FLOATING PRODUCTION SYSTEMS PROLIFERATING AROUND THE WORLD

Dec. 7, 1992
Use of floating production systems (FPS) in offshore oil and gas development is proliferating around the world. The technology embraces conventional production platforms and subsea wells tied into floating storage/processing systems, drilling rigs converted to production use, and more exotic approaches involving tension leg platform (TLP) and guyed/compliant tower designs.

Use of floating production systems (FPS) in offshore oil and gas development is proliferating around the world.

The technology embraces conventional production platforms and subsea wells tied into floating storage/processing systems, drilling rigs converted to production use, and more exotic approaches involving tension leg platform (TLP) and guyed/compliant tower designs.

FPS technology has been in commercial use almost 25 years, but widespread application did not take off until the early 1980s, when the combination of depressed oil prices and advances in deepwater technology made FPS designs more attractive. Low oil prices mandated a new approach for developing oil and gas in deep and ultradeep waters because fixed platform costs had risen to the point that only supergiant oil fields were likely to see development. At the same time, petroleum companies benefited from the oil boom of prior years to plow more money into deepwater technology research. The technology also was driven by the need for more cost effective solutions for developing marginally economic oil and gas reserves in proven basins, such as the North Sea and off Australia.

While much FPS activity has occurred off Australia and Northwest Europe, Brazil has done more than any other nation to push the deepwater frontier. And more U.S. operators, including independents, are turning to FPS schemes to develop deepwater strikes in the Gulf of Mexico.

The FPS push provides a benefit for the service side of the industry as well. Increasingly, operators are turning to conversions of semisubmersibles and other mobile offshore drilling units (MODUS) for FPS use as conversion economics and flexibility of design improve. That puts to work rigs otherwise idle in a perpetually under-utilized market.

The very nature of the global petroleum industry today, with its emphasis on reducing costs, maintaining flexibility, and seeking innovative solutions, ensures that FPS systems will enjoy even greater application into the next century.

GULF OF MEXICO

Most Gulf of Mexico operators are awaiting higher oil and gas prices before beginning to develop deepwater prospects that likely would involve installation of FPSs.

A handful of companies has begun developing some of the gulf's larger deepwater discoveries, resorting to such options as TLPs or guyed or compliant towers.

Depending on reservoir requirements, TLPS, compliant towers, and other FPSs are economic at water depths of 800-1,200 ft. In addition, proven production technology is available to operators for applications in water as deep as 2,000 ft.

Reserves of most discoveries in the Gulf of Mexico generally are far less than 100 million bbl of oil equivalent (BOE), considered the economic threshold for deepwater development with fixed steel pile platforms. Consequently, as operators study prospects in ever deeper water, FPSs are becoming more economically attractive.

Excluding projects already under way, major company developments in ultradeepwater likely won't get under way in the Gulf of Mexico until the late 1990s. But several projects operated by smaller, independent companies are set to come on stream sooner, at least one by early 1993.

Not all deepwater discoveries in the Gulf of Mexico are marginally economic. Development of some fields is being delayed because a few companies are trying to sort out project portfolios according to internal schedules and capital requirements.

Studies indicate deepwater oil and gas fields in the Gulf of Mexico are competitive with prospects elsewhere in terms of reserve exposure, per barrel cost, or other performance measures. And economics of various deepwater production systems are comparable for applications in water 600-1,200 ft deep.

However, as operators look at deeper water locations, costs associated with water depth and the number of wells required for development increase substantially. In fields with moderate reserves-less than 100 million BOE-and in water deeper than 1,500 ft, FPSs gain an advantage.

Lower development costs and moderately sized reservoirs mean more FPSs inevitably will be deployed in the Gulf of Mexico.

Most FPSs working in the gulf by 2000 will be converted MODUS. But ultradeep prospects with large reserves could prompt some major companies to experiment with untried concepts, such as the Spar FPS.

MAJOR COMPANY PROJECTS

When Shell Offshore Inc. in 1993 installs Auger TLP in about 2,860 ft of water on Garden Banks Block 426 and begins producing, it will set a deepwater production record in the gulf.

Shell estimates Auger development costs at more than $1.3 billion. At its peak, Auger is expected to produce about 40,000 b/d of oil and 150 MMcfd of gas. Ultimate recovery is estimated at 220 million BOE.

