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 Figure 1). The concepts range from fixed platforms to subsea compliant and floating systems. In 1859, Col. Edwin Drake drilled and completed the first known oil well near a small town in Pennsylvania, U.S.A.
Figure 1.6--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). Figure 1.9a--Worldwide fleet of installed and sanctioned semisubmersible FPS (courtesy of BP). Figure 1.9c--Worldwide fleet of installed and sanctioned spars (courtesy of BP). Figure 1.10--Semisubmersible FPS planned for the Thunder Horse field (courtesy of BP). Figure 1.11--Alternative proven technology field development options (courtesy of BP). Figure 1.12--Subsea production trees used in conjunction with a fixed jacket structure (Intec Engineering, Houston).
The Oudna Field is located approximately 80 km. offshore Tunisia (Figure 1). Successful application and optimization of an artificial lift system for this field required a considerable amount of evaluation prior to implementation, in order to take into consideration three specific features of the prospect:
After extensive study of the various artificial lift alternatives available, the decision was made to install the first sub-sea hydraulic jet pump system, capable of producing 25,000 bpd, because it afforded the following advantages:
In this paper the authors explain the need for a long life system, the reasons for selecting jet pumps, the considerations in the design of the jet pump, its installation and operation. The process used for the optimization of the jet pumping system is discussed.
Initial field economics on Oudna was carried out based on a $27 / BBL pricing. With this oil price, under any circumstances the Field was likely to be Marginal. Although confidence existed that the Oudna reservoir modeling was sound this in turn had indicated that both reservoir pressure support and an artificial lift production mechanism would be required to keep oil production levels to that required.
Given that the field is in 270m of water and around 80km from shore then both the Production Handling and Artificial Lift options were going to be limited.
The industry has many leases in the western Gulf of Mexico (GoM) where there isnot extensive infrastructure and the Floating Production, Storage andOffloading (FPSO) concept can be economically competitive. As part of conceptscreening and appraisal of new deepwater fields, BP retained Single BuoyMoorings (SBM) to evaluate various disconnectable FPSO options with focus onthe vessel turret, the disconnectable system, and potential riser solutions.The study assumed the development would comprise of 12 subsea wells in 6,200ft. of water tied back to four subsea manifolds. The flowlines would becomposed of two loops connecting to the FPSO facility via four risers. Thesmall amount of produced gas would be exported via a pipeline and export of theproduced oil would be via shuttle tankers. The possible need for high pressure(and high volume) water injection was also assumed.
A hybrid riser system is a feasible but expensive riser solution for adisconnectable FPSO in the Gulf of Mexico. The emphasis in the conceptevaluation was on cost effective alternatives to hybrid risers, i.e.,evaluating turret and mooring systems which would make the steel catenary riser(SCR) or its variations feasible.
This paper describes the main results and conclusions of the evaluation andsizing of an External Turret system of the MoorSpar type. The system comprisesa spar buoy to which the FPSO is connected via an articulated yoke system hencedecoupling the FPSO heave/pitch motions from the SCR friendly spar buoy. Thistype of external turret allows the steel risers and umbilicals to be in simplecatenary configuration.
The concept evaluation included a HAZID performed by DnV and a third partyreview performed by Atkins. The following issues were also addressed:technology readiness, complexity and safety of operations, uptime, CAPEX andOPEX.
Management - No abstract available.
This article is a synopsis of paper SPE 56708, "FPSO Trends," B.F. Ronalds, SPE, and E.F.H. Lim, U. of Western Australia, originally presented at the 1999 SPE Annual Technical Conference and Exhibition, Houston, 3-6 October.
This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3-6 October 1999. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Abstract A review of trends in floating production, storage and offloading (FPSO) technology is presented, using an extensive database of past, current and planned developments around the world. The review commences with the first FPSOs in the mid-1970s, explores the stimuli for FPSO development in Asia, in particular, over the next two decades and their widespread acceptance in the North Sea in the late-1990s.
Nine floating production, storage and offloading (FPSO) systems utilizing tankers (or barges) anchored by single point moorings have been installed or are under construction.
Since the first FPSO system began operation in 1976 a total of almost 40 system-years operational experience has been accumulated. As a result of this experience, component design reflects the particular FPSO environment and reliability has been much improved while system downtime has been reduced.
After broadly describing the nine FPSO facilities, the operational experience of the most essential components and subsystems are detailed. The key elements include: the mooring system, the fluid transfer system, the processing equipment and the cargo offloading system.
Emphasis is put on the fluid transfer system which includes high pressure flexible risers and high pressure swivels accommodating independent paths pressure swivels accommodating independent paths for crude, gas and water. The principal results are given for a research program investigating high pressure seals for large diameter swivels. pressure seals for large diameter swivels. The paper concludes with a near-future forecast of FPSO applications.
An integrated vessel-based floating production, storage and offloading (FPSO) facility is composed of the following principal components or subsystems:
1. A single point MOORING SYSTEM consisting of: one or more anchor points; single or multiple mooring risers; a buoyant or fixed body; a mechanical swivel that allows weathervaning, and a means of connection with a permanently moored vessel. Two fundamentally different types of single point mooring systems are employed in the nine FPSO facilities under consideration: the single buoy storage (SBS) system and the single anchor leg storage (SALS) system.
