a fixed platform and is used in conjunction with subsea wellheads to exploit moderate to deepwater fields, particularly where the installation of a fixed platform is neither practical nor cost-effective. For all floating systems, a range of stability criteria is followed to ensure system stability in calm waters with sufficient safety margins to allow for the dynamic conditions of stormy seas. The primary considerations for stability revolve around the location of the center of gravity and the relative location of the center of buoyancy; see Fig. 14.28. As the floating structure heels, it gives rise to a restoring moment, which stabilizes the system.

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  Fig. 14.28—Stability of floating systems (courtesy of MSL Engineering).

A conventional FPS typically uses either a semisubmersible to accommodate the equipment and utilities or a ship-shaped monohull, the latter often built from converted oil tankers. A spread of mooring lines is used for station keeping during production, and flexible flow lines are adopted, which permit wave-induced vessel motions to be absorbed.

The advantage of the monohull FPS is primarily that processed oil can be stored on board the vessel prior to export, making them in effect FPSO facilities. The main drawback for semisubmersibles is the lack of storage capacity to prevent shutdowns when offloading operations are disrupted.

As water depths increase, the length and, hence, weight of conventional wire and chain mooring systems increase. Floating structures must increase in size to provide the necessary buoyancy to carry the extra weight, which adds incremental cost to the development. Further, many of the conventional mooring systems are deployed in the catenary configuration, giving low stiffness, which allows considerable offsets and poor response. This is undesirable for operational reasons and often requires use of flexible riser systems to compensate for the movement.

To overcome the weight problems associated with wire/chain moorings, synthetic materials, such as polyester, are being evaluated and have been applied as a replacement for conventional steel ropes and chain mooring systems. They have less weight and, in the taut configuration, provide lower vessel movement and a reduced footprint on the seabed.

The interaction between risers and moorings is self-evident. One of the functions of the moorings is to guarantee the integrity of the risers, but moorings are subject to practical limits regarding their numbers and strength. Assessments for the risk of mooring failure should therefore reflect this unavoidable interaction between the adopted riser and mooring systems.

Deepwater riser systems have been acknowledged by the industry as representing critical technology for current planned and future field developments. Drilling and production risers can be of the top-tensioned arrangement. Load and fatigue limitations for these risers are a significant challenge. VIV can significantly reduce the fatigue life of both the riser and the wellhead. The matter of riser contact and clashing has been covered earlier in the TLP subsection. It should be recognized that the prediction of response for an array of top-tensioned risers is nontrivial, given the hydrodynamic interaction.

Flexible risers and steel catenary risers (SCR) are other systems available to the engineer. These systems are equally complex in design and in response predictions. Nevertheless, these systems add to the range of options available to develop deepwater fields.

One other noteworthy riser system is shown in Figs. 14.29a and 14.29b. This system has been deployed for the Girassol FPSO in West Africa in 4,500 ft of water. Riser towers allow multiple flow lines to be installed in a small area without interference with mooring lines and each other. They can be designed with very low heat loss coefficients to minimize flow assurance problems.

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  Fig. 14.29a—Schematic of FPSO.

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  Fig. 14.29b—Terra Nova FPSO (Photographic Archives, Petro-Canada/Terra Nova).

For FPSs, it is perhaps revealing to consider the approach adopted by BP in its currently ongoing field development evaluations for the deepwater Thunder Horse field in the Gulf of Mexico. A unique combination of characteristics is at play in the Thunder Horse field, dictating the facilities for the project. Located in water around 6,000 ft of water depth, the field’s reserves are contained within eight adjacent offshore license blocks, making it impossible to reach all reserves from a single drilling center. The reservoir itself lies deep below the seabed—some zones are more than 3.7 miles down; others lie below salt formations, requiring costly and time-consuming wells. Hydrocarbon fluids from the reservoir have extremely high temperatures and pressures, around 15,000 psi and 250°F. These are among the highest yet to be handled in the offshore industry. To maximize production, seawater must be injected into the reservoir from the outset. While this is standard industry practice, it has never before been executed at the injection rates and pressures needed for Thunder Horse. These and other factors have resulted in the selection of a semisubmersible production unit (see Fig. 14.9a), which will serve as a processing, drilling, and quarters platform for the field, supporting up to 40 production and injection wells. All wells, some local to the platform, others as far as 6 miles away, will be completed as subsea wells with wellhead control trees located on the seabed, tied back by flowlines and risers to the platform.

