The Gullfaks Field Development- Challenges and Perspectives

I SocietyofPetroleumEngineers I SPE 25054 The Gullfaks Field Development: Challenges and Perspectives Svein Tollefsen,' Eirik Graue, and Stein Svinddal, Statoil AIS 'SPE Member Copyright 1992, Society of Petroleum Engineers Inc. This paper was prepared for presentationat the European Petroleum Conference held in Cannes, France, 18-18 November 1992. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submined by the author@).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 PetroleumEngineers. Permissionto copy is restricted to an ebstract of not morethan 300 words. Illustrationsmay not be copied. The abstract should contain conspicuousacknowledgment of where and by whom the paper is presented. Write Librarian, SPE, P.O. Box 833836,Richardson, TX 750833836, U.S.A. Telex, 163245 SPEUT.

ABSTRACT

INTRODUCTION

The Gullfaks Field is located in the Norwegian Sector of the ~ o r t h Sea, ' block 34/10, and currently has the capability of producing more than 70,000 S d / d of oil (440,000 stb/dl from three CBS platforms. The reservoir san& comprise shallow marine to fluvial sediments of the Cook Formation, Statfiord Formation and Brent Group, ranging in age from Early to Middle Jurassic. Water injection is the major drive mechanism for maintaining reservoir pressure above bubble point.

The Gullfaks Field, situated in the Norwegian Sector of the North Sea, block 34110 (Fig. 1), is the first licence ever run by a fully Norwegian joint venture corporation. The licence group consists of Statoil (operator), Norsk Hydro and Saga Petroleum. The field currently has the capability of producing more than 70,000 Sm3/dof oil (440,000 stbld) on a stream day basis from three main reservoirs of Jurassic age. These are the Cook Fm., Statfjord Fm. and Brent Group, with total recoverable reserves estimated to 230 mill. Sm3of oil (1.5 bill. stb) and 25 bill. Sm3 of associated gas (890 bill. scf). The Brent Group has been subdivided into the Upper Brent, Tarbert and Ness fms. and Lower Brent, Etive and Mnnoch fms.

Development wells have confirmed a complicated structural picture with numerous faults beyond seismic resolution, causing major impacts on predicting field reserves and flow patterns. Reverse faulting in an area of predominantly normal faulting further emphasisesthe structural complexity.

The field produces from three separate CBS platforms, the Gullfaks A, B and C. Gullfaks A and C are fully independent processing platforms, with three separation stages. The crude oil is stored in the concrete base of the platforms and loaded into tankers via two separate mooring buoys. Associated gas mainly passes into the Statpipe network. Some gas is, however, recompressed and reinjected into the reservoir. The Gullfaks B platform provides processing facilities for single stage separation only, and transports partly stabilised crude to both the A and C platforms for further processing. The particular option of further processing on two different platforms has ensured a high degree of flexibility for oil delivery from the Gullfaks B platform. A separate pipeline transports the associated gas to Gullfaks A. The platform infrastructure and capacities are shown in Fig. 2.

Complex geology along with field performance after water breakthrough resulted in several changes in the initial developmentstrategy. Production from the highly productive Tarbert and Staffjordsands was accelerated in order to compensate for the loss of production from the Lower Brent sands caused by sandproduction after waterbreakthrough. Development of complex Ness and low productivity Cook sands have recently commenced. Gravel packing, implemented in the Upper Brent field development, provided sand control and increased production rates. Various types of chemical sand control are currently being evaluated and tested in the field. Lowering pressure in gravel packed wellbore region below bubble point may increase the production rates even further.

This paper presents the history, current status and Mure perspectives of the Gullfaks Field Development, the technology available, as well as new technology required for optimising such complex field developments. By comparing early development plans to the present situation, emphasising in particular all the adjustments required to get there, this paper provides a broad base of experience which may be of great value t o both further development of this particular field, as well as to other field developments of similar complexity in the years ahead.

Following advances in drilling technology, highly deviateoP~orimntal wells improve recovery and accelerate field development by combining production from several reservoirs in one single well. A test programme for surfactant and WAG flooding has been implemented on the field. Other EOR methods, such as gel and polymer flooding, are currently being investigated for potential use. Referencon and illustrations at the end of paper.

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THE GULLFAKS FIELD DEVELOPMENT - CHALLENGES AND PERSPECTIVES

HISTORICAL REVIEW Exploration history Block 34110 was awarded to the licence group in 1978 during the 4th concession round. The first exploration well, 34110-1 (Fig. 31, encountered a 160 m oil column in the Brent Group and penetrated water bearing Cook and Statfjord fms. Exploration well 34110-3 established the oil-water contact (OWC) in the Brent Group. The next three wells confirmed the OWC and appraised the western part of the field. Early use of 3D seismic introduced a new era of exploration and appraisal drilling in the eastern part of the field. Well 34110-7 proved a deeper hydrocarbon system in the Cook Fm., whereas well 34110-1 1 in the north-eastern corner of the block succeeded in proving a deep OWC and a new oil system in the Statfjord Fm. The exploration and appraisal phase was completed by the end of 1983 with a total of 1 4 wells.

Development, Phase I Based on well information and seismics a field development plan in two phases was proposed. Following the Commerciality Report in late 1980, the authorities approved a Field Development Plan (FDP) for the western part, Phase I in October 1981. This plan included the production of the Brent Group reserves west of an assumed sealing northsouth trending fault (Fig. 1). Two CBS platforms were required for producing these reserves. The overall production philosophy was to produce the reserves successively shallower within the Brent Group Water injection would be the major drive mechanism, maintaining reservoir pressure above bubble point. In order to avoid potential sand problems during production, selective perforating would be used. At this stage, the total Gullfaks recoverable reserves were estimated to approximately 230 mill. Sm3 of oil (Table 1).

