Strong Aquifer Research Articles

Intelligent-Fields Management at Woodside: Using Off-the-Shelf Technology

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 116519, "Intelligent-Fields Management at Woodside: A Low-Cost Step Improvement in Field Management Using Off-the-Shelf Technology," by Bruce James, SPE, Kevin A. Kerr, Stephanie Lim, SPE, Ed Lewandowski, SPE, Craig Knight, SPE, and Richard Bell, SPE, Woodside Energy, prepared for the 2008 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 20-22 October. The paper has not been peer reviewed. By use of improved integration, data efficiency, and more-informed decision making, Woodside's intelligent-fields-management (IFM) system has improved the way its Cossack/Wanaea/Lambert/Hermes (CWLH) fields are managed. The greatest value was in improved integration of data and work practices and in longer-term reservoir management. Introduction The overall goal was to improve management of oil and gas fields through better integration of workflows and data, with an emphasis on use of real-time production data and downhole-flow control. This review focused on improved integration of work processes and information. Common applications include production optimization, allocation, and surveillance by use of data-driven neural networks. This case study describes how Woodside's IFM program was implemented and discusses accomplishments in a 12-month period at relatively low cost starting with little pre-existing knowledge. Initially, the current IFM program focused on near-term management issues, such as well-test deferral and daily optimization of the CWLH fields. The system is proceeding on two other oil fields, and efforts are under way to expand the program to gas fields and to other parts of the life cycle, such as reservoir management. CWLH Fields The CWLH oil fields are offshore Western Australia, 125 to 145 km northwest of Karratha (Fig. 1). The Lambert and Hermes fields are 15 km north of the Wanaea and Cossack fields. The fields lie on the inner continental shelf in water depths of 75 to 135 m. The fields are produced through the Cossack Pioneer floating production, storage, and offtake facility through a subsea system of 11 wells tied back by flowlines. Production from the Wanaea and Cossack fields began in November 1995. The Hermes field came on stream in October 1997, and the Lambert field began production in September 1999. Well testing is conducted by diverting individual wells into the dedicated test separator. High recovery is the result of high reservoir permeabilities, excellent reservoir continuity, and a strong aquifer drive. The produced-fluid gravity ranges from 47 to 48°API, viscosity ranges from 0.17 to 0.5 cp, and gas/oil ratio (GOR) ranges from 140 to 1,300 scf/STB. All four fields are undersaturated.

Analysis of Possible Applications of Dual ESPs—A Reservoir-Engineering Perspective

Summary Relatively few field installations of a dual-electric submersible-pump (DESP) completion have been reported. In general, the purpose of the second pump was either to increase the pumping capacity, or to act as a backup to improve the reliability of the pumping system. However, DESPs potentially can address a much wider range of reservoir management challenges. This paper will analyze the performance of a DESP in a range of reservoir scenarios. It will show how DESP performance can be modeled by use of commercially available, coupled, well-performance and reservoir-simulation tools. Four DESP applications were analyzed. Where possible, the robustness of the numerical-modeling results will be compared with analytical predictions. DESPs gave improved oil production and recovery in reservoirs with strong aquifer support and became progressively more attractive in a layered-reservoir scenario as the pressure difference between the production zones increased. However, while DESPs had no significant advantages in a long, horizontal well placed in a homogeneous reservoir, they can increase recovery in a tilted, layered reservoir. A slim, deepwater well completed with a lower-capacity downhole pump and a larger (multiwell) seabed booster pump was shown to be a potentially attractive solution for some reservoir developments. This work provides a comparison of the drivers for the choice of a single electric submersible pump (SESP) and a DESP in the scenarios studied. It illustrates a modeling methodology and provides DESP-selection guidelines, thus aiding the increased application of this technology.

