Overview of the GASP Project-Field Applications and Economics
- M.M. Sarshar (Goodfellow Assocs.) | J.J. O'Connor (Chevron (U.K.)) | P.M. Lovie (Goodfellow Lovie Assocs.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- March 1992
- Document Type
- Journal Paper
- 332 - 340
- 1992. Society of Petroleum Engineers
- 4.3.1 Hydrates, 4.2 Pipelines, Flowlines and Risers, 3.1.6 Gas Lift, 6.5.2 Water use, produced water discharge and disposal, 4.5.7 Controls and Umbilicals, 4.5.9 Subsea Processing, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.2.1 Phase Behavior and PVT Measurements, 4.5.10 Remotely Operated Vehicles, 7.5.3 Professional Registration/Cetification, 5.3.2 Multiphase Flow, 4.4.3 Mutiphase Measurement, 4.1.5 Processing Equipment, 2.4.3 Sand/Solids Control, 5.7.4 Probabilistic Methods, 4.5 Offshore Facilities and Subsea Systems, 4.1.2 Separation and Treating, 4.2.4 Risers, 4.3.4 Scale
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The aim of the Good-fellow Assocs. subsea production (GASP) project was todevelop a sub-sea production system for use in the development of marginalfields. The project was divided into three phases that culminated in testing aprototype system in a dry dock. The GASP system enables manifolding ofproducts, separation of gas from produced liquids, and transportation of gasand liquids through separate lines. The produced liquids are pumped with asingle-phase pumping system that is highly modularized for ease of installationand retrieval of key components. GASP is suitable for deep-water applicationand development of marginal fields far from the host platform. The economicswere assessed with probabilistic methods to weigh the uncertainties. Developingmarginal fields with the GASP system looks attractive, offering a developmentcost of $2.50 to $5.50 per barrel in many typical instances.
GASP was a joint industry project supported by the European Community andeight major oil companies: Agip (U.K.), Chevron (U.K.), Conoco (U.K.),Elf(U.K.), Norsk Hydro, Phillips Petroleum (U.K.), Statoil, and Texaco (U.K.).The project was developed under three phases. Phase 1. Nov. 1986-Nov. 1987:conceptual development of the subsea production/process system. Phase 2. Nov.1987-Feb. 1989: detailed design of prototype system and material procurement.procurement. Phase 3. Jan. 1989-May 1990: installation and testing of theprototype system in a dry dock.
The main objectives of the project were (1) to develop a subseaproduction/processing system suitable for development of marginal fields; (2)to identify the key components of the system, their requirements, and the stateof the an for their application; (3) to address all major operational aspectsto establish the viability, applications, and limitations of the system; (4) touse the GASP system to prepare a cost estimate for the development of a fieldand to establish the economic viability of the system; and (5) to demonstratethe operation and control of a prototype system to confirm system viabilityprototype system to confirm system viability and to identify areas requiringfurther development or modifications for future field applications.
Why Subsea Production and Processing? Production and Processing? Developmentof marginal fields with conventional bottom-supported jackets and floatingproduction systems, in most cases, is uneconomical because of their highcapital cost. The economics are affected further by the development of fieldsthat are located in deep waters and have one or more of the followingcharacteristics: (1) reservoir conditions demanding several satellite wells forthe recovery of field reserves; (2) low production rates associated with lowPI; (3) production rates associated with low PI; (3) limited total recoverablereserves, typically ranging from 10 to 100 million bbl oil; (4) low productionpressure and rapid pressure decline, requiring water injection and gas lift asan additional aid to enhance recovery; and (5) high water cut, reaching 70% to80% oftheproductionneartheendofthe field life. These conditions can beaggravated further by uncertainties in reservoir behavior, the presence of H2Sand CO2, waxy crude oil, and production of sand. An economic solution is tominimize the capital cost and to use the existing nearby facilities as much aspossible. This approach entails transporting the products for processing andexport to the host platform. processing and export to the host platform. Ainmost cases where production from several wells is involved, manifolding theproducts subsea becomes necessary to save the cost of pipelines over longdistances. Transporting well products in a multiphase (gas and liquids) stateover long distances poses a number of problems, including severe poses a numberof problems, including severe slugging and pressure fluctuations. Theseconditions also have an affect on the design and capacity of the topsideprocess facilities that need to cope with the expected slug and plug flowconditions. plug flow conditions. Loss of pressure along the pipelines as aresult of friction and head losses often limits the production life and subseaboosting of the products becomes necessary. Near the end of the field life, ahigh water cut means that head losses dominate. For deepwater production, wherea significant difference production, where a significant difference exists inseabed elevation between the sub-seaproduction system and the host platformhead losses may form more than 90% of the total losses along the line. Notethat for deepwater fields, even if conventional production platforms are used,head losses along the riser will restrict the production rate through theentire life of the production rate through the entire life of the field unlesssome form of downhole or sub sea boosting is included. In most cases, theproduced hydrocarbons are well below their produced hydrocarbons are well belowtheir bubblepoint when they reach the wellhead, and gas/liquid ratios can rangefrom 3% to greater than 90% during the production life of the field.
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