Development, Phase I1 Based on an updated FDP, which included the eastern part of the Gullfaks Field, the authorities approved the Phase II development in 1985. Another CBS platform was required for producing the Brent, Cook and Statfjord reserves in the complex Phase II area. A 60" deviation was considered a limit in drilling platform wells. The overall production strategy in Phase II was unchanged compared to the FDP in Phase I.

Production Start The Gullfaks A platform came on stream on December 22nd. 1986. In order t o accelerate production start, a total of five subsea wells were predrilled and put on

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stream initially. A 6th subsea well drilled on a separate segment was tied back some months later (Fig. 2). Gullfaks B started production in February 1988, whilst Gullfaks C came on stream in December 1989. During the first production period, it became clear that the process and water injection capacity had to be upgraded in order to optimise production. This is now implemented. Fig. 4 shows production profiles as planned in 1988 compared to current estimates.

GEOLOGY GeophysicsAnd Structural Geology Structural mapping of the Gullfaks Field is complicated due to poor seismic data and complex structural geology. The first 3D survey was shot in 1979, providing a great improvement compared to previous available 2D data. A second 3 0 survey collected in 1985 further improved the data. Recent processing techniques made it possible to improve seismic quality even more. As such, a reprocessing of the survey was completed during the spring of 1992. This resulted in higher resolution data, particularly towards the eastern parts of the field. The Gullfaks Field was highly deformed during the late Jurassic extensional period. This resulted in rotated fault blocks with low angle normal faults, dipping approximately 60' to the east and typically spaced 1 1.5 km apart. Strata within the fault blocks normally dip 15"-25" t o the west (Fig. 5). In addition, many small-scale, east-west trending normal faults occur on the field. While most faults were non-sealing during hydrocarbon migration and filling of the reservoir, several faults act as barriers during production, limiting horizontal flow and pressure communication across the field.

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In the eastern part of the field a horst block dominates the structural picture, resulting in a graben west of the horst. Coexistence of westerly and easterly dipping faults may have caused spatial problems accompanied by local reverse faulting. Strata within the graben and horst blocks are mostly horizontal or even slightly dipping to the east. Large scale normal faults as well as a major drop in the Base Cretaceous Unconformity define the northern, eastern and southern limits of the Gullfaks structure (Fig. 5). The stratigraphy of the Gullfaks Field show progressive erosion towards the east. Whereas the Middle Jurassic Brent Group is not eroded in the western part of the field, some 600-800 m of Middle and Early Jurassic sediments are eroded on the horst block to the east (Fig. 5). Structural depth maps of top Brent Group, top Cook Fm. and top Statfjord Fm. are shown in Fig. 3.

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StratigraphyAnd Reservoir Description The lithostratigraphic subdivision used on the Gullfaks Field is described by Vollset and Dor8 (Fig. 6 ) . This subdivision is used on group and formation level, and at members level in the Statfjord Fm. A further internal field zonation is shown as well. Note that the petrophysical interpretation presented in the first column shows only sand, shale, calcite and coal as rock forming constituents in the Cook and Statfjord fms. In the Brent Group feldspar and mica are extracted as separate additional constituents. The name "Sverdrup Member" is proposed for the shallow marine reservoir unit in the lower part of the Amundsen Fm.

Hydrocarbon/P/essure Systems The Gullfaks Field is the shallowest Mesozoic oil accumulation in the Tampen Spur area, northern North Sea. The majority of hydrocarbon volumes have migrated into the structure from the east and northeast, with minor contribution from the west. A recently discovered hydrocarbon accumulation in the southwestern part of the field suggests filling from the southlsouth-east as well. The various hydrocarbon contacts and volume distributions for the different systems are listed in Table 2.

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systems, the main Brent oil system nevertheless contributes towards some 70 % of the STOOIP. Additional potentials, still not incorporated in the STOOIP figures, are represented by the Triassic sequence in the eastern part of the field. Some of the wells drilled in this area have penetrated deeper oil systems than seen elsewhere on the field.

During six years of production from the Gullfaks Field, the reservoir development and management plans have been modified somewhat. This is due to improved and updated geological, reservoir and well performance information, as well as new technology.

Development strategy A primary set of producers and injectors are dedicated t o each reservoir unit in order t o obtain sufficient recovery. The number of wells needed is a function of reserves and the communication complexity for the reservoir. The production wells are situated high on the structures in the eastern parts of the fault blocks, whereas the injectors are placed downdip near the OWC (Fig. 5). Generally, producers are supported by injectors within the same "major fault block".