Reviving the Mature Handil Field: From Integrated Reservoir Study to Field Application

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 110882, "Reviving the Mature Handil Field: From Integrated Reservoir Study to Field Application," by Henricus Herwin, SPE, Emmanuel Cassou, SPE, and Hotma Yusuf, SPE, Total E&P Indonesie, prepared for the 2007 SPE Asia Pacific Oil & Gas Conference and Exhibition, Jakarta, 30 October-1 November. The Handil field, discovered in 1974, is a giant mature oil field in the Mahakam Delta of Indonesia. Fieldwide production declined from 200,000 BOPD in the late 1970s to 12,500 BOPD in 2003. An integrated study on the largest gas-injection reservoir was performed to assess project performance. An intensive light-workover (LWO) campaign was launched, and three pilot wells, each with a different type of completion, were put on production successfully. Infill drilling and optimization of an enhanced-oil-recovery (EOR) project also were implemented. Fieldwide production increased to 23,000 BOPD. Introduction As Fig. 1 shows, the Handil field comprises 555 unconnected accumulations (reservoirs) in structurally stacked and compartmentalized deltaic sands. The reservoirs are trapped by the Handil anticline, which is cut by a major impermeable fault dividing the field into two compartments: north and south. The reservoirs are between 200 and 3500 m subsea and cover an area 10 km long by 4 km wide. Three reservoir characteristics distinguish the field.Shallow zone: This zone is as deep as 1500 m subsea, with excellent permeability ranging from 200 to 2,000 md and with very strong aquifers that maintain the reservoir pressure at initial condition. However, the sands are poorly consolidated, requiring sand-control techniques.Main zone: This zone is between 1500 and 2200 m subsea, with permeability between 10 and 500 md. Most reservoirs had initial-gas caps, which have been pre-served to maintain the reservoir pressure, especially because the aquifers are not as strong as those for the shallow reservoirs. The sands are normally well consolidated; therefore, sand production is not an issue.Deep zone: This zone is below 2200 m subsea, contains mostly gas, and decreases in quality with depth to a permeability of several millidarcies. Production History To maintain production and reservoir pressure, water injection was started in 1978, which maintained the 160,000 BOPD production until 1985. Gas lift was introduced in 1979 and was implemented fieldwide in 1991. Infill drilling has helped maintain production. More than 350 wells have been drilled in the field, with an average spacing of 300 m. In November 1995, a lean-gas-injection project was initiated in five reservoirs. The project boosted the production of the five large reservoirs and altered the overall decline rate of the field. Therefore, the project was extended in 2000 to six other large reservoirs, which resulted in more than 25% of the field reserves being under a tertiary-recovery mechanism. In 2003, field production had declined to 12,500 BOPD.

Field-Scale Compositional Simulation of a CO2 Flood in the Fractured Midale Field

Abstract A stimulation test using electric heating was conducted on a single oil production well in the Schoonebeek reservoir in The Netherlands during 1989 and 1990. The performance of the test and its interpretation is described. The Bentheim reservoir sands are 31 m thick with a porosity of 0.3 and a permeability in the range 0.2 - 4 µm2; the oil has an in-situ viscosity at 160 mPa.s and is waxy with a cloud point very close to the reservoir temperature of 40 °C. The reservoir pressure of about 7000 kPa is supported by a strong edge aquifer. The objective of the test was to stimulate oil production with heat and, particularly, to melt wax that was suspected to be present either near the wellbore or uniformly throughout the reservoir. Prior to stimulation the oil production rate was 13 m3/d at a water cut of 35%. As the surface power dissipated was increased above 60 kW, the oil production rate increased abruptly to 30 m3/d with a bottomhole temperature in the range 54 to 60 °C; at higher power levels no further increase of production rate was observed. Analytical methods proved very useful for understanding the electric healing process, particularly for tracing the electric current flow path in the reservoir and for modelling the heat distribution and production response. Numerical simulations of the well's performance showed that the observed abrupt increase of oil production rate was compatible with the melting 01 wax at 60 °C and partial removal of a skin (of approximately 27) but not of a wax deposited uniformly throughout the reservoir. Introduction Though electrical heating has been used to stimulate well productivity al various times over the last 25 years, it is not widely applied. A lest of the stimulation method was recently completed on Well SCH-280 in the RW2-E area of the Schoonebeek oil reservoir of The Netherlands (see Figs. 1 and 2) by the Nederlandse Aardolle Maatschappij B. V. (NAM). In this paper we describe the properties of the Schoonebeek reservoirand the characteristics of Well SCH-280 and review the objectives, test programme and actual performance of the electric heating stimulation (EHS) test. In several respects, the information required to interpret the test unambiguously was not available. To circumvent these limitations, methods were developed for inferring the electric current flow path and heat distribution in the reservoir, Using both analytical and numerical simulation methods, a broadly consistent interpretation of the test was developed and this is described herein. FIELD PERFORMANCE OF OTHER ELECTRIC HEATING TESTS Over the last 25 years there have been a number of reports in the literature of planned or executed field tests of the electric heating process, mostly based on the ohmic dissipation of electric energy in the formation. Electrothermic Co., for example, stimulated four wells of the Little Tom field in South Texas. The reservoir there contains 8 - 12 °API gravity oil with a high pour point [1,2].