Several proven types of platform were initially considered, among them ship-shaped vessels, semisubmersibles, TLPs, and spars. Ship-shaped production vessels, although used extensively around the world, were ruled out because of riser load and the technical infeasibility of bringing fluids at high temperatures and pressures onto a weathervaning vessel using the industry’s standard solution of a moving swivel. TLPs carry the disadvantage that in water this deep, their rigid steel tendons anchoring the floating hull to the seabed become too heavy and costly. Spar platforms were looked at closely. Spars supporting the weight of the dry-tree steel risers and keeping these in tension becomes a critical factor. The high-pressure/high-temperature conditions on Thunder Horse also demand that the risers be heavy walled, adding to the weight problem. Another hurdle to overcome is at the top of the riser where the well fluids are transferred to the processing deck. On a spar platform, the relative movement between risers and floating platform is pronounced. The influence of this and other factors, notably the very large topsides load and the requirement for multiple well centers to access the entire reservoir, finally led to selection of a semisubmersible, but one with a difference—its scale. The Thunder Horse concept will be the largest production semisubmersible ever built, having a two-level deck measuring about 455 ft long and 360 ft wide, mounted on a four-column hull. The hull and deck, together with drilling facilities and quarters, will weigh more than 50,000 tons. The platform will be held on station by 16 mooring lines made of chain and steel wire rope. Each line will be anchored to the seabed by suction piles, giving the semisubmersible the ability to survive the Gulf of Mexico’s hurricanes.

Subsea Systems

Many hundreds of subsea wells are currently in service worldwide. Subsea characteristics include wellhead (see Fig. 14.30), and trees are installed on the seabed; well drilling or intervention requires vessels such as jack-up rigs or semisubmersibles; reservoir fluids are generally tied back to a host facility for processing and export; and utilities, control, and chemicals are supplied from the host facility via umbilicals.

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  Fig. 14.30—Subsea field development.

Subsea wells may be installed individually, in clusters, or on a template where the reservoir fluids from all the wells are channeled to a manifold that is tied back to a host platform. A simple template arrangement is shown in Fig. 14.31.

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  Fig. 14.31—Subsea template.

Often wellheads and wet trees are designed as "diverless" and more recently "guidelineless" because they can be installed, maintained, and repaired either by remote control using equipment that does not need guidelines or tools that are wire guided from a vessel. Fig. 14.32 shows a single-well diverless subsea production system.

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  Fig. 14.32—Diverless subsea production system.

The wellhead sits on a guide base on the seabed and acts as a location device for the Christmas tree. Attachment of the tree to the wellhead and flowline is by remote control. While referred to as new technology, the diverless wellhead has proven to be reliable. It has permitted the development of fields in water depths beyond the saturation diving limits and competes with diver-assist subsea wells in moderate water depths because of potential cost savings.

For multiwell templates, some cost savings can be realized during drilling because the vessel does not have to be relocated for each well. Further, major savings may be possible by transferring the reservoir fluids through one large flowline rather than individual flowlines. Well testing is accomplished by installing a separate flowline with a valve manifold for switching wells. Potential further cost savings may be possible for the control systems and piping for gas lift and water injection. However, one of the major hazards that must be considered at the design stage is dropped objects during drilling and the risks associated with producing from completed wells while the other wells in the template are drilled. If production from completed wells is not possible until all wells have been drilled, the potential cost savings may be negated through cash-flow considerations. One technique that has been adopted for combining some of the advantages of single and multiwell subsea systems is to produce moderately spaced satellite wells to a central manifold unit on the seabed. The manifold permits the reservoir fluids from the wells to be mixed and wells to be tested, and cost savings may be significant if the host facility is located miles away. Conventional welded steel pipe is used for most flowlines. The steel is protected against external corrosion by coatings, anodes, or both. An alternative for steel flowlines is the use of flexible piping that comprises laminations of steel wires and other materials. Although expensive in comparison with steel pipe, the costs may be offset by savings in installation cost. Flexible pipe, through use of large-diameter reels, can be installed relatively quickly and does not need a separate external coating. For further discussion, see the chapter on Piping and Pipelines in this volume of the Handbook.

