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The PDF file of this paper is in Russian.
The production experience from the Statfjord Field on the Norwegian Continental Shelf is one of the greatest adventures in modern oil and gas history. After achieving very high oil recovery factor using a predominant drainage strategy with pressure maintenance by water and gas injection, the drainage strategy in the field has since 2007/2008 been changed to reservoir depressurization.
Prior to depressurization start-up, the field has produced about 652 million Sm3 (4.1 billion bbl) oil and 187 billion Sm3 gas. Currently, the field is producing at an oil rate of approximately 5 300 Sm3/d and a gas rate of about 11 million Sm3/d. Estimates indicate that successful implementation of the new drainage strategy will continue and lead to an ultimate oil recovery of higher than 67% and a significant additional gas production, as a result of the depressurization process. In addition, the field life will be extended from 2009 to 2025, and this will contribute to lifetime extension of the attached satellite fields.
The main purpose of this paper is to provide a description of the multidisciplinary approach used for evaluation and planning of the Statfjord Late Life (SFLL) with reservoir depressurization, share learnings from depressurization start-up and address challenges, uncertainties and opportunities.
Abstract The Statfjord Field has produced about 635 million Sm (4 billion bbl) of oil and exported 68 billion Sm of gas. This equals to an oil recovery factor of 65% and a gas recovery factor of 48% of volumes initially in place. Currently, the field is producing at an oil rate of approximately 20 000 Sm/d, which is about 17% of the plateau production rate. The predominant drainage strategy has been pressure maintenance by water and gas injection. However plans toextend production life for the Statfjord Field even longer will require changing drainage strategy from pressure maintenance to depressurization. Estimates show that implementation of the new drainage strategy will lead to an increased ultimate gas recovery from 53% to 74% and an oil recovery factor of 68%. Lifetime for the Statfjord Field will be extended by approximately 10 years. A change in focus from oil production to gas production has consequences both subsurface and topside. Key elements for implementing the depressurization of the Statfjord Field reservoirs are drilling and recompletion of approximately 80 wells which will be equipped with artificial lift and sand control, as well as topside modifications on the three existing platforms. This results in a high offshore activity level for several years on a field in production. A new gas export pipeline to the UK FLAGS system (Far north Liquid And Gas System) is necessary to provide sufficient offtake of the produced gas. Implementation of a new drainage strategy on the Statfjord Field has also regional effects. Prolonged life time of the Statfjord Field installations leads to increased recovery for the Statfjord Satellites and opens for business opportunities in a longer term. Introduction The Statfjord Field is the largest producing oil field in Europe in terms of recoverable reserves. It is located in the Tampen Area of the North Sea, 200 km northwest of Bergen, Norway, straddling the border between the Norwegian and the UK sector, see Figure 1. The field is approximately 27 km long and 4 km wide with a STOIIP of approximately 1 billion Sm3 and an estimated ultimate recovery factor for oil of 68%. It is developed with three concrete platforms and each platform is a combined drilling and production unit. In addition, the Statfjord satellite fields (Statfjord Øst, Statfjord Nord and Sygna) and the Snorre Field are connected to the Statfjord Field facilities. The Statfjord Field is located on a late Jurassic rotated fault block. The Statfjord Field's two main reservoir sand stone units, members in the Brent Group and Statfjord Formation, are divided by the Dunlin Group which mainly consists of shale. The Brent Group is divided in Upper and Lower Brent. The Main Field which contains 85% of the STOIIP consists of a rotated fault block with the Brent Group and Statfjord Formation reservoirs. It has a dip of approximately 6–7 degrees towards west-northwest. The East Flank consists of slump fault blocks generated by gravitational failure at the crest of the field. The East Flank is structurally and stratigraphically complex. It is heavily faulted with internal faults and small scale structures making reservoir mapping challenging. The communication from the Main Field to the East Flank is generally good, with some restrictions as one moves to the east of the field.
This paper was prepared for presentation at the 1999 SPE Offshore Europe Conference held in Aberdeen, Scotland, 7–9 September 1999.
This paper describes the main challenges of the Brent field, which are related to the final stage of the currently executed pressure-maintenance waterdrive and preparations for field depressurization. These challenges are grouped into three categories: timely development of all reserves, production optimization before deep depressurization, and proper execution of the redevelopment project.
Located in about 460 ft of water roughly 100 miles northeast of Shetland (Fig. 1), the Brent field is one of the largest hydrocarbon accumulations in the U.K. sector with 3,600 million STB original oil in place (OOIP) and 6.9 Tscf original gas in place (OGIP). Estimated ultimate recoveries are 1,980 million bbl oil and 5.5 Tscf wet gas. Oil and gas are exported through two pipeline systems: the Brent system for oil and the FLAGS system for gas. These systems form a large part of the total infrastructure in the northern North Sea.
The Brent field can be considered a mature field, with about 77% of its waterflooded ultimate oil recovery produced to date. To enhance the ultimate recovery of both oil and gas beyond that possible by the current waterflood at near-initial reservoir pressures, low-pressure operations facilities and gas lift will be installed during 1994-97, and the field will be depressurized in a controlled fashion beginning in 1997. To make the change to low-pressure operations/depressurization and to cater for the longer life expected of the Brent field, extended platform shutdowns are required, so one of the four platforms will be out of service between mid-1994 and early 1998. The redevelopment project, costing an estimated #1.3 billion,* is unique in scale, complexity ("brown" field engineering) and implementation (it will be executed while ongoing operations are maximized).
The optimization of oil recovery from the Brent field under this new long-term development strategy is exceptionally complicated. It requires proper integration of waterflood tail-end production from a complicated crestal region with the transition to depressurization, all in a limited time frame. Well operations play a key role in developing all future reserves and integrating redevelopment well activities. In addition, increased emphasis is given to all initiatives that increase potential and productivity. Any deferment of oil production will put ultimate recovery at risk in view of the slow loss of lift in oil-producing wells after the year 2000.
The Brent field, discovered in Aug. 1971, is one of the largest hydrocarbon accumulations on the U.K. Continental Shelf. Its discovery marked the start of extensive activity for exploration of hydrocarbons in the northern North Sea. Located in Block 211/29, the Brent field comprises four installations and a remote flare (Fig. 2). Brent Alpha is a steel piled structure; Brent Bravo, Charlie, and Delta are concrete gravity structures. Together, these structures provide 154 well slots.
The field is operated by Shell U.K. E&P on behalf of the Shell/Esso joint venture in the U.K. sector of the North Sea.
Oil production started in 1976 and peaked at a yearly average of 416,000 B/D in 1985 and 1986. Oil is exported through the Brent systems pipeline to Sullom Voe. Gas export to St. Fergus started in 1982 through the FLAGS line, with all gas sales to British Gas.
Under waterflood development, gas production from the Brent Field will fall off plateau in 1998 and. at field abandonment, it is estimated that approximately 55% of the 6.9 Tscf GIIP and 54% of the 3600 MMstb STOIIP would be recovered.
With its high solution gas-oil-ratio, reservoir depressurisation, as an enhanced recovery project, is an attractive possibility. In this process, reservoir pressures would be progressively lowered, ultimately to approximately 1000 psi.
It is expected that gas liberated from residual and by-passed oil would increase gas recovery by over 1 Tscf allowing the field to continue to produce at plateau levels into the 21st Century. Depressurisation is also expected to increase oil and condensate recovery by 30 MMstb compared to a continuation of the ongoing waterflood. From a sub-surface viewpoint, the main challenge would be to manage the field to maximise oil recovery while maintaining gas sales at plateau.
To allow the field to move into a new development phase, an extensive platform modification programme will need to be initiated. Planning has to take into account the uncertainties associated with a project that has not been tried on an oil reservoir of such a scale. Aquifer influx, H2S and sand production are some of the risks that have been assessed and contingency measures identified.
The Brent Field is located 150 kms north-east of the Shetland Islands, and is one of the first and largest oil fields to be developed in the UK sector of the North Sea. Discovered in 1971 in Shell/ Esso block 211/29 (Fig. 1), it was brought on stream in 1976 and reached a peak oil production of 500 Mstb/d in 1984 (Fig. 2).
In total, 83 oil producers have been drilled from four platforms. By January 1992 cumulative production amounted to 1370 MMstb of oil (38% STOIIP) and 2250 Bscf of gas (33% GIIP). A further 38 downdip water injectors wells and 13 crestal gas injectors maintain reservoir pressures at approximately 5400 psi.
The vertically separate Brent and Statfjord accumulations contain light 39 to 40 degrees API oil and considerable variation of fluid properties with depth is apparent (Fig. 3, Ref. 1). Until the gas export pipeline was commissioned in 1982, produced gas was re-injected into the primary gas caps. After 1982, a sales agreement with British Gas commenced, and an average of 500 Mmscf/d of dry gas has been supplied via the FLAGS line and an onshore gas treatment plant located at St. Fergus on the north-east coast of Scotland.
The field lies in a westerly dipping tilted fault terrace some 40 kms long and 15 kms wide that extends from North Alwyn in the South to the Statfjord Field in the North.
There are two distinct reservoirs, the Middle Jurassic Brent Group and the Lower Jurassic/Triassic Statfjord Formation. The top of the Brent Group lies at a depth of 8500 ftss (Fig. 4) and the sequence vanes between 780 and 850 ft. in thickness. The reservoir consists of generally good quality sandstones, shales and coals that were deposited throughout the East Shetland Basin and adjoining Viking Graben. In common with other deltaic deposits, the reservoir sandstones are separated by extensive shales, giving a number of semi-independent producing intervals (Fig. 5, Ref. 2).
The Statfjord Formation lies at a depth of 8900 ftss and reaches a maximum thickness of 1000 ft.