Design and Performance of a Water Disposal Well Stimulation Treatment in a High Porosity and Permeability Sand

Abstract Injectivity problems associated with produced water disposal have been ongoing in the Masila project in Yemen. Disposal wells experience an immediate low injectivity upon commencement of injection as compared to the productivity measured during pumping clean-up of the wells. It has been hypothesized that this behaviour, referred to as the check-valve effect, is caused mainly by mobile formation fines in the near-well vicinity. Injectivity often declines further because of plugging by impurities in the disposal water. Laboratory and field work have been done to test several methods of improving water disposal well performance, including the application of horizontal wells and proppant fracture stimulation of vertical wells. Another technique tried in the field was a stimulation treatment involving HCl/HF acid followed by a thin-film polymer. The intent of the treatment was to destroy potentially mobile formation fines in the near wellbore area and then to stabilize those that remained in an attempt to reduce the check-valve effect. The acid and polymer treatment was developed through laboratory core testing and was employed on a newly drilled water disposal well. The procedures and results of the laboratory work are described along with the design and implementation of the stimulation treatment. The injection performance of the well is examined relative to other disposal wells in the field. Initial results of the stimulation treatment were disappointing but the well has improved over time to become a moderately good injector. However, the results of the test have not provided enough encouragement to date to warrant further work in the field. Introduction The disposal of produced water in the Masila project in the Republic of Yemen has been the subject of a number of earlier papers(1–3). Field water production has been rising steadily in recent years due to the strong aquifer support in the Upper Qishn reservoir section. These reservoirs are high porosity and permeability and exhibit superior production characteristics. Current oil and water production levels are 36,566 and 198,728 m3/d, respectively. All of the produced water is disposed of through reinjection into the producing formations. Injectivity problems continue due to the nature of the formations and the quality of the disposal water. Details of the injectivity problems and investigations as to their causes have been discussed previously(1). The performance of four horizontal disposal wells and the results of four proppant fracture stimulated vertical disposal wells have been presented(2). In addition, a stud has been published of continuous high-pressure injection above formation parting pressure as an aid to injectivity(3). Laboratory and field trials have indicated that injectivity problems are caused by a combination of native reservoir fines migration, formation plugging by injected solids and oil, and the formation of calcite scale downhole. Several authors have discussed such injectivity problems and their causes in some detail(4- 8). In addition to the use of horizontal wells and proppant fractured stimulated vertical wells, a field trial was conducted of an acid stimulation technique designed in the laboratory.

The Effect of Thief-Zone Identification and Shutoff on Water Production in the Nimr Field

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 91665, "Impact of Thief-Zone Identification and Shutoff on Water Production in the Nimr Field," by Richard S. Medeiros, SPE, Petroleum Development Oman; Deepankar Biswas, SPE, DeGolyer and MacNaughton; and P.V. Suryanarayana, SPE, Blade Energy Partners, prepared for the 2004 SPE/IADC Underbalanced Technology Conference and Exhibition, Houston, 11-12 October. The full-length paper describes ongoing efforts to improve the performance of Nimr wells by identifying and shutting off thief zones and summarizes the results to date. Underbalanced drilling (UBD) data have shown that rogue fractures and bypass zones play a key role in the movement of water through Nimr reservoirs. UBD was used to identify nonmatrix water-bearing features and shut them off by use of different shutoff techniques, including a new selective shutoff completion tool. Introduction The Nimr field in southern Oman is a group of six fields, most of which are mature oil fields operated by Petroleum Development Oman (PDO). The fields A, B, E1, E2, and G produce medium-gravity viscous oil under strong bot-tom waterdrive. These fields contain more than two billion bbl STO initially in place and have been on production since the mid-1980s. Initial development was by vertical wells, but since the mid-1990s development primarily has been by horizontal wells. Production is from a combination of Cambrian aeolian and carboniferous glacial sediments. Reservoir het-erogeneity is high, particularly in the glacial Al Khlata reservoirs. Combined production from the Nimr fields accounts for more than 10% of current PDO oil production and is produced from approximately 500 active wells at an average 93% water cut. A combination of unstable displacement, strong aquifer drive, complex geological settings, and nonmatrix permeability events has resulted in unpredictable new-well performance with progressively higher initial water cuts. In this respect, Nimr presents the typical problems of a mature field—that of water movement and its effect on sweep and recovery. One of the key developmental strategies has to be identification and mitigation of water movement, thus reducing the amount of water produced and improving net oil production. UBD. UBD began in the Nimr A field in 2002. UBD typically is used to increase well productivity by eliminating drilling-induced formation damage for faster drilling/penetration rates. Although UBD was initially used in Nimr for these objectives, its long-term value has been its reservoir-characterization (RC) data. Nimr is one of the unique fields where the RC benefits of UBD have driven its continued use in the field. The investigations carried out using UBD RC data in 2002 and 2003 have resulted in the evaluation and exploitation of two significant opportunities in addition to other large, longer-term opportunities currently being developed.