Flow Assurance

The full scope of flow assurance is shown in Fig. 14.33. Flow assurance matters specific to subsea tieback systems are shown in Fig. 14.34. Flow assurance, by definition, focuses on the whole engineering and production life cycle from the reservoir through refining, to ensure with high confidence that the reservoir fluids can be moved from the reservoir to the refinery smoothly and without interruption.

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  Fig. 14.33—Full scope of flow assurance (courtesy of MSL Engineering).

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  Fig. 14.34—Flow assurance matters for subsea tieback systems (courtesy of BP).

Flow assurance is sometimes referred to as "cash assurance" because breakdown in flow assurance anywhere in the entire cycle would be expected to lead to monetary losses. A few specific flow assurance issues are discussed next.

It is necessary for sufficient pressure to be available to transport the hydrocarbons at the required flow rates from the reservoir to the processing unit. Matters that require consideration in this regard include pressure loss in flowlines, separator pressure setpoint, pressure loss in wells, artificial lift method selection, remote multiphase boosting, drag reduction, slugging in horizontal wells, gas lift system stability, and interaction with reservoir performance.

Components and systems should be designed and operated to ensure that flowrate targets are achieved and that flow is continuous. Issues to be taken into account include hydrate formation, wax deposition, asphaltenes, sand and solids transport, corrosion, erosion, scale deposition, interaction of slugging and pipe fittings, interaction of slugging and risers, relief and blow-down, pigging, liquid inventory management, and well shut-in pressure.

For multiphase flowlines, it is necessary for the process to be able to handle the fluid delivery, and consideration should be given to a number of issues including interaction with facilities performance, slugging (steady state), slugging (transient), slug-catcher design, severe slugging prevention, effect of flow rate change, temperature loss prediction, piping layout, remote multiphase metering, gas and dense phase export, oil and condensate export, and separator performance.

The need for well testing and overall production system optimization contributes to flow assurance issues. Significant advances have been made in this field. Flow assurance will continue to remain critical technology as deepwater developments progress and as longer tiebacks from subsea wellhead systems are considered.

Offshore Production Operations

Offshore production operations can be either very similar to or radically different from land-based installations.

Well Completions

Except for a few innovative installations, wellheads and Christmas trees on platforms are basically the same as for land wells (see Fig 14.35). Control valves, safety valves, and piping outlets are configured the same and use the same or similar components. Some of the valves probably will have pneumatic or hydraulic actuators to facilitate remote and rapid closure in an emergency. Also, some Christmas trees may have composite block valves instead of individual valves flanged together.

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  Fig. 14.35—Platform well bay.

The major difference, however, between land and platform well completions is the economics incentive on platforms to reduce equipment weight wherever possible and to minimize space requirements. Simply put, lighter, smaller equipment and more compact installations result in less expensive platforms. A good example is the use of composite block valves to reduce Christmas-tree size and weight. Another example is the spacing of wellheads, as close together as drilling operations will permit, with just enough room for safe and efficient operations of the tree valves, control valves, and well-workover equipment. Typically, this means centerline distances of 6 to 10 ft between wellheads.

Where only one drilling rig is on a platform, all the wellheads usually are located in one bay. Larger platforms that are designed to accommodate two drilling rigs may have two well bays (one for each rig) with two or more rows of wells in each bay.

Process Equipment

The primary function of process equipment, whether on a platform or on land, is to stabilize produced fluids and prepare them for shipping or disposal. Well production is separated into components of oil, gas, and water (and sometimes condensate). The separated fluids are measured and then either shipped, injected back into the reservoir, or flared.