UpgradingAnd RedistributionOf The Reserves During the field development planning and early production period the Lower Brent, Rannoch and Etive fms. were regarded as the main reservoir in the Gullfaks Field. Early production and injection wells, however, revealeda promising thickness expansion and quality improvement of the parameters applied to reserves estimates for the Tarbert Fm. As drilling proceeded it became clear that the Tarbert Fm., particularly in northern parts, had been greatly underestimated. This was mostly due to a reinterpretation of well 34110-6, which revealed an undetected fault with a 60 m missing section in the Tarbert Fm. In addition, several development wells drilled through major north-south trending faults demonstrated segmentation of the faults, contributing towards an upgrade of the reserves (Fig. 7). Current interpretation of central parts of the field rarely shows any Heather sequence (Upper Jurassic shale) between base Cretaceous and the OWC. The space is replaced by the Tarbert Fm. Furthermore, better communication during production is obtained from segmented faults. As such, the Tarbert Fm. is now considered the main reservoir of the Gullfaks Field. It has been beneficial to optimise locations of develop-

ment wells also with respect to the evaluation and testing of structural closureslprospects in structurally deeper layers. In fact, an additional 11 % of the STOOIP is proved by development wells in six such structures (Table 2). Even though Gullfaks is a structurally complex field, with many different oil

The primary drive mechanism for oil production is water flooding, maintaining reservoir pressure above bubblepoint. Water injection is and will continue to be the major pressure supporting mechanism together with natural basin influx.

Communication The communication within the reservoirs and between fault Mocks on the Gullfaks Field is a subject of great attention. The best possible picture of the communication relationships throughout the field is formed through the interactive use of structural and stratigraphic information, openhole pressure data, open and cased hole logs, production data, permanentlmemory pressure gauges3, transient well testing and radioactive tracers. The Tarbert and Lower Brent reservoirs show excellent lateral and vertical communication both internally and between fault blocks. Regional lateral calcite layers may locally restrict vertical flow, but good lateral communication still exists. Extensive faulting causes flow patterns which are difficult to predict in heterogenous reservoirs like the Ness and Statfjord fms. Generally, pressure data and well performance indicate good communication within each fault block. Faults with a throw greater than 3010 0 m (reservoir dependent), however, distortleliminate this communication. Major faults are mostly detected

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THE GULLFAKS FIELD DEVELOPMENT CHALLENGES AND PERSPECTIVES by seismic interpretation. Nevertheless, in as much as 70 % of the Gullfaks wells additional small-scale faults not previously seen on seismic are detected. This further complicates communication patterns.

Well Placement A total of approximately 100 wells are needed to develop the Gullfaks Field. Generally, for every two producers one injector is needed. In good homogenous reservoirs like the Tarbert Fm. a set of high capacity injectors ("super water injectors") situated far to the west in fault block row 5 is able to sweep and maintain the reservoir pressure in the formation from west to east. Due to good lateral communication it is possible to place these injectors at a considerable distance from the OWC. This provides a uniform rise of the water level and hence further postpones water breakthrough in the oil producers. On the contrary, a closer configuration between producers and injectors is needed in heterogenous reservoirs. Due to improved drilling and completion technology, high anglelhorizontal wells may be drilled parallel to faults or erosion planes, maximising distance to the OWC, and thereby postponing water breakthrough and improving drainage of attic oil (Fig. 5). Consequently, oil recovery is acceleratedhmproved and the required number of primary wells is reduced. Furthermore, platform wells may now reach areas which were previously planned for subsea development.

Drainage Phi/osophy According to previous FDPs, development was to start with the Brent reservoir in both Phase I and Phase II areas. The Statfjord and Cook reservoirs were to be put on stream when a production plateau was reached in order to compensate for production loss from the Brent reservoir due to water breakthrough. Development of the Brent reservoir was to start with the structurally lower Etive and Rannoch fms. (Lower Brent), continuing with the Ness Fm., and finally producing from the Tarbert Fm. During 1990-1991 this strategy was changed. The Gullfaks Field faced severe water breakthrough in the Lower Brent producers. In addition to a substantial decline in oil production, the total liquid rates dropped due to sand production. Consequently, Lower Brent oil production level stabilised prior t o reaching the planned plateau rate for the field based upon the positive production level experienced during 1989. In order to compensate for this, development of Tarbert and Statfjord sands were accelerated (Fig. 4). Simultaneously, sand control actions were performed in Lower Brent wells, successfully restoring liquid rates to original level, and in some cases increasing the oil production. For this reason, the development of the less productive Ness and Cook fms. were postponed. Simulation

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studies show that both reservoirs need time in order to reach a sufficient recovery. Further delay will therefore have a negative influence on recovery. Furthermore, simulation studies predict water breakthrough in some Tarbert oil producers by 1992, hence making oil production from Ness and Cook wells important in compensating for Tarbert production loss. As such, development of the Ness and Cook reservoirs currently have high priority. Originally, the eastern area (Phase Ill should produce from the Brent reservoir first, followed by the Statfjord and Cook fms. Evaluation work carried out prior to production start indicated that alternating drilling of development wells into the Brent and Statfjord reservoirs would be most beneficial, providingsufficient time to evaluate and incorporate critical data prior to planning of the next well in the same reservoir. The first well drilled from Gullfaks C was originally planned as a high productivity Lower Brent producer. Due to a geological surprise the well was completed as a low productivity Cook producer. Remapping and revised drainage strategy have resulted in the Statfjord reservoir being more important in increasing the production on Gullfaks C than previously anticipated. Recent drilling in southern parts of fault blocks 1 and 2 indicates an increase in Statfjord reserves, further confirming its major role in the Phase II development. Reducing the number of primary wells and accelerating the oil production make commingled production and injection a subject of consideration. A major challenge is the ability to control and monitor production and injection from the various reservoirs. Productivity and pressure contrasts may initiate cross flow and unbalanced flow profiles. This could result in operational problems due to sand production and reduced recovery from low productivity zones.