The Auk Field, Block 30/16, UK North Sea

Abstract The Auk Field is located in Block 30/16 at the western margin of the Central Graben. Block 30/16 was awarded in June 1970 to Shell/Esso, and the discovery well 30/16-1 spudded in September 1970. The well found oil in a complex horst block sealed by Upper Cretaceous chalk and Tertiary claystones. The field contained an original oil column of up to 400 ft within Rotliegend sandstones, Zechstein dolomites, Lower Cretaceous breccia and Upper Cretaceous chalk. Production by natural aquifer drive commenced from a steel platform in 1976, initially from the Zechstein carbonates and now predominantly from the Rotliegend sandstone. Artificial lift was installed in 1988 helping to maintain production at economic levels past the year 2000. A complex reservoir architecture with cross flow between the Rotliegend and Zechstein reservoirs, a strong aquifer causing early water breakthrough via faults, and a limited seismic definition led to significant production variations from the initial forecasts. Equally important for the field, horizontal well technology opened up additional reserves and accelerated production from the complex Rotliegend reservoir; the most recent volumetric estimate for the total field predicts an ultimate recovery of 151 MMBBL for the existing wells from a STOIIP of 795 MMBBL . Full field reservoir simulation and 3D seismic data acquisition took place since mid 1980s but only recently resulted in a satisfactory understanding of the reservoir behaviour. The field is situated about 270 km ESE from Aberdeen in 240-270 ft of water. It covers a tilted horst block with an area of 65 km 2 , located at the western margin of the Central Graben. The Auk horst is bounded on the west by a series of faults with throws of up to 1000 ft, the eastern boundary fault has a throw of 5000 ft in the north reducing in throw southwards. The best reservoir lithology in the Zechstein is a vuggy fractured dolomite, and in the Rotliegend dune slipface sandstones provide the majority of the production. Both reservoirs and the overlying Lower Cretaceous breccia shared a common FWL at 7750 ft TVDss. The 38° API oil with a GOR of 190 SCF/STB was sourced from organic-rich Kimmeridge Clay.

The West Firsby Oilfield, Development Licence 003, Lincolnshire

Abstract The West Firsby Oilfield exemplifies the classic east Midlands oil play, sourced by early Namurian pro-deltaic shales. Stacked fluvio-deltaic sandstone reservoirs of latest Namurian to early Westphalian 'A' age are structured into a Variscan inversion anticline in the hanging wall of the northeastern boundary fault of the Dinantian-Namurian Gainsborough Trough. The Enterprise West Firsby-1 discovery well, drilled on a 'Top Westphalian 'A'' seismic depth closure, encountered oil-bearing sandstones at three levels. These are thought to represent the earliest Westphalian 'A' Sub-Alton/Crawshaw distributary channel and mouthbar sandstones (Reservoir Zone [RZ] 1), the stacked fluvial channel sands of the Namurian Rough Rock (RZ2) and an underlying high quality mouth-bar sandstone (RZ3). In the hanging wall setting, these units can be correlated over an area far larger than the West Firsby Field. On acquiring operatorship of the Development Licence (DL 003) in 1991, Tullow Exploration put the WF-1 well into production from RZ2 and 3 disposing of produced water in the earlier-drilled and unsuccessful WF-2 step-out. Between 1992 and 1996, three new production wells (WF-4, -5 and -6) were drilled from the same surface site. The wells principally produce from RZ2 and involve high-angle/horizontal sections in these sandstones, approaching 170 m in length in WF-6. Strong aquifer support, coupled with the injection of produced water into RZ2 of WF-2, promotes early natural flow from such wells at rates up to 800BOPD, and when this declines jet-pumping can maintain production at rates of several hundred BOPD/well. As of 1st January 1999, the West Firsby Oilfield had produced 0.97 MMBBL of an estimated 13 MMBBL OIIP, maintaining an average annual rate during 1998 of 345 BOPD from four wells. Remaining recoverable reserves are estimated at around 1.03 MMBBL.