Differences between the process equipment (oil and gas separators, free-water knockouts, gas scrubbers, pumps, compressors, etc.) installed on a platform and those installed on land are minor (see Fig. 14.36). Where possible, consideration is given to using vessels and machinery that are compact and lightweight (e.g., electric motors are commonly used instead of gas engines for driving pumps and compressors). Vertical clearance between decks may impose height limitations and dictate, for example, the use of horizontal instead of vertical separators.

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  Fig. 14.36—Platform deck layout for process facilities.

There is a major difference, however, in the way equipment is packaged. If it is to be installed offshore after placement of the platform jacket and decks, process equipment usually is built in modules at a land site. The module assemblies then are barged offshore, lifted onto the platform, and hooked up. This significantly reduces expensive offshore installation and hookup time. In any event, the equipment and its piping, wiring, and controls are installed as compactly as possible. The extra engineering and fabrication cost needed to reduce deck area to an absolute minimum are more than offset by savings in platform structure cost.

Well Servicing and Well Workover

On relatively small platforms with no more than 5 to 10 wells, it is common practice in some areas to drill all the wells before any of them are placed on production. The drilling rig is removed after the last well is drilled, and future well workover is performed with a portable workover rig well pulling unit. Downhole work that does not require pulling tubing (e.g., replacing safety valves, gas lift valves, or standing valves) normally is accomplished with a wire-line unit.

On larger platforms with more wells, drilling and production operations generally are carried on concurrently. In this case, the drilling rig performs well workover if it is still on the platform.

Crude-Oil Disposal

In the great majority of cases, crude-oil production is transported from platforms by subsea pipelines. Because most offshore producing areas involve multiple platforms and more than one operating company, the pipelines are generally common carriers.

Depending on pipe diameter, length, need for burial, need for coatings and cathodic protection, water depth, and various construction considerations, an offshore pipeline can be the single most expensive element of an offshore installation, sometimes far exceeding the cost of one or more platforms. In the great majority of cases, however, piping is still the safest, most economical way to transport crude-oil production to a land site.

Occasionally, an offshore oil field is too remote, production rates are too low, or the field is too short-lived to justify a pipeline economically. The alternative is to transport the oil using tankers. This usually requires some type of loading system installed 1 to 2 miles from the platform, such as a moored buoy or articulated loading tower. A seafloor pipeline connects the loading facility during the transfer of oil.

The two most important drawbacks of tanker-loading operations are sensitivity to weather and the need for separate oil storage. Tanker loading is best suited to mild weather areas to minimize downtime from storms. Oil storage requirements will depend on total field producing rates and reservoir characteristics (i.e., whether the wells can be shut in for short periods without lost productivity) as well as tanker downtime. This has led to the development of permanently moored storage tankers.

Gas Disposal

Disposal of gas from an offshore production site will depend on a combination of reservoir and economic factors. If well production is primarily oil, the gas may be handled as a byproduct and be disposed of in the most economical way. Piping the gas to a land site for sale and use as a fuel is generally preferred if it can be done economically. Injection back into the producing formation is a common alternative. This helps maintain reservoir pressure and conserves the gas for possible future sale. In some areas, gas flaring is still acceptable, but many countries now forbid it except for the short test periods and for the disposal of small amounts of residual waste gas.

Water Disposal

Produced water is normally cleaned so that it may be either discharged offshore in accordance with governmental regulations or re-injected into the reservoir. In either case, a combination of mechanical and chemical methods may be used to condition the produced water before disposal. Tankage and filtration are used to remove oil and other contaminants from the water. Chemical treatment is common to control bacteria and corrosion in injection wells.

Arctic

Production operations in the offshore artic regions are within the reach of existing technology. Procedures used onshore and offshore in less hostile regions, however, must be modified to meet the challenges of the harsh climatic conditions in the remote locations.

In the last decade, the major area of industry interest has been the offshore region of Alaska and Canada. The environmental conditions vary significantly in each of these regions. Major factors that affect normal offshore operations are the extremely cold temperatures, fog, gusty winds, short open-water season, permafrost, and the persistence of ice. The specific production system that is selected must be tailored to each unique combination of these factors to ensure safe oilfield development.