Lower Brent Lower Brent, being the first reservoir on production, now faces severe water breakthrough in most of the producers in the Phase I area4. Phase II wells have produced for only 2 years and water breakthrough is not expected until 199211993. The characteristic coarsening upward sequence in Lower Brent causes override of injected water, thus causing poorly flushed Rannoch-I and Rannoch-2 sections. Once water breakthrough occurs, the water cut increases rapidly before stabilising at 50-70 %. Perforating low in the Rannoch Fm. does not alone prevent water from entering the Etive Fm. Water production causes sand production at lower liquid rates, hence significantly reducing MSFR. However, the application of sand control methods in water producing wells has increased the total liquid rates, and hence the oil production. In order t o improve the recovery in the low productivity intervals, horizontal wells and propped hydraulic fracturing in the low

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SVElN TOLLEFSEN, ElRlK GRAUE AND STEIN SVINDDAL

permeable Rannoch-112 successfully implemented.

sections

have

beenI

most of the Gullfaks Field, strata within fault block 1 dip gently t o the south. Heterogeneity and faulting of the reservoir have complicated the prediction of communication patterns. Besides, there is virtually no water zone present, enforcing water injection into the oil column. Placing injectors is therefore a subject of great attention, aiming at postponing water breakthrough and improving reservoir sweep.

Tarbert-2 and Tarbert-3 The Tarbert-213 units are the most productive reservoir units on the Gullfaks Field today, generally with permeabilities in the order of 1-10 Darcies (Fig. 6). Good productivity and communication throughout the field give this reservoir highest priority. The reservoir pressure is stabilised at a depletion from initial pressure of 2,000-3,000 kPa throughout the field, although the Tarbert Fm. in the Phase IIarea seems t o be somewhat isolated from the rest of the Tarbert Fm. Pressure data, however, indicate communication with the Lower Brent reservoir in the Phase I area.

Sand control is important in order to achieve good recovery. Selective perforating, gravel packing and chemical techniques have been used and proven successful in various wells.

Cook Production from the Cook Fm. in Phase I started in 1986 when the formation was unexpectedly found oil bearing in the forth subsea development well, A4H. The well was completed as an alternating gas injector and oil producer. The Cook-3 unit is the most important reservoir in the Phase Iarea, whereas Cook-2 has small volumes above the OWC and low productivity (average permeabilities of 1-4 and 0.01-0.1 Darcies respectively). Final development of the Cook Fm. in Phase I starts during 1992, upon which a total of 5 wells will be drilled.

Only two producers on the western flank currently produce water (A-21 and B-l3), however, water breakthrough is expected in wells in the central area (fault blocks 4 and 5) in 1992. The oldest Tarbert well, 9-1, has produced approximately 5.2 mill. Sm3 of oil since 1988. The primary drilling programme will be completed in 1993. Additional offtake points in the Tarbert Fm. will be obtained by sidetracks, recompletions and finally commingled production in high anglelhorizontal wells together with NesslTarbert-1 units.

Two thirds of the Cook reserves in the Phase IIarea are located in the low productivity Cook-2 sands, thus representing a challenge in increasing recovery beyond the expected 15 % resulting from conventional wells and water drive. In addition to the planned low deviation wells producing from Cook-3 sands via induced fractures and perforations in Cook-2, horizontal wells will be considered drilled through the entire Cook2 section. As such, all barriers may be penetrated with the longest sections possible in each sand body. Vertical producers will be fractured and stimulated using proppants in order t o maximise productivity from Cook-2. Final development of the Cook Fm. in the Phase II area is to commence in 1993.

Although the NesslTarbert-1 reservoirs have several highly productive sands, small sand bodies with limited lateral and vertical communication within the units make reservoir management challenging. Pressure and log evaluation confirm the complexity of fluid flow. Local pressure differences between Ness sands may be as high as 3,000 kPa. Tarbert-213 and Lower Brent production influence fluid movement in NesslTarbert-1. Pressure depletion was observed prior to development of the NessKarbert-1 reservoirs. Tarbert-213 influences production in upper parts of the Tarbert-1 and Ness reservoirs, whereas Lower Brent affects production in the Ness-1 and Ness-2 units.

WELL COMPLETION

The NessKarbert-1 units will be developed with higher well density than the other reservoirs. This will partly be obtained by commingling and recompleting both Tarbert-213 and Lower Brent wells which penetrate the Ness Fm. Unconsolidated formations, pressure variations and expected rapid water breakthrough demand sand control. Reservoir simulation models and field observations suggest water breakthrough within the first year of production. The ability t o process produced water as well as handling associated sand production are key factors in the NessKarbert-1 development.

The Gullfaks wells have traditionally been completed with a standard 7" liner and 5 'k" tubing configuration (Fig. 8). But since a wide variety of well operations are required in the various wells, the standard completion configuration, along with increasing well deviations and complex well paths, have frequently complicated such operations. To improve access, the completion configuration was therefore simplified by introducing the MONOBORE concept (Fig. 8). In this configuration the 7" liner is directly connected to a 7" tubing configuration t o the surface, resulting in a smooth pipeline from bottomhole t o surface. This approach has significantly reduced the number of workovers which would otherwise be required, e.g. having to pull the tubing prior to gravel packing "old" wells. Thus, the

Statfjod Formation Production from the Statfjord Fm. started in 1990. In contrast to the characteristic westerly structural dip in

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THE GULLFAKS FIELD DEVELOPMENT - CHALLENGES AND PERSPECTIVES risks of higher operational costs and delayed drilling programmes are reduced as well.