Major companies are studying several other deepwater discoveries. Among them, Chevron Corp.'s Vancouver project in more than 2,700 ft of water on Green Canyon Blocks 161 and 205 could begin production by 1997-98, once a development scheme is finalized.

Amerada-Hess Corp. and Oryx Energy Co. have yet to settle on a development plan for reserves estimated at more than 100 million BOE, confirmed earlier this year on Garden Banks Block 260.

But of 10 large oil and gas discoveries in the Gulf of Mexico in 2,000-6,000 ft of water, only Shell's Auger field is under development.

ENSERCH DEVELOPMENT

Enserch Exploration, Dallas, chose an FPS to develop reserves estimated at more than 40 million bbl from a 24 slot subsea template in 2,100 ft of water on Garden Banks Block 388, about 15 miles from the site of Shell's Auger TLP.

Enserch expects production to begin sometime in 1995 and peak in 1999 at about 120 MMcfd of gas and 40,000 b/d of liquids.

Enserch still is studying the development scheme for Garden Banks 388. The company has reached tentative agreements to buy the production riser used by Placid Oil on Green Canyon Block 29 and Biscay 1 semisubmersible to convert to an FPS for the project. Enserch Senior Vice Pres. Richard Kincheloe said the production system Enserch is using at Garden Banks 388 is similar to that of Placid Oil Co.'s Green Canyon 29 deepwater project.

"As far as the reservoirs go and our recoveries there, that was an ill fated project," Kincheloe said of the Placid led project. "But the production system worked fine."

Kincheloe said Enserch will be able to defer some incremental drilling costs on Block 388 because the tract's FPS will have drilling capabilities.

Enserch's plan to drill delineation wells after the FPS is installed could make it the first exploratory drilling from an FPS in the gulf.

DEEPTECH PLANS

Another independent, DeepTech International Inc., Houston, by summer 1993 expects to be producing gas from a single well on Ewing Bank Block 914, part of a multitract leasehold straddling the Flex trend in the central gulf.

Water depths in the Gulf of Mexico increase quickly over the Flex trend, from about 600 ft along the lower edge of the Outer Continental Shelf to more than 2,000 ft in the gulf's deep water.

Harry Briscoe, president of DeepTech, said his company earlier this month was completing an exploratory well on Block 914, which it plans to tie back to a subsea tree with an individual flowline. The company plans to drill a well on Ewing Bank Block 915 to further delineate reserves.

Harvey Fleischer, president of Deepwater Production Systems Inc., a DeepTech subsidiary, estimates reserves in the area at 30-35 million BOE, large enough to support either an FPS or a fixed platform.

Although comparisons are difficult, Fleischer said the approximate total cost of developing Block 914 field-in about 1,000 ft of water-with a fixed platform and 20-24 wells would be about $135 million. By comparison, developing the reserves in smaller bites with an FPS could be accomplished at an estimated cost of $90-100 million. Neither estimate includes operating costs, or such items as christmas trees, conductor pipes, or production risers.

"Taking an existing semisubmersible MODU and converting it, I estimate 20-25 months would be needed from the time I start detailed engineering until the time I'm on location, ready to drill and produce," Fleischer said. "Designing, constructing, and installing a jacket and topsides for a fixed platform of adequate size would take at least 30 months."

Adds Briscoe, "If everything went right, I could see production out there with an FPS in 1995-96."

GULF OF MEXICO OUTLOOK

Most gulf operators agree TLPs and guyed or compliant towers are too costly to use to develop fields with reserves less than 100 million BOE, especially in water more than 2,000 ft deep.

But conventional FPSs compete well in many ultradeepwater applications because FPS facility costs don't increase with water depth as quickly as those of other systems. Also, the size and weight of a fixed platform jacket increase exponentially as water depth increases, further complicating production operations.

Deepwater's Fleischer estimated an incremental cost of $10-12 million to equip the FPS for DeepTech's Ewing Bank 914 project to work in 1,500 ft of water, instead of the 1,000 ft water at the planned installation site.

"I couldn't even begin to estimate what the incremental cost increase would be for a fixed platform," he said. "You might be looking at an increase of more than 100%."

For ultradeepwater applications, TLPs or compliant towers can offer more flexibility than a conventional FPS but at two or three times the cost. In addition, a conventional FPS can be moved once its current project is depleted, allowing the operator to spread development costs over more than one project.

"Petrobras has done that several times off Brazil," Kincheloe said.