Environmental Conditions

Sea ice is the principal environmental factor in all of the offshore artic areas. The most abundant type of sea ice encountered offshore is less than 1 year old. This first-year ice begins to form during fall and grows to a thickness of 4 to 8 ft during the winter. Sheets of ice close to shore become landfast and remain locked in place throughout the winter. Beyond the landfast zone, the ice is kept in constant motion by wind, currents and, in some areas, the influence of the arctic polar pack. This dynamic movement causes shearing impacting between ice features that produce ridges of ice several miles in length. Ice ridges formed in this manner are called pressure ridges. Localized ridging around a grounded ice feature, the shoreline, or a structure is considered a rubble pile. In areas of extremely cold winter temperatures, the ice blocks within a ridge or rubble pile begin to refreeze into a contiguous feature. Depending on the conditions, the refrozen consolidated thickness could become several times larger than the first-year ice thickness.

The other major type of ice is not formed from the seawater but is freshwater ice from the glaciers of northern Canada. In the Arctic Ocean, the glacial fragments are called ice islands. These tabular-shaped features are several thousand feet in diameter and more than 200 ft deep.

Ice usually exerts the predominant forces on arctic offshore structures. Extensive laboratory and field tests have been conducted on small-and large-scale specimens to determine in-situ strength characteristics for design. From the results of these tests, the mechanical properties of ice are predicted. They consider salinity, temperature, crystallographic structure, and loading rate.

When ice is loaded at a very slow strain rate, it exhibits a plastic behavior. Loaded rapidly, it behaves as a brittle material. Empirical equations have been developed that relate the ice movement rate and shape of the structure or indenter to the strain in the ice feature.

The shape of the structure is also a primary factor in producing a crushing, buckling, or flexural failure of the ice feature. For narrow structures relative to the ice thickness, crushing is the predominant failure mode. As the width increases, a combination of crushing and buckling of the ice field around the platform results in the development of a rubble pile. The rubble pile will then shield the structure from direct impact of subsequent ice floes and ensure failure of the ice mantle away from the production facility. Sloping sided structures normally force a flexural ice failure. Because ice flexural strength is 20 to 40% of the crushing strength, an appreciable reduction in ice forces can be achieved when a bending failure is induced.

The wave conditions in the arctic are similar to other offshore areas, and the design of structures against wave loading is well established. Near-shore sea states can be defined by determination of the open-water area along the storm route or fetch and the water depth. In the Arctic Ocean, the presence of the sea ice and the polar pack limits the open-water fetch for storms to generate and consequently reduces the design wave height.

Permafrost is soil at a temperature below 32°F with partially or completely frozen pore water. Drilling and production operations in areas with permafrost have been well defined from experience of the Prudhoe Bay field. In most near shore areas of the artic, permafrost has been found at or near the mudline. These soils are very stiff and can make excavation for pipelines or driving of piling nearly impossible. Permafrost normally is soil bonded by ice and is very susceptible to change in temperature. This can result in significant changes in the soil characteristics and must be considered in the design.

Production Structures. Artificial Islands. Artificial islands already are used in many shallow-water areas throughout the world for permanent drilling and producing facilities. The islands that are currently being used for drilling in the arctic consist of either unretained or retained beach slope systems, as shown in Figs. 14.37a and 14.37b. Because of the short summer construction season and, in some areas, the lack of island fill material, the quantity of fill required for the island should be minimized. The minimum island working surface is determined by the area required for drilling and production operations. To reduce the quantity of island fill, the steepest side slopes that the mode of construction and fill material will allow should be provided. The minimum side slopes of unretained islands depend on whether the island is constructed by summer dredging or winter transport of onshore borrow material over the ice to the desired location. The side slopes for summer dredging are approximately 1:20 (vertical to horizontal), and for winter construction are 1:3. On completion, sandbags or concrete mats are placed on the exposed slopes of the island to prevent ice and wave erosion. Sandbags, stiffer soils for embankments, or caisson units are used on retained islands during construction to reduce the required volume of fill. The caisson units typically consist of vertical walled concrete or steel units. The caisson also provides easy access to the island as a dock for resupply and could be used for storage of consumables or oil.