THE SAND PRODUCTION PROBLEM The highly productive reservoir sands of the Gullfaks Field are poorly cemented and consolidated. For this reason the high production potential in most oil wells in the field could not be fully utilised due to sand production. In order to overcome this problem, the strategy originally focused on selective perforation in consolidated sand intervals, primarily in Lower Brent wells. Thus, oil in the surrounding highly permeable sands of poor consolidation was produced through these perforations. The consolidated intervals were identified from core data, openhole log data and past experience. The strategy was successful for some time, however, upon experiencing water breakthrough in the wells, MSFR was significantly reduced. As such, sand control would be required in order to maintain high production rates at the field. Gravel packing has so far been the major method of sand control, but other methods are also currently being testedlinvestigated.

SAND CONTROL - A REVIEW OF PAST EXPERIENCE AND RECENT DEVELOPMENTS Gravel Packing Sand Control

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Established Method of

The first gravel packed well at the Gullfaks Field, well A-23, was packed across a 41 m perforated interval in May 1989. The method has been greatly improved ever since. Productivity loss due to the potential collapse of poorly gravel filled perforation tunnels, and subsequent fill-up of poorly sorted reservoir sand, is prevented by increasedunderbalance during perforation and improved prepacking techniques. Due to the danger of bridging during gravel packing, particularly in highly deviated wells, the maximum length which could be gravel packed in one single stage has been restricted. Previously, therefore, sand control actions across long intervals implemented use of multistage gravel packing techniques, e.g. well A-33, which was gravel packed in 4 stages across a total interval of 150 m. However, this is a time consuming and expensive procedure. By introducing the shunt tubular system these problems were significantly reduced. The shunts provide a passage for the gravel pack slurry in tubes with restricted leak off and reduce the danger of

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bridging. The tubes are mounted along the outside of the screens. Consequently, it is possible t o gravel pack much longer intervals in one single stage, thereby reducing operational duration and costs due to delayed production. The longest single stage gravel pack to date was installed in the 68O deviated well 8-20 in February, 1992, with a total length of 11 0 m. Another costly aspect of gravel packing wells with 5 H" tubing configurations was that the operations had to be carried out using the drilling rig, deferring other drilling operations and eventually reducing the field production revenue. Recent estimates indicate that total costs of delaying drilling operations 1 day amounts to approximately NOK 5 mill. (USD 800,000). Although the introduction of the 7" MONOBORE system (eliminating the necessity of pulling production tubings) and enhanced gravel packing technology reduced the duration of gravel packing operations, the costs involved are still significant. For this reason, a separate snubbing rig now carries out such operations. While the snubbing rig is occupied gravel packing one well, the drilling rig may drill the next well at another location on the platform. Additional costs of operating the snubbing unit are minor compared with the savings achieved by preventing deferments on the primary drilling programme. To date, 17 oil wells (35 % of all the production wells) have been gravel packed. Production experience from these wells is good, and close to half the total field production is currently produced from these wells.

Stimulation of Gravel Packed Wells Although the extensive gravel packing scheme implemented in Gullfaks oil wells has increased MSFR and thus production rates to a significant degree, decline in productivity from some of the wells is observed over time. The tendency is most pronounced in the older wells which were perforated in low underbalance and gravel packed without first being prepacked5. Even though the mechanism by which the productivity starts declining is not yet fully understood, significant efforts have been made in order to develop a satisfactory stimulation procedure for restoring productivity in gravel packed wells. The first stimulated well was A-23 in December 1990. Since then, several gravel packed wells have been stimulated, the experience from each job contributing towards a continuous improvement of the procedures. The present "state of the art", aiming primarily at dissolving and stabilising clay minerals, involves the successive injection of mud acid followed by clay acid6. In order to gain experience from each stimulation job, wells are, whenever possible, production tested both prior to the stimulation and immediately after. Multirate well testing generally confirms a significant increase in productivity immediately after stimulation. Similar tests run at a later time, however, show that productivity starts to decline again after some time. Such observations enforce a somewhat frequent stimulation sche-

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dule. Several wells, among those well A-23, have been restimulated. Because of the fairly high level of costs involved, particularly due to a relatively long bean-up period after stimulation, the timing of such jobs must be carefully considered in an overall cashflow analysis.

Producing Gravel Packed Wells With Pressure In Gravel Packed Region Below Bubble Point There is a somewhat significant pressure drop across the gravel pack and the transition between crushed zone and prepacked perforation tunnels (Fig. 9). As such, it is possible to increase the production rate in gravel packed wells by lowering the flowing pressure within the gravel packed region below bubble point, whilst at the same time maintaining the near-wellbore reservoir pressure above bubble point. Due to turbulence effects, this pressure drop is clearly rate dependant, and may typically vary between 5003,000 kPa. The pressure drop has been quantified by the application of multirate well testings. Hence, by plotting sandface pressure and pressure drop across the gravel pack as functions of production rate, it is possible to estimate an additional production potential (Fig. 10). The principle is applied in several gravel packed wells at the field and has increased production rates in these wells by approximately 20 %. Naturally, the gain would be at its highest in wells having significant pressure drop across the gravel pack. Such wells are, however, normally restricted by minimum well head pressure, and would probably therefore at some point be subjected to acid stimulation in order to reduce the pressure drop as much as possible. By applying this principle it is possible, nevertheless, to defer such stimulation jobs to a significant extent.