Evolution of Production Practice And Reservoir Management of the Winter Field

Abstract Actual production data of Winter Field were examined for production rates, oil cut, cumulative oil produced and reserves per well in relation to well length. The log oil cut vs. cumulative oil production per well of groups of wells plots showed that the reserves at a 2% oil cut was the same despite the different lengths of these wells. Published data were next examined to establish the relationship between well length and reserves. It is obvious that the relation between reserves as a function of well length is not a linear relationship for the entire well length examined. This relation shows that as the well length increases from 200 m to roughly 500 m there is a linear increase in reserves. The slope of the line is less than one (0.7); as the length increases beyond 600 m there is very little increase in the reserves. This could explain why the Winter wells all have the same reserves. These groups of wells varied in length from 574 m to 1,110 m; that is, they are all in the length range (greater than 500 m) that gives the maximum reserves(1). In order to verify this conclusion and utilize it to increase the reserve from existing and future wells a series of well workovers and treatment programs were carried out. Newly drilled wells were completed in such a way as to use the conclusions and recommendations of these programs. Introduction The Winter field (Figure 1) has been developed utilizing horizontal wells to produce heavy oil (13.7 API oil of 2,800 – 3,800 cp. viscosity) in a 12 m thick Cumming Sand underlain by a very strong aquifer. The oil cut vs. oil cum. per well plots for each phase (wells drilled in a specific year) are shown in Figure 2. It is obvious that the reserves per well at an economic oil cut of 2% are essentially the same for the different phases. It is interesting to notice that the average well length for the different phases ranges from 574 m to 1,111 m. Data for over 250 horizontal wells producing oil over water reservoir in Saskatchewan published in SEM publication were analysed and the reserves as a function of length are shown in Figure 3. This figure illustrates the non-linear nature of the relationship between reserves and well length. For example a well of 200 – 300 m length has a reserves of 9,000 m3 while a well of 1,000 – 1,100 m has a reserves of 15,000 m3; rather than the 30,000 – 40,000 m3 expected in a linear correlation. Detailed analysis of every well in the Winter Field was carried to identify potential reasons for better or worse performance. A series of water shut-off treatments and workovers were carried out. External casing packers were utilized for formation isolation and proved to be effective. Finally, the information gained from all of the above is being tested in some of the 1995 drilling program through a new completion practice targeting reserves maximization with minimum effect of initial rate.

BASS STRAIT'S BREAM B RESERVOIR DEVELOPMENT: SUCCESS THROUGH A MULTI-FUNCTIONAL TEAM APPROACH

The effective development of thin oil columns in areas of complex stratigraphy, sparse well control and offset from existing production presents a diverse range of challenges. The success of the Bream B reservoir development can be attributed in part to the formation of a multi-functional development team. This team defined pre-development planning processes and analysis tools which were used to meet the challenges of the project. This paper discusses the Bream B development and the pivotal role the team played in its evolution.The Bream Field is an anticlinal structure with a series of retrogradationally-stacked clastic reservoir sequences. A large gas cap overlies a 13.5 m oil column in a reservoir that has strong aquifer support. The Bream A platform was installed in 1987 to develop the western and northern lobes of the field. The 18-slot Bream B concrete gravity structure was installed in October 1996 to develop the eastern half of the field.Geotechnical and engineering uncertainties, as well as a fast-paced drilling program required thorough planning by the team of geoscientists, engineers and petrophysicists. ThIS included the development of detailed contingency and well sequencing plans, the quantification of pre-drill technical uncertainties and the implementation of fully interactive remapping capabilities. During the program, application of geophysical amplitude and modelling analysis, sequence stratigraphy, petrophysics, and reservoir simulation were all used to interpret results and optimise the placement of remaining development wells.The success of the multi-functional pre-development planning processes and analysis tools was demonstrated by the requirement of only a single geological sidetrack during the drilling program and a platform production rate of 35,000 BOPD (5.6 ML/day) (August 1997).