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  Fig. 14.37a—Protected slope production islan (Sandwell Engineering Inc., Vancouver).

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  Fig. 14.37b—Caisson-retained production island (Sandwell Engineering Inc., Vancouver).

Artificial islands must be designed to withstand the horizontal forces exerted by ice. The potential failure modes of the island consist of slope instability, bearing failure, or horizontal shearing of the island near the waterline. Each of these failure modes can be predicted by classic geotechnical analysis. The only variable in the analysis is the properties of the island fill material. During winter construction, the fill is delivered to the site at the cold ambient temperature and dumped into the sea. Ice forms on the granular material and inhibits consolidations. As the island surface thaws, considerable settlement may take place. To minimize the effects of thaw settlements, thermal analysis of freezing and thawing interface should be conducted to determine the proper graduations of fill material.

The design of production facilities placed on an island is similar to that on land. Equipment foundations must be designed and insulated to reduce the potential for frost heaving, pile jacking, and thaw settlements from seasonal thawing and freezing of the island surfaces and, in some areas, subsea permafrost. To prevent thaw settlement, an artificial refrigeration system for the fill material could be installed. Placement of equipment and accommodation modules should account for predominant wind, ice movement, and wave directions to ensure safe year-round operations.

Gravity Structures. Various types of gravity structures are being proposed for use in the arctic. Many of the conventional gravity structures that are used in the North Sea are being adapted for the deepwater and moderate-ice-concentration areas. In the more hostile areas of the high arctic, vertical- and sloping-sided gravity structures are being proposed. These structures provide the large deck load and space requirements, protection of the wells within tower shafts, and storage of oil. Because of the extreme winter ice conditions in many areas, the production facilities will have to operate nine months without major resupply.

The vertical-sided structures (Fig. 14.38) are proposed for the shallow, near-shore areas in the arctic. These structures typically are rectangular or hexagonal and are capable of being installed directly on the seabed or subsea berm. Production equipment can be placed directly on the working surface of the top slab or integrated into the hull of the structure. Wells are drilled and produced directly from the deck of the structure. Because of the large width of this concept, the structural integrity of the system is not sensitive to local discontinuities in the seabed from ice gouges or settlements in the foundation from local degradation of permafrost.

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  Fig. 14.38—Vertical-sided structure (Brian Watt Assocs., Houston).

Conical, sloping-sided structures (Fig. 14.39) are being proposed for the deeper-water, dynamic-ice-movement areas. This geometry induces flexural failure of the ice features and is relatively transparent to pack-ice movements. The deck is fully outfitted with processing equipment before it is mated with the structure. Wells are confined to a central moon-pool area in the cylindrical throat. Consumables and oil can be stored in the base.

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  Fig. 14.39—Arctic mobile drilling structure – sloping-sided structure.

Piled Structures. Piled steel structures have been developed primarily for the Bering Sea area of offshore Alaska. These structures are similar to conventional template or jacket concepts but must be modified to resist annual sheet-ice loading. A typical geometry is shown in Fig. 14.40. The platform concept consists of four or eight main pile legs with intermediate bracing of the legs omitted in the ice-loading zone near the waterline. Well conductors and oil-transport lines are positioned within the legs of the platform for protection from ice loading. This requires close spacing of the wells and, in some cases, completion of the wells at different levels of the deck. Diver access tubes may also be located in the legs to facilitate the repair and inspection of subsea components of the platform during complete ice coverage.

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  Fig. 14.40—Piled structure.

In most other arctic areas, pile structures are not practical. Subsea permafrost makes pile installation nearly impossible. The short construction season also does not accommodate the installation, pile driving, and placement of the topsides modules in one season. Also, the hookup and commissioning of the production equipment modules would be very expensive in these remote areas.

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. 14.38 describes some of the deepwater facilities and subsea technology issues.

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

• 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.

References

SI Metric Conversion Factors

ft	×	3.048*	E – 01	=	m
°F		(°F–32)/1.8		=	°C
mile	×	1.609 344*	E + 00	=	km
psi	×	6.894 757	E + 00	=	kPa
ton	×	9.071 847	E – 01	=	Mg

*

Conversion factor is exact.