2. FLUID TRANSFER conduits which transport fluids from the seabed to the surface and the vessel's production equipment, and vice versa. An essential part of this system is the fluid swivel that allows uninterrupted flow to the vessel regardless of its heading.
3. A floating VESSEL which can be either a pur posebuilt barge or a converted trading tanker.
4. PRODUCTION EQUIPMENT, installed on the vessel's deck, separates the produced wellhead fluids into gas, oil and water. Separated gas is burned to generate power and the balance is reinjected into subsea wells, used for gas lift or flared. The oil is stored in the vessel's cargo tanks awaiting offloading to shuttle tankers for transport to shore while the water is purified and dumped into the sea.
One of the facilities under consideration is employed as a floating plant to refrigerate, store and offload LPC received from a nearby platform.
5. CARGO TRANSFER equipment enables the safe, rapid. periodic transfer of produced crude from the FPSO vessel's cargo tanks to shuttle tankers that may moor either in tandem with or alongside the production vessel. It is also possible to employ a separate loading terminal or pipeline.
6. LOGISTICAL SUPPORT facilities that frequently include a shore-based administrative office, telecommunications networks, spare parts stock, consumable supplies and means of transportation for personnel as well as equipment.
This paper will review the design of the production facilities on the multiwell floating production and storage unit (FPSU) operated by Shell Tunirex in the Tazerka field, offshore Tunisia, on behalf of a joint venture with AGIP (Africa) and Entreprise Tunisienne d'Activits Petrolires. Economics and product specification dictated the application of special techniques in the production and utility designs regarding process flexibility, gas disposal, power generation, and pollution prevention. The field, containing estimated reserves of 8 to 10 million bbl [1.3 x 10(6) to 1.6 x 10(6) m3] of recoverable oil, is located in deep water (459 to 984 ft [140 to 300 m]). It was desirable to use a single-process train with as near a 100% on-stream factor as possible. While this is not the first application of a flow station on a weathervaning unit, it is believed to be the first to process crude directly from several subsea wells.
The Tazerka field lies 35 miles [56 km] offshore the northeast coast of Tunisia in the Hammamet Grand Fonds permit. It has been in production since Nov. 1982 and currently produces some 10,000 B/D [1590 m3/d]. Oil is produced from four subsea completed wells in water depths ranging from 459 to 607 ft [140 to 185 m], flowing by Coflexip (TM) flowlines to the single anchor leg system (SALS) that holds the FPSU on location in 459-ft [140-m] water depth. Oil flows through swivels on the SALS to the FPSU-i.e, to the converted very large crude carrier (VLCC) tanker Murex (Fig. 1). The entire crude production facilities are integrated onto the converted unit, which then stores up to 140,000 tonnes [140,000 Mg] of crude. The system is completely independent of platforms and pipelines to shore, with off-take achieved by discharging, using the original VLCC cargo pumps, to trading tankers moored alongside. This approach to developing the field, instead of conventional methods such as steel or concrete platforms connected by pipeline to shore, was dictated by economics, which showed that conventional methods would have been too expensive.
The initial field development plan called for reservoir natural depletion with provisions for future installation of water injection and gas lift facilities to enhance recovery. Fig. 2 shows a block flow diagram depicting the deck-mounted facilities/utilities that have been designed and engineered for the Tazerka FPSU.
Crude Oil Production. The Tazerka FPSU development is designed to receive 30,000 B/D [4770 m3/d] of produced liquids from up to eight subsea completed wells. All wells have provisions for future gas lifting. Three of these wells also have been designated for water injection. At present, the well fluids from the four installed subsea wells flow through 4-in. [10-cm] Coflexip seabed lines to the SALS manifold, then through a six-bore product swivel, and finally, through the mooring yoke to the receiving manifold on the FPSU. Well subsurface safety valves and wing valves are controlled hydraulically from a control panel on the FPSU deck by control lines routed through a 20-bore swivel on the SALS.
Oil/Gas/Water Separation. From the receiving manifold on the FPSU, the incoming stream is routed to a single-process train, consisting of a separation unit (HP, LP, and test) and a stabilizing unit. The possible combinations of the process train and the valve switching provide for an on-stream factor close to 100%. Oil can be produced through any one of the six product swivels to the receiving manifold. All separators are of identical design and are capable of handling the full production flow, therefore enabling any one separator to be out of service for maintenance or repair while still maintaining production through the others. The test separator also can be used as a stabilizer. Fig. 3 shows the changeover philosophy in detail. Produced water can be removed from the crude oil in two stages. 1. Bulk separation in the three-phase separators is possible in either series mode or parallel mode. 2. Final separation of water occurs in the FPSU's dedicated crude receiving tanks, where water can be taken off the bottom by the original VLCC's stripping pumps. A dehydrator can be installed if high water production or stable emulsions occur.