The obvious advantage of this method compared t o standard gravel packing is the non-restricted wellbore, providing improved access to operations in the well. Should the method fail, it is still possible to install a gravel pack across the treated zone. On the other hand, it is necessary to drill and circulate out consolidated excess materials afterwards. This is carried out using a snubbing rig. The application of alternate pumping of resin slurry and chemical diverters have made it possible to treat long intervals in one single stage. Well C-8 was recently treated by this method over a 113 m zone containing 8 separate perforation intervals. A 3 m perforation interval in well B-20 was subjected to direct injection of consolidating chemicals in April 1992. The injected chemicals, an epoxy resinlafterflush system, were placed using snubbing equipment. Significant sand production afterwards indicatesfailure, most probably due to incomplete placement of the chemicals. Unfortunately, the well operations time schedule did not permit any logs to be run afterwards in order t o confirm the cause of failure. The well is currently being gravel packed across this interval.

Propped Hydraulic Fracturing By this method a fracture is created in a low permeable reservoir zone (with high degree of sand consolidation) and filled with proppants in order to keep it "open". The fracture is designed such that it extends into the overlying highly productive reservoir sands with low consolidation7. The technique was recently implemented in several oil wells in the Lower Brent reservoir. A major problem was initially related to proppant flowback during production, primarily due to extremely low net confining pressure along with required high flow rates. To rectify this problem, resin coated proppants have later successfully been applied.

Chemical Sand Control Methods Generally, there are two alternatives of chemical sand control methods available today: Squeezehnjection of phenolic resin coated proppants (resin slurries) into cavities behind casing and in the perforation tunnels Direct injection of consolidating chemicals into the formation The injection of resin slurries has successfully been implemented in several wells on the Gullfaks Field. The first well, B-2, was treated in August 1991, increasing the maximum sand free liquid rate by approximately 50 %. Carbolite or just normal, carefully sized sand have been used as proppants. The proppants are squeezed into the perforation tunnels and other cavities behind the casing caused by previous sand production and act essentially as porous plugs preventing sand grains from entering the wellbore.

LOOKING AHEAD Continuous Reservoir Development Pressure support in the heterogenous formations like Ness and Statfjord will represent a major challenge in the years to come. Economical and technical considerations may not justify the drilling of injectors in small fault blocks with restricted communication to adjacent fault blocks. Thus, concepts such as producing wells with reservoir pressure below bubblepoint must be carefully considered in order to maintain production rates and achieve satisfactory drainage. The horizontal well concept as an approach for improving oil recovery was recently applied to the Gullfaks Field upon the drilling of Lower Brent well A34A. The plans ahead are to implement this concept in the Upper Brent reservoirs by drilling horizontally through both the stratified Ness Fm. as well as the

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THE GULLFAKS FIELD DEVELOPMENT CHALLENGES AND PERSPECTIVES Tarbert Fm. Instable hole conditions during drilling and completing the well with satisfactory sand control are aspects which require careful planning and sophisticated technical solutions. Horizontal cased hole gravel packing across a 400 m perforated interval is currently being planned for sand control purposes in well 8-23 (which will be the first horizontal Upper Brent well on Gullfaks). The efforts of reducing injection water override effects in the Lower Brent and Ness reservoirs will continue. Established methods, such as zone isolations, perforating wells structurally deep, varying perforation density and drilling horizontal wells in low permeable sands will be applied and further improved in the future. The approaches of WAG injection and various high productivity reservoir blocking techniques, will be also be considered for application on a field scale basis.

Production With Reservoir Pressure In NearWellbore Region Below Bubble Point The Gullfaks Field is classified as an undersaturated oil reservoir. Upon proposing the original field development plans, attention was therefore paid to potential problems of reduced recovery and productivity due to the creation and production of secondary gas. As such, the field was planned exploited by a complete reservoir pressure maintenance scheme, maintaining the reservoir pressure above bubble point. Detailed reservoir simulation studies have, however, identified a potential of accelerated oil production in some wells by reducing near-wellbore pressure below bubble point. This increases pressure drawdown and hence production rate. By producing the wells at a rate corresponding t o a particular pressure drawdown profile, aided by detailed reservoir simulation, it is possible to control secondary gas movement such that all liberated solution gas may be produced directly and evenly distributed into the well. A pilot programme was initiated in April 1992 in the horizontal well A-34A, includingthe careful monitoring of productivity development and GOR/wellhead pressure in this well and the stratigraphically higher surrounding wells B 4 and 8-7. The programme resulted in an immediate increase in production rate by approximately 4 0 % in well A-34A. No decline in productivity due to gas blocking or reduced relative permeability to oil is observed yet. Other wells are currently being evaluated for potential production with near-wellbore pressure below bubble point. The creation of secondary gas caps for the purpose of draining additional oil reserves structurally updip of the wells (attic oil), may be a possible approach to enhanced recovery provided it is possible to control gas movement in the reservoir. Producing oil wells downdip below bubble point may as such represent an alternative to secondary gas injection.

SPE 25054

Enhanced Oil Recovery - Advanced Methods Motivation Reservoir simulations based on the current field development strategy predict that more than 300 mill. Sm3 of oil will remain in the Gullfaks reservoirs at the end of field life. A substantial part of this oil is contained in rocks with excellent reservoir properties. All the major platforms are installed, and uncertainties concerning reservoir architecture, fluid distributionsand flow performance decrease as more field history becomes available. Itis an obvious challenge to recover as much of this oil as possible, which is one of the main goals of the Current reservoir management efforts.

An extensive programme has been initiated to verify techniques or methods capable of improving recovery on the Gullfaks Field. The stages in a process of selecting and verifying EOR methods are as follow: 1. Identify the EOR potential.