CONVERTING MODUS

High upfront deepwater costs can be curtailed or deferred by converting MODUs to production modes.

Most recently, Chiles Offshore Corp., Houston, converted Intrepid semisubmersible to a permanent production mode and sold the FPS-renamed Petrobras XXIV-to Brasoil, the international subsidiary of Petroleo Brasileiro SA. Petrobras plans to deploy the FPS in about 900 ft of water in Albacora field off Brazil (OGJ, Oct. 19, p. 36).

Oceandril Data Services, Houston, lists two semisubmersible MODUs--including Petrobras XXIV--that have been converted to permanent production modes. Another nine semisubmersibles in Oceandril's data base are working as FPSS, all off Brazil for Petrobras.

"There's so much first class equipment available out there, it's very simple to buy a unit and modify it to meet project specifications," Kincheloe said. "In the short term, it's the only way to go."

The converted semi Enserch will deploy on Garden Banks 388 will cost $20-30 million, including purchasing, converting, and equipping. A newly built FPS would have cost far more than $100 million, Kincheloe estimated.

Many inactive semisubmersible MODUs could be converted to production applications. At best, such conversions likely would retain only limited drilling capabilities, so converting too many MODUs could affect deepwater drilling rates or hamper deepwater drilling capabilities.

Newbuilt FPSs someday will be working in the Gulf of Mexico but not before 2000, Kincheloe said.

"In my judgment, there's nothing a company could get on a newbuild it couldn't put on a modified existing vessel," Kincheloe said. "If the well count is small enough and reserves are adequate to support a floating facility, as long as the rig's structure is sound, it's such as tremendous savings, you're crazy not to do it."

MAXIMUM FLEXIBILITY

For maximum flexibility of development, an FPS must be equipped to allow simultaneous drilling, production, and workover operations. FPS weight must be controlled rigorously to retain as many operating capabilities as possible.

On Garden Banks 388, Enserch has predrilled and cased four wells to prepare them to produce from reservoirs at 6,100-10,800 ft. According to the development plan for the field, Enserch will install the FPS and complete existing wells and put them on production as quickly as possible. Once production is established from the shallower reservoirs, Enserch plans to drill wells from the FPS to delineate reserves below 13,000 ft in the same sands targeted by Shell at Auger.

By placing shallower reservoirs on production as soon as possible, Enserch expects its revenue stream to be sufficient to fund whatever additional work is required to fully develop the field.

"Why spend $15 million to drill a well now when we could drill it for half that cost or less from a floating production facility?" Kincheloe asked.

DEVELOPMENT OPTIONS

Selecting a conventional FPS as a development option limits peak output, as well as the number of wells that can be used to produce a particular reservoir.

The main advantage of a compliant tower is its well system is virtually identical with that of a conventional fixed platform. Drilling can be carried out with a conventional platform rig equipped with a surface blowout preventer (BOP). After wells are drilled, tubing can be run and wells completed with the Christmas tree at surface.

However, a compliant tower is effective only to depths of 3,000 ft or less, is the heaviest deepwater development option, the most costly, and yields the greatest financial risk.

TLPs are effective to water depths of at least 4,000 ft, and production and maintenance operations are similar to those of fixed platforms. Christmas trees are at surface, and workover operations are carried out with a surface BOP.

However, drilling wells as part of a TLP development scheme requires use of a floating MODU, which also means using a subsea BOP and drilling riser. In addition, the TLP is weight sensitive and like the FPS can't accommodate heavy payloads.

"In short," say Ed Horton and John Halkyard of Deep Oil Technology Inc., Irvine, Calif., "the compliant tower and the TLP must have firm development plans and are totally dependent on the performance of the specific reservoir to be profitable."

A conventional FPS is more versatile than a TLP or compliant tower. The subsea wells and risers required by an FPS are more expensive and difficult to operate than well systems of TLPs or compliant towers.

A conventional FPS is likely to be the preferred development concept for some small fields in deep water. But for large reservoirs requiring a large number of wells for proper development, high maintenance costs, and frequent workovers, a conventional FPS likely would lose out to other concepts.

Horton and Halkyard contend a new approach is needed to develop a deepwater production system that can be profitable under the Gulf of Mexico's economic constraints. They say the 835 ft tall drilling and production Spar FPS concept developed by Deep Oil, McDermott Marine Construction, Rauma Repola Offshore Oy, and Reading & Bates Development Co. represents a new functional approach to an old, proven concept.

SPAR FPS

Horton and Halkyard say the Spar FPS combines many of the favorable characteristics of TLPS, compliant towers, and conventional FPSS, while overcoming many limitations of those systems:

  • The Spar well system is similar to that of a TLP, not as attractive as the well system on a compliant tower but much better than that of a conventional FPS.

  • Initial cost of the Spar is less than other systems, with the possible exception of a converted semisubmersible MODU operating a limited number of subsea wells.

  • Spar installation cost is about the same as a conventional FPS, and much less than a TLP or compliant tower.

  • The Spar is less load sensitive than either the TLP or conventional FPS and has greater depth range and better mobility than the TLP or compliant tower.

  • The Spar-like a conventional FPS -can use a development plan that allows start-up of production sooner than with a TLP or compliant tower and is the only deepwater development system with significant optional oil storage capacity.

The features above would give the Spar a decided edge over alternative deepwater production systems for many of the Gulf of Mexico's medium sized reservoirs, Horton and Halkyard contend.

SPAR DESCRIPTION

In a paper presented during the 1991 Offshore Technology Conference in Houston, Deep Oil's Roger S. Glanville, Halkyard, and others described a drilling and production Spar designed for a 36 well development at a Gulf of Mexico location in 2,700 ft of water.

The authors concluded the unit designed for Chevron would be a simple, cost effective drilling and production option for deepwater gulf wells.

"It allows flexibility on selection of well systems and drilling strategies, including early production or predrilling programs," they said.

The Chevron Spar would have a diameter of 140 ft, a draft of 650 ft, and two 90 ft by 35 ft moonpools through which the operator could drill and service wells and produce oil and gas.

The Chevron design included two drilling rigs and production facilities to allow simultaneous drilling and production. The vessel's deck load is at 17,000 tons. As designed for Chevron, the Spar has no oil storage. But as much as 500,000 bbl of onboard storage could be added without affecting other parameters or operations.

Glanville estimated the Chevron Spar could be built at a conventional shipyard at a cost of about $240 million, plus the costs of fabricating subsea templates, selected deck modules, drilling and production risers, and BOP stack.

"With careful planning and early identification of long lead time items, it should be possible to install a Spar within 3-3/2 years after award of the contract," the authors wrote.

Chevron commissioned a study of the Spar concept as one of five alternatives for developing its Green Canyon Block 205 prospect. Other concepts studied for the application include a TLP, compliant tower, and FPSs based on one or two converted semisubmersible MODUS.

PETROBRAS EFFORTS

Brazil's Petrobras, the industry leader in FPS applications and deepwater production, is pressing the deepwater production frontier to 1,000-2,000 m (about 3,000-6,000 ft).

To achieve this target, Petrobras recently created Procap 2000, a continuation of its Program for Technological Capability for Deepwater Production (Procap) coordinated by its Cenpres research and development center the past 6 years.

Procap 2000, a 4 year program with a $56 million budget, was approved because Petrobras is convinced the future of Brazil's petroleum production basically depends upon deep and ultradeep waters in the Campos basin. As with the earlier program, Procap 2000 will work intensively with the Brazilian and international scientific communities.

At present Petrobras produces an average 650,000 b/d of crude oil, with about 8% coming from waters deeper than 400 m. Barring any major onshore or shallow water discoveries, Petrobras expects this figure to reach 61.1% by 2001. Important Campos oil strikes in waters deeper than 400 m include supergiants Albacora in 1984 and Marlim in 1985 and Bijupira Salema and Barracuda fields in 1990. These fields are about 80 miles offshore in the eastern Campos basin, with the bulk of potential reserves in water depths of 400-2,000 m accounting for 66% of total proved and potential hydrocarbon reserves in Brazil.

"One of the determining factors for Brazil's continuous successful performance in exploiting deep and ultradeep waters is its floating production systems with semisubmersibles," said Marcos Assayag, Procap coordinator.

"When we speak of FPS, we are not talking only of semisubmersible production platforms but include subsea connection systems, wet Christmas trees, diver assisted-in water depths to 300 m-and diverless-to 1,000 m, flexible risers, vertical as well as horizontal flow systems, submarine manifolds, and diverless/guidelineless template manifolds that collect production from several wells and take it to a platform where primary processing starts," Assayag noted.

Campos crude produced via converted MODU FPS is transported to shore by tanker or pipelines. Assayag contends the versatility of these systems reduces big upfront investments and have cut down project lead times.

Petrobras has installed 165 wet Christmas trees, which account for more than 25% of the world total. Petrobras has designed wet Christmas trees and risers for operation in 1,800 rn water depths and is developing projects for application, focusing on standardization and cost reduction.

PROCAP FOCUS, GOALS

Procap 2000's deepwater technology focus is on:

  • Stability in horizontal and highly deviated wells.

  • Drilling highly deviated wells in poorly consolidated sandstones and unstable shales.

  • Kick and blowout control in deepwater wells.

  • Subsea submersible centrifugal pumping.

  • Subsea separation systems.

  • Subsea multiphase pumping.

  • Flow assurance in deepwater conditions.

  • Reduction of rig downtime due to BOP handling.

  • Stationary production unit with dry completion.

  • Stationary production unit with subsea completion.

  • Acquisition of geological, geophysical, geotechnical, and environmental data.

Procap 2000's overall goal is to come up with technological innovations that would cut current Campos deepwater lifting costs of an average $10/bbl by as much as 40%, said Assayag.

"Flexible lines represent about 25% of the cost of installation of an FPS. Petrobras is working with suppliers sharing knowledge gathered from operational experience for drawing up new specifications for flexible flow lines to be used in water depths greater than 1,000 m," he said. "The target is to reduce to the minimum possible the number of flexible lines, cutting costs and extending technological knowledge for the development of ultradeepwater fields."

For Petrobras, FPS early production systems designed for 2-3 year use evolved into permanent production systems designed for 10-15 years. These systems became increasingly complex and now handle as much as 100,000 b/d, up from initial design capacity of 20,000 b/d. Multipoint mooring systems were replaced by single point systems in an effort to improve tanker mooring safety and reliability.

FPS ADAPTABILITY

According to Assayag, the key to FPS deployment is its adaptability to specific conditions. In the case of the Campos basin, tankers were adapted for FPS use in the delineation and early production in a field when there was no infrastructure for crude storage. That was the case with the P.P. Moraes, a tanker converted into an FPS that served early production schemes in Albacora and Garoupa fields and is expected to be upgraded from a water depth rating of 250 m in Albacora to work in 850 m of water in Barracuda field, Brazil's second largest field after Marlim.

Barracuda has reserves estimated at 660 million bbl and contains 25.6 gravity oil, lighter than the basin average. It lies in 700-1,100 m of water.

Petrobras has prepared a $200 million pilot project scheduled to start up at the rate of 7,000 b/d and 4 MMcfd of gas and peaking at 25,000 b/d and 12 MMcfd from five wells in 1996, pending project approval.

One of the technological bottlenecks Procap 2000 faces involves mooring. For depths shallower than 400 m, the chain/cable/chain system was installed with the Vitoria-Regia, the first low cost, fully integrated semisubmersible for deepwater production intended for permanent production in Marlim and Albacora.

At water depths to 2,000 m, Cenpes will have to develop alternative mooring systems.

"We may try synthetic cables or systems with dynamic positioning used for drilling platforms. These are not to be used permanently in production platforms because it is very expensive to maintain the rig in position. But, as we go deeper, the length of the flow line increases and one alternative may be to mix the two systems, using dynamic positioning as an option, only to be used in extreme conditions, such as during a storm," Assayag said.

Another bottleneck involves developing lay barges with the capacity for launching flexible lines at depths greater than 1,200 m.

"The system for installing these lines also present problems. At 2,000 m water depths it will be necessary to change the structure of the lines to improve pressure resistance capacity. One of the alternatives would be to produce lines with synthetic frames. At present they are produced with synthetic fibers but have steel frames. However, we will not abandon steel lines because their flexibility increases with greater lengths," Assayag said.

"As far as semisubmersibles go, we will have to consider the reduction of weight on the platforms, perhaps transferring weight to its legs. We will also have to review the systems for well connections. We are using the layaway system and, in the case of greater depths, we will analyze the vertical system, where the drilling rig itself may install the connection system, avoiding the need to use lay barges," he said.

In order to assure significant effective results in these projects, the final products will be presented as prototypes, field tests, small scale models, or basic designs. Cenpes will wait for investment decisions of the company to undertake tests on a commercial scale that could involve outlays of as much as $150-200 million for a single project.

Copyright 1992 Oil & Gas Journal. All Rights Reserved.