Little Sand Draw Field, Big Horn Basin, Wyoming: A Hybrid Dual-Porosity and Single-Porosity Reservoir in the Phosphoria Formation: DISCUSSION

Little Sand Draw field produces hydrocarbons from an asymmetric anticline located on the southwestern margin of the Big Horn basin. This 479-ac, 32-well field has produced 10.4 million bbl of oil. Most production is from the Ervay Member of the Permian Phosphoria Formation. On the basis of gamma-ray logs and textural evidence, the dolomitized, 90-100 ft (27.5-30.5 m) thick Ervay Member can be subdivided into six reservoir zones. Zones are bounded by marine-flooding surfaces, and each zone is laterally consistent throughout the field. Lower Ervay zones, which were deposited under low-energy open-marine conditions, are predominantly mud-supported rocks. Higher energy, yet more restricted marine conditions occurred during deposition of the upper Ervay and resulted in a domin nce of grain-supported rocks. Moldic and micro-intercrystalline porosity occurs in four zones. Moldic pores dominate total porosity and have significant hydrocarbon storage capacity. Intercrystalline pores control matrix permeability, which is generally less than 20 md. Such permeabilities cannot account for observed production rates of several hundreds to thousands of barrels of fluid per day. Open fractures are present in all zones and contribute significantly to reservoir drainage. Fracture intensity is controlled by lithology and structural position. Silicified strata are the most highly fractured. Structurally, wells with the greatest fracture intensity are aligned along the northwest-trending hingeline of the fold. However, in much of the reservoir, flow behavior is dominated by east-northeast-trending fract res which are recognized on borehole-imaging logs and as directional permeabilities from pressure-interference tests. Most, but not all, wells are at or near virgin reservoir pressure. This, along with high water-production rates, suggests strong aquifer support for reservoir pressure. A comparison of pressure and water-cut data shows that those wells with depleted reservoir pressure also had water cuts that rose relatively slowly. Geographically, these wells define dual-porosity "compartments" in which matrix porosities and permeabilities, as well as fractures, affect flow. Elsewhere in the field, fractures are the dominant control on flow in what appears to be single-porosity behavior.

Application of 3-D Reservoir Modeling to Development Planning and Management of the Cano Limon Field, Colombia

The Cano Limon field of the Llanos foreland basin, Colombia had a STOIIP of 2 billion barrels. A three-dimensional geological reservoir model has been constructed using the computer program MONARCH on the basis of data from 24 wells. The model includes the high net/gross M1 reservoir and the overlying, as yet undeveloped, low net/gross C5 reservoir, over an area of 9 [times] 3 km. The M1 reservoir comprises a network of fluvial sandbodies, deeply incised into a marine shale unit and may thus represent an incised valley-fill complex. The C5 interval comprises single-story channel sand bodies, isolated within thick floodplain deposits, indicative of much increased accommodation space. The Cano Limon model is represented by a matrix of 1.75 million volume elements ([open quotes]voxels[close quotes]), each measuring 50 Y 50 m horizontally and 0.6 m vertically. At each voxel, the model indicates whether shale or sand is present. MONARCH differentiates between genetic sandbody types: channel, mouthbar, and crevasse splay. Correlatable sand are mapped using a deterministic approach and the lateral extent of non-correlatable sandbodies is derived using statistical distributions of width/thickness ratios. MONARCH combines structural information, as derived from seismic, with information about sand body orientation, as provided by dipmeter, oriented more » cores and seismic amplitude maps. In the case of Cano Limon, which is produced by a strong aquifer drive with a mobility ratio of 11, this level of 3-D data integration helps provide reliable guidelines for the further development and management of the field. « less

Reservoir Management Practices

Summary This paper describes the reservoir management practices used at fieldsdeveloped and operated by Esso Production Malaysia Inc. (EPMI). The goal of EPMI's reservoir management activities is to maximize profitability andeconomical recovery of oil. Excellence in reