Vol. No. 8

August 1999

Frontiers of Technology

Subsea Completions

Enabling Early Production From Deepwater, Remote, and Marginal Fields

While subsea-well completions occupy a small niche in the offshore petroleum industry, their evolution has attracted a lot of attention because they offer a means of producing field extremities not reachable by directional drilling from existing platforms. Also, they offer production options where field economics do not justify the installation of one or more additional platforms.¹

During the past four decades, subsea-well-completions technology has grown from untested engineering theory to viable, field-proven equipment and techniques that are accepted by the petroleum industry and the governments of producing countries. In the 37 years since the first systems were installed, approximately 1,100 subsea wells have been completed. Two-thirds of those wells are still in service. Among these completions is a variety of configurations that includes single-satellite wells, which employ subsea trees on an individual guide base; subsea trees on steel-template structures with production manifolds; and clustered well systems, which are essentially single-satellite wells connected to a nearby subsea-production manifold. All of these configurations typically are tied back to platforms, floating production and storage vessels, or even to shore.

Subsea-Completions Technology Evolves

Historically, water depth and cost have consistently challenged operators engaged in exploration and production in the world’s offshore areas. In an effort to handle both of these challenges, producers deemed subsea completions their most economical choice.

For years, water depth alone was the driver of the development of subsea equipment due to the physical limitations that become increasingly difficult as depth increases. However, in more recent years, cost has become an additional driver as lower oil prices have mandated that companies receive more value for their deeper-water investments. A third historical driver has been the speed with which subsea completions can be installed to establish a stream of revenue for operators.

“The greater emphasis on using subsea completions has been to produce marginal fields to existing platforms…,” stated industry expert Harvey Mohr in 1989 and 1991 trade-journal articles on subsea-well completions.² “With emphasis on producing in deeper and deeper water, the need to bring fields on stream economically greatly enhances the attraction of subsea completions.”³

During the 1960s, wellhead components that enabled operators to get their newly drilled subsea wells on stream were among the first pieces of subsea-completion hardware to emerge from supplier drawing boards. During this period, the first subsea trees were placed on the floor of the Gulf of Mexico (GOM). Of the 68 subsea completions installed in that decade, virtually all were in U.S. waters. Wells were tied back to fixed platforms in maximum water depths of 400 ft (189 m). Subsea trees took on a strange appearance as through-flowline (TFL) technology was developed to provide a means of sending downhole tools into the completion.

The 1970s and early 1980s saw subsea production activity increase in all parts of the world. Rising crude prices led to a frenzy of offshore-development projects. Investments in production facilities reached huge proportions. During this period, the first subsea-tree system was installed totally below the seabed. It was part of a caisson completion system that involved the installation of a master-valve block within a caisson below the sea floor to protect the well and its components from icebergs. TFL technology improved, and completions were extended to 650-ft (221-m) water depths during the period. Also, the pull-in flowline-connection technique was developed to allow completions to produce back to remote facilities. During the late 1980s and by the early 1990s, advancements in the technology necessary to economically develop deepwater oil and gas fields using floating production systems and subsea satellite installations were developed. Also, the first horizontal tree was installed and a modular approach to design emerged, as operators pushed suppliers to develop interchangeable modules that used field-proven components to bring more cost-effectiveness to early-production projects.

Diver/Diverless Installation Techniques Evolve

Even though deepwater exploration successes were yet unknown, much of the early development of subsea-completion technology focused on diverless techniques, as operators anticipated future deepwater requirements. Meanwhile, operators wasted little time in using industry-proven diver-assist technology for installing their subsea-completion equipment in shallow-water fields. By using surface hardware adapted to diver-assist underwater use, subsea-field completions progressed off North America from 1961 to 1970. Gradually, subsea technology evolved as refinements and improvements were made on the basis of field experience.⁴

In the 1970s, an offshore pilot test of a deepwater (170 ft, 52 m) subsea system was conducted on West Delta Block 73 in the GOM. While it was still accessible to divers, this test project demonstrated the capabilities of diverless technology to install, operate and maintain a remote, deepwater production system from field development through abandonment. In 1971, four subsea-well completions producing to a jackup rig were installed using diver-assist technology in 250 ft (76 m) of water in the Ekofisk field. This marked the beginning of subsea-well completions in the North Sea.

Wet vs. Dry Environments

During the 1970s and 1980s, both wet- and dry-environment technologies were developed. Wet technology was developed and installed first, since it was easy to take off-the-shelf equipment and install it in a subsea environment. However, the wet environment exacted a maintenance toll that led to the development of dry-environment technology. This technique employs steel chambers to provide a dry, 1-atmosphere environment for standard oilfield equipment. Maintenance is performed by transporting men from a surface support vessel to the seafloor chamber in a service capsule with a lift line and a life-support umbilical. Of the two technologies, operators eventually opted for the wet environment. Since that time, it has been the only method used.