2. Identify applicable EOR methods. 3. Conduct laboratory testing and simulation studies. 4. Perform well tests and field pilots. 5. Implement on field scale.

Potentials Remaining oil in the Gullfaks reservoirs are mainly associated with: high residual oil saturation poor vertical sweep efficiency attic oil residuals low permeability regions

Method selection Three systems are identified to have an EOR potential specifically for the Gullfaks Field (Fig. 111. These are: Water-alternating-gas injection I WAGI, improving vertical sweep efficiency and recovering attic oil.

Thin polymer gels, - blocking high permeable reservoirs to improve vertical sweep efficiency in low permeable reservoirs. Surfactant flooding, reducing residual oil saturation by improving microscopic sweep efficiency.

SPE 25054

SVElN TOLLEFSEN, ElRlK GRAUE AND STEIN SVINDDAL

Proiect status

wells drilled from the B-platform. Natural water influx is expected to provide sufficient pressure support. Drilling is due in 1993.

The WAG project started in 1990. Simulation studies were performed in order to identify the improved oil recovery potential. A pilot test was designed and the necessary modifications on the water injector ended in January 1991. The pilot test commenced in March 1991, and up to June 1992 three gas injection periods were performed in the central area of the field (fault block 3F). Gas breakthroughs were observed in the main target wells. Maximum water cut decreased from 54 % to 42 % in the main target well. Post test simulation studies show improved recovery of approximately 100,000 Sm3 of oil. A more extensive WAG implementation, including more water injectors, is currently evaluated.

The Tordis Field, located in block 3417 (Fig. 1) and operated by Saga Petroleum A/S, was discovered in 1987. Pressure data showed depletion of oil in the Brent Group caused by the Gullfaks Field production. The FDP involves a subsea development connected to the C-platform with pressure maintenance by water injection. Production start is planned for 1994. Production well C-7 proved oil in the Lunde Fm. in the eastern part of the Gullfaks Field (fault block 1). Oil was earlier observed in exploration well 34110-13. The Lunde reservoir was production tested in C-7, but showed an immediate decline in reservoir pressure, indicating a somewhat limited communication in parts of the formation. Evaluation of development strategy will start in near future.

The thin polymer gels project was initiated in 1989 for the development of a chemical system capable of selectively blocking override zones some 50 to 100 meters into the reservoir. Three different systems are identified with interesting properties. A field test is planned in 1993. The surfactant flooding project started in 1989 by screening studies and optimising of a surfactant system for the Gullfaks Brent oil. The system reduced residual oil saturation in core flooding experiments from 3 5 4 0 % to 5 %. Two field tests have been performed in two different wells t o verify laboratory results. Measurements of residual oil saturation were carried out using the Partitioning Tracer Test Technique, along with an extensive logging programme. Data are currently being evaluated. Depending on the results, a further pilot field test will be considered.

The Gullfaks Field area is structurally complex. 70 % of the wells prove minor or large faults not previously seen on seismics. Continuous production drilling has resulted in a redistribution of the estimated reserves. The Tarbert Fm. is now the main reservoir on the field. Accelerating the development of the highly productive Tarbert and Statfjord fms. increased the plateau rate of the field. Advances in drilling and well completion, commingled productiontinjection and highcapacity water injectors accelerate oil production and reduce the total number of wells required.

Discoveriiw and prospects A number of recent discoveries and promising prospects are located in the vicinity of the Gullfaks Field. Three discoveries with proven significant reserves are the "Gullfaks Snr", the "Gullfaks Vest" and the "Tordis" Fields. In addition, the Lunde Fm. in fault block 1 was found oil bearing in well C-7 (Fig. 1).

Gravel packing is currently the main technique of sand control on the Gullfaks Field. Recent improvements have reduced costs of implementation and improved production behaviour. Squeezehnjection of resin coated proppants has proved a successful and cost effective method of chemical sand control in "old" production wells.

Exploration well 34110-2, drilled in 1978, led to the discovery of the Gullfaks Ssr Field (Fig. 1). Further appraisal drilling proved oil and gas in both the Brent Group and the Statfjord Fm. The field is structurally complex with many different OWC's and pressure regimes. An FDP has not yet been approved by the licence, but preliminary plans indicate a separate platform with flowlines to the main field for processing and transport. One or two long range wells may be drilled from the,P-platform, accelerating production start from the oil ;one. Exploration well 34110-34, drilled in 1991, led t o the discovery of the Gullfaks Vest Field (Fig. I), proving oil in the Tarbert and Ness fms. According t o current plans, the field will be woduced from two horizontal

385

9

THE GULLFAKS FIELD DEVELOPMENT - CHALLENGES AND PERSPECTIVES

10

ACKNOWLEDGMENT

3.

Unneland, T. and Haugland. T. "Permanent Downhole Gauges Used in Reservoir Management of Complex North Sea Oil fields' Paper presented at the 3rd Latin American Petroleum Congress, CONEXPO ARPEL, Rio de Janeiro, Brazil, October 18-23, 1 9 9 2

4.

Anes, H.M., Haga, O., Instefjord, R. and Jakoben, K.G. "The Gullfaks Lower Brent Waterflood Performance' Paper presented at the 6th European Symposium on Improved Oil Recovery, Stavanger, Norway, May 21-23, 1991

The authors wish to express their sincere thanks to all colleagues at Statoil Bergen Operations for their advice and encouragement in producing this paper. The authors would also like to thank the management of Den Norske Stats Oljeselskap a.s IStatoilA/SI, Norsk Hydro A/S and Saga Petroleum A/S for their permission to publish this paper.

