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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.
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.
The novel reservoir processes and rapidly or ESP installations to maximize liquid The Brent field is in the U.K. North Sea and changing reservoir conditions require production, through-tubing recompletions initially contained 3.8 billion STBO and flexibility in development planning and a to access reserves behind pipe, reservoir 7.5 Tscf gas. Redevelopment from three of reduced reaction time between observations surveillance, and various types of well the four Brent platforms required installing and remedial actions.
Summary Planning for the depressurization of the Brent Field required an extensive study of the aquifer to determine the withdrawals necessary to depressurize the field and to predict the effect of depressurization on surrounding fields. Static and dynamic aquifer models were constructed and several techniques were applied to evaluate the sealing capacity of the major boundary fault. Since the aquifer extends over several license blocks, integration of a wide range of data of varying quality from different sources was required to build up a complete aquifer model. The results highlighted effects of pressure communication between fields which were not apparent to teams studying individual fields in isolation. Introduction Controlled depressurization of the Brent Field (Fig. 1) to maximize hydrocarbon recovery will require back production of considerable volumes of water to gradually reduce the reservoir pressure from 5500 to 1000 psi. An understanding of the size and strength of the aquifer attached to the reservoir (Fig. 2) is a critical input to the design of this process, influencing the rate and quantity of water to be back produced. In addition, other oil fields are thought to be in pressure communication with the Brent Field via the aquifer and the potential impact of Brent depressurization on all these fields needed to be quantified. Thus, as part of the planning for depressurization, an extensive integrated petroleum engineering study was undertaken to assess the range of uncertainties in the behavior of the Brent reservoir aquifer during depressurization and to quantify the possible impact of the redevelopment project on surrounding fields, including the effect of any possible communication between the Brent and Statfjord Fields. This study was confined to the Brent reservoir as the Statfjord reservoir aquifer has already been shown to be relatively tight, with the result that depressurization will have minimal impact on even the nearest fields. In fact, the gas reserves in the Statfjord in both the Brent South and Strathspey Fields are planned to be produced by depletion drive, allowing the reservoir pressure to drop until the wells die, without any voidage replacement. The investigation concentrated on three major aspects.An analysis of all available data to establish the extent of the aquifer in communication with the Brent Field and determine its properties. Prediction of the behavior of the aquifer during depressurization. An assessment of the risks of additional communication being established during depressurization, particularly by possible leakage across the Northern Boundary Fault from the Statfjord Field, and quantifying the impact of any such communication in the worst case. Extent and Properties of Brent Aquifer Since there is a general dearth of data in areas between fields, the study required integration of a wide variety of data from various sources to produce an overall aquifer description. Aquifer Mapping. Some base data were available from a limited series of time and reservoir property maps of the Brent and Statfjord Formations in the Greater Brent Area. These had been produced during an early review of the aquifer attached to the Statfjord Field. One initial task of the present study was thus to produce a depth map of the Brent Aquifer at top Brent reservoir level (Fig. 2). This was carried out by combining existing depth maps of known fields with a regional time map. The latter map was depth converted using available depth functions from the Brent Field itself, and tied in to all available wells within the aquifer. Over key areas, principally the Northern Boundary Fault area, all available seismic, both two dimensional (2D) and three dimensional (3D), was reevaluated to provide a consistent seismic interpretation. A set of cross sections over the aquifer is shown in Fig. 3. To the north, west and east the Brent aquifer is seen to be bounded by major faulting. To the south, in the area of North Alwyn, the aquifer is effectively bounded by a combination of faulting and poor quality reservoir. Historical Aquifer Pressure Data. All available Brent reservoir pressure data from wells in the Greater Brent area were collated and corrected to the Brent Field datum level of 8700 ftss for comparison. The data consisted of repeat formation tests (or equivalent) pressure data from exploration, appraisal and early development wells (Fig. 4), together with average pressure trends from the fields on production. The early data from the 1970s suffered from inaccuracies in both absolute pressure measurements from Amerada gauges and in true-vertical depth conversion, since full deviation surveys were not run in supposedly vertical wells. Representative average data were plotted against time for each cycle (Figs. 5 to 7), from which several conclusions were drawn:All fields in the Brent and Statfjord aquifer blocks were initially in the same pressure regime, which was some 100 psi below that in the Dunlin block to the west. Subsequent performance of the Brent and Statfjord Fields shows no evidence of any communication between the two blocks over producing times. All fields within the Brent aquifer block are in some degree of pressure communication. However, the downdip well 3/3-11, drilled in 1989, was still undepleted, indicating that faulting and permeability deterioration with depth severely limit the effective western extent of the aquifer.
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.