Completions in U.S. Waters

In the mid-1950s, initial work began on the first remote underwater drilling- and completion-system project for the GOM. This marked the start of what was to become the petroleum industry’s first subsea-wellhead completion. Installed in 1961 in the GOM’s West Cameron Block 192 in 55 ft (16 m) of water, the completion set the stage for future production in deeper offshore waters.

At about the same time, the first full-field subsea development occurred when 20 subsea satellite wells with multiple-zone completions were installed and connected to a platform at California’s Conception field. Over the years, numerous projects have produced technical milestones in the evolution of subsea-completion technology. Many of these projects are well known because of the publicity that has surrounded them from their inception. U.S. achievements include the following.

Mensa

During late 1997, work began on the Mensa project. Extreme water depth, high flow rates, and erosion-resistance requirements made this project a pioneer in subsea-tree design and installation equipment/technique.

Located on Mississippi Canyon Block 687 some 147 miles southeast of New Orleans, the Mensa gas-well-development plan initially used three satellite wells with 10,000-psi working pressure and guidelineless, diverless subsea trees, which produce to a subsea manifold 5 miles away. A single 63-mile flowline (world’s longest offset from a host platform) carries the commingled production from the manifold to a shallow-water platform.⁵

Troika

Clustered subsea-completion developments arrange wells around, but keep them separate from, a central manifold structure. Such systems employ the drilling rig to install the inherently smaller system components.

The Troika system is a subsea cluster-type development that was installed in 1997 in 2,700 ft (823 m) of water in the GOM. The manifold is tied back to, and controlled from, Shell Oil’s Bullwinkle platform (approximately 14 miles distant) by means of two 103/4-in. flowlines. Among other things, this project accomplished the cost-effective installation of a subsea cluster-system module (combined template/ manifold) using the rig’s drillstring. By maneuvering the carrier under the rig’s moonpool, lifting the module off the boat using slings attached to the drillstring, and then lowering it onto preinstalled piles on the sea floor, the module was set in less than 12 hours.

Gyrfalcon

In March 1997, a gas well was abandoned in the mudline beneath 883 ft (269 m) of water on the GOM Green Canyon Block 20. The well tapped marginally economical reserves, but completing it was deemed uneconomical because its shut-in surface pressure exceeded 12,000 psi. Such pressures dictated a structure for which the capital cost would exceed the value of the expected reserves. Also, as of that time, no high-pressure subsea completions had ever been accomplished.

Two years later, in 1999, another operator is attempting to breathe new economic life into the well. The resulting completion will be the world’s first 15,000-psi subsea well completion. Expected to come on stream in mid-2000, the achievement will be known as much for overcoming the previous operator’s economics-killing costs as for its high pressures.

North Sea Development

Historically, the most active area for subsea completions has been the North Sea. Some 40% of all subsea-tree installations worldwide have been done there.⁶ Both the U.K. and Norwegian sectors have seen numerous subsea completions, but the most ambitious projects traditionally have been in Norwegian waters.

Ekofisk

In 1971, North Sea subsea completions originated with the Ekofisk field early-production system. It consisted of four subsea satellite wells producing to a jackup drilling rig modified for production processing with offloading to shuttle tankers.⁷ This was the first North Sea field development using subsea trees and the first use of subsea-well completions. Situated in 230 ft (70 m) of water, the wells were completed with diver-assist technology that was well established by this time.

Argyll

The development of the Argyll field in 250 ft (76 m) of water marked the world’s first application of a floating production system (FPS) and the first production of oil from the U.K. sector of the North Sea. The field began in 1975 with four satellite subsea wells flowing to a subsea riser base beneath an FPS vessel. Soon, more wells were added. Eventually, two additional fields were produced over the project’s life. The project was abandoned in 1992.

Buchan and Balmoral

In 1981, the Buchan field was developed in 390 ft (119 m) of water using an FPS and an arrangement of satellite and template subsea wells tied to a subsea manifold. The Balmoral field came on stream in 1986 using an FPS and subsea-well system that included satellite and template wells producing to multiple subsea manifolds.

Snorre and Åsgard

In 1992, the Snorre field was developed in 1,100 ft (335 m) of water using subsea completions to produce to a tension-leg platform approximately 4 miles away. The Åsgard field, developed in the late 1990s, featured a total of 59 subsea completions grouped together in 17 standardized four-well templates connected and tied back by pipeline bundles to floating production and processing vessels in 984 ft (300 m) of water. The Åsgard’s SO3 pipeline bundle includes closed-circuit, hot water heating lines to ensure that hydrates and paraffins do not form. This technology was first applied in the early 1990s in the Britannia gas field in the North Sea.