Svendsen, 0.. Kleven, R., Abnes, N. and Hartley, I. 'Stimulation of High Rate Gravel Packed Oil Wells Damaged By Clay and fines Migration: A Case Study, Gultfaks field, North Sea" Paper SPE 24991, presented at the European Petroleum Conference, Cannes, France, November 16-1 8, 1 9 9 2

REFERENCES 1.

Vollset, J. and Dor6. A.G. "A Revised Triassic and Jurassic tithostratigraphic Nomenclature for the Norwegian North Sea' Norwegian Petroleum Directorate Bull. No.3, 1-53, 1 9 8 4

2.

Pettorson, 0.. Storfi, A., Ljosland, E. and Massie, I. "The Gultfaks fie1d:Geolog y and ReservoirDevelopment" North Sea Oil and Gas Reservoirs-ll, The Norwegian Institute of Technology, Graham & Trotman, 1 9 9 0

TABLE 7:

SPE 25054

6.

Unneland, 1.and Waage, R.I. "E'xperienceand Evaluation of PIoduction Through High Rate Gravel Packed Oil Wells, Gultfaks field, North Sea' Paper SPE 22796, presented at the 1991 SPE Annual Technical Conference and Exhibition, Dallas, Oct. 6-9

7.

Bale. A.. Owen, K. and Smith, M.B. "Propped Fracturing as a Tool for Sand Control and Reservoir Management " Paper SPE 24992, presented at the European Petroleum Conference, Cannes, France, November 16-1 8, 1 9 9 2

Estimated Recoverable Reserves at Gullfaks

Y w

1981 1984 1988 1992

-

Upper Brent '

" "

"

'

Lowga Brsnt '

''

'

'

'

'

'

"

"'

'

Statfjord

Cook

.

TOTAL

IcPSmJ

%

lob sm3

%

lob Sm=

%

lo= sm3

%

lo" sm=

55 70 83 108

24 33 39 47

135 109 81 75

59 52

40 12 13 21

17 6 6 9

19 33 26

9 16

230.0 210.0 210.0 230.0

39 33

11

TABLE 2: Hydrocarbon Contacts and Volume Distributions at Gullfaks Reservoir

Ateatfault block

ST001P

OWC I

Brent

Phase 1/11 lexcl. 2A,6A,6B, 6AI

Statfjord Cook

Phase II Phase II

Brent Cook Statfjord Cook Brent Lunde "I

Reserves proved by development ws/s, partly incorporated in recoverable reserves

1

I

I

SPE

LOCATION MAP

The Gullfaks Field

Fig.1 Location map of the Gullfaks Field.

25054

SPE

.......... .,.-. . @ ,

OIL -6 ' i C GAS WATER FL.OWI.INE SUBSEA WELl SUBSEA COMPLETED INJECTION WELL Q s rn. 2,: k r r ~

- - -

il

Fig.2 Field facilities, design capacities and infrastructure.

25054

tructural depth map,

producer ir,Injector

......: OWC

6BEo:

number

Intersection Base Cretaceous unconformity and the fault plane: T. Brent eroded m B. Brent eroded

-

o ---0.5

1.5

km

Fig.3 Structural depth maps

Structural depth map, Top Statfjord Fm.

SPE

Production rate (Smsd) -

-

1

EBIRannochIEtive

3c FDP -88

Fig.4

Tarbert 133Ness

Statfjord I C o o k '

-

Current history and forecast 1992 update compared to Field Development Plan 1988

I

A

25054

SWI

I

TP

M

TP

. TARBERT PROWCER

TP~/~'~T/N!'

SWI : SUPER WATER NECTOR : N S S NECTOR : COOK NECTOR : STATFJORD NECTOR

NP : N S S PROWCER.

N

LBP : LOWER BRENT PROWCER CP . CO(X PROWCER SP . STATFmD PROWCER

CI SI

NIRI CI

LBP

SP

LBP CP

' Hwizmtal scab apfm&mt&y 3 x vertical

a

j

PERMEABLE

IWi PERMEABLE

SI

NO VERTICAL BARRERS

-.

VEfllCAL BARRERS

0

LOW PERMEABLE SANS. VERTICAL BARRLRS

Fig.5 An east-west cross section showing structural styles, setting and we1 placement of the GuUfaks Field

YULE

PROOELNi

DEEP MARINE SHALES

RESERVUR

cam FIWECRUW

NEARWORE

DEEP MARINE %ALES

Fig.6 A composite log display. Composed of wells 8-9 (Brent), C-3 (Cook) grid C-2 (Statfjord).

SPE B E F O R E DRILLING

A F T E R DRILLING 0-3

ig. 10

Production potential in gravelpacked wells.

Fig.7 Segmentation of a fault leaves more of the reservoir above the OWC, compared to a "one big fault" situation. ( Modifiedafter Petterson et.al. )

m

5 1/2" TUBING COMPLETION llNlMUM ID: 3.7"

Fig.8

r

MONOBORE C o M P m a MINIMUM ID: 6"

5 112 Tubing and 7" Monobore completion configurations

SURFACTAN T

OIL

GEL

0GAS Fig.9

Shematic perforation tunnel in gravel packed wells showing various pressure regimes.

WATER SURFACTANTS+ MOBlLlSED O I L

g.11 Improved vertical (GELIWAG) and microscopic (surfactant) sweep efficiency.