Numerous other subsea-well systems have been completed in the North Sea since these fields were developed, and a variety of designs and configurations have emerged. Traditionally, U.K. water depths have favored diver-assist technology, but some developments in the deeper waters of the Norwegian sector required diverless technology.

Offshore Brazil

In addition to North Sea and U.S. offshore fields, much of the historical development of subsea-completion systems has been offshore Brazil, mostly in the Campos basin. Petrobrás, the state oil company, is the most active operator worldwide in terms of the total number of subsea completions, with 329 installations so far and another 250 planned for the 1999–2004 period.

In 1974, Brazil found itself in an ironic situation. The nation’s daily production was decreasing in spite of an increase in reserves from new discoveries in the Campos basin. To correct this, early-production systems were planned to reduce the time to initial production, to better define the reservoir conditions, and to improve cash flow.⁸

“Subsea completions provided a means of achieving these needs,” said Ricardo Juiniti, Senior Staff Petroleum Engineer for Petrobrás. “The first completion was installed in 1977 in the Campos basin’s Enchova field. This completion was located in 384 ft (117 m) of water and produced from a single satellite well through a subsea test tree to the semi-submersible Sedco 135D, the first drilling vessel in Brazil to be converted to a floating production facility. Two years later, the first subsea tree was installed at 620 ft (189 m). From 1979 to 1981, seven early-production systems with wet trees were installed to accelerate Campos basin production, while seven fixed platforms were being built.”

With discoveries in water depths deeper than 656 ft (200 m) came the routine use of floating production vessels as economical and feasible alternatives to fixed platforms. Initially built to accelerate production, many of these temporary-use vessels became permanent installations.

“Dry-environment technology was used in the Garoupa and Namorado fields beginning in 1979,” Juiniti states. “Initially, dry chambers were installed on eight wells in 394 to 525 ft (120 to 160 m) of water, but the technology was deactivated in 1986 due to the high risk associated with performing well interventions through the chambers and excessive operational costs associated with using a dedicated vessel. Those wells are still producing with wet trees.” The development of all other Brazilian fields used wet-environment technology.

By the end of 1982, 32 non-TFL, 4-in.¥ 2-in.¥5,000-psi wet trees had either been installed, were being installed, or were on order. Four different manufacturers were used to allow a performance comparison of the different tree designs. The first subsea manifold also was installed during 1982, and it introduced a variety of new options for subsea layouts. The manifolds were diver-assist installations and could accommodate up to eight wells.

“By 1984, movement toward deeper waters necessitated the installation of subsea trees in depths that exceeded the limits of divers. This forced us to go to diverless installation methods,” Juiniti recalls. “But problems with the pull-in of flowlines prompted a decision by management to pull in tree flowlines in waters up to 985 ft (300 m) deep using diver-assist only, when feasible. Remote flowline pull-in would be used only when diving was not possible or was too expensive.”

Discoveries in the 1300-ft (400-m) Marimba, 1,900-ft (600 m) Albacora, and 3600-ft (1100-m) Marlim fields caused Petrobrás to develop the Lay Away System for pulling in tree flowlines and, later on, the guidelineless (GLL) subsea tree.

“We used this technology to install the first GLL tree in 1991 in 2,366 ft (721 m) of water and subsequently to develop the Marlim field,” Juiniti continues. “The Marlim field development, which will comprise 148 subsea wells producing to six floating production units, when completed, contributed to the development of a standardization program for GLL subsea trees as well as more effective and less costly diverless flowline pull-in. In 1994, the first installation of a GLL tree in 3,370 ft (1,027m) of water was made, a world record at the time.”⁹

Petrobrás also set the world record for a subsea-tree installation when it installed a subsea tree in early 1999 on a well in the Roncador oil field in the Campos basin. The subsea tree was set in 6,080 ft (1853 m) of water and produces via a rigid riser to a dynamically positioned floating production, storage, and offloading vessel.¹⁰ All these achievements were obtained after massive investments in research through ProCAP 2000, Petrobrás’ Technological Innovation Program on Deepwater Exploitation Systems, which aims at steep reductions in production costs and increased productivity in deepwater fields while enabling oil production at water depths greater than 3,281f (1000)m.

According to Ronaldo Dias, head of the Campos Basin Drilling and Completion Div., the investment made by Petrobrás in subsea completions allowed the company to develop offshore fields in a very profitable way by reducing the time to initial production.

“The standardization of Christmas trees played an important role in terms of reduced cost and project optimization,” says Dias. “Nature didn’t give us much choice. We had to go for the oil, which was much deeper than we would have liked. Subsea completions seemed to be the best solution, although we had a hard time making them work properly sometimes. However, I think it was worth the effort.”

The Future

The DeepStar project, an R&D consortium operated by Texaco that seeks the development of low risk methods of producing oil and gas in the deepwater GOM, is espousing what could become the deepwater-completions philosophy of the future. “If development of deepwater fields is to proceed, operators have to be convinced that they have commercially viable development options,” said Texaco’s Steve Wheeler, who has been involved with DeepStar since its inception. “These options must maximize the operator’s ability to avoid large capital commitments prior to his verification of acceptable reservoir performance.”

“DeepStar’s consortium of 21 operating companies and 40 supplier organizations are cooperating to find solutions to the challenges that face them in developing the deepwater Gulf of Mexico.¹¹ The project seeks to utilize partnering to jointly explore and research deepwater production technology, hardware and software, innovative tools, centralized processing facilities, production-sharing operations, and other innovative concepts,” stated Wheeler.

“We believe that subsea completions will play a key role in helping manage risk in future deepwater-field development. Since about 60% of the cost of a subsea development is built into the well cost, they can be scaled up or down quickly. Therefore, they offer operators a way of managing their costs in new fields where reservoir performance, production rates, and size are unknown. They can’t do that with other field development concepts, such as high-cost deepwater FPSs,” Wheeler said. “We’ve named this the ‘inchworm’ philosophy. Unlike a lot of deepwater field-development philosophies, our research indicates that operators should progress slowly by drilling and completing only a few wells initially in a new deepwater field. Next, they should place them on production using subsea completions and tiebacks to existing GOM infrastructure in order to establish an early-production revenue stream. Once the size of the reservoir and other important performance parameters have been determined, the operator can then expand to the level of development that is deemed appropriate. This philosophy protects capital by lowering overall risk until the field’s parameters are fully known.” Also, Wheeler and his DeepStar participants are pushing for the standardization and modularization of subsea-completion components because it speeds up field development and often reduces costs.

Most operators agree that subsea-completion standardization is an irreversible trend. Like Wheeler, they believe standardization of interfaces will, for example, allow the replacement of a damaged subsea tree with a new one “off-the-shelf” without lengthy interruptions to the well’s production, thereby saving revenue that would be lost while waiting on a “tailor-made” tree.

“We want standard interfaces between vendor components that will allow us to prebuild subsea trees,” Wheeler said. “Then we will stock them so they are ready when we need them. That’s cost-effective for us, and it allows our vendors to better manage their manufacturing efforts.”

Traditionally, the decision to develop an economically marginal oil or gas field and the choice of a production system has been governed largely by the presence of available infrastructure, existing technology, and the cost-effectiveness that can be obtained by marrying both. However, emerging technology is now playing a role equal to or greater than existing infrastructure and cost in the development of 5- to 20-million bbl fields. Looking to the future of subsea completions means looking back at the technology that has been proven during the past four decades and then finding better, more cost-effective ways of applying this technology to solve new, more complex challenges.

“The greater emphasis on using subsea completions has been to produce marginal fields to existing platforms…”

References

Bradley, H.B.: “Chapter 18: Offshore Operations,” Petroleum Engineering Handbook, SPE, Richardson, TX (1987) 30.
Mohr, H.O.: “Forecast & Review: Subsea Completion Planners See an Active Future,” Ocean Industry, Gulf Publishing Co., Houston(1991) 46–50.
Mohr. H.O.: “Subsea Completions: Steady Activity Trend Continues,” Ocean Industry, Gulf Publishing Co., Houston, TX (1989) 36–39.
Hansen, R.L. and Rickey, W.P.: “Evolution of Subsea Production Systems: A Worldwide Overview,” JPT (Aug. 1995) 675.
Da Costa, M. and Hartley, H.J.: “Mensa Project: Subsea-Tree System,” paper OTC 8579 presented at the 1998 Offshore Technology Conference, Houston, 4–7 May.
“Global Subsea Well Production Will Double by Year 2000,” Offshore (Dec.1997) 58.
Jobin, T.J.: “Subsea Well Development and Producing Experience in the Ekofisk Field,” JPT (April 1978) 513.
Armando, S.: “Petrobrás Early Production Systems,” 1982 International Meeting on Early Production Systems, Rio de Janeiro, 8–10 May.
Silva, C.H., et.al.: “Marlim Field: The Evolution of Subsea Techniques and Hardware,” paper OTC 10718, presented at the 1999 Offshore Technology Conference, Houston, 3–6 May.
Henriques, C.C.: “Roncador Field Early Production—A 2000-Meters-Water-Depth Challenge,” paper OTC 11070, presented at the 1999 Offshore Technology Conference, Houston, 3–6 May
“DeepStar: Tackling the Challenges,” Oil and Gas Investor, Houston (May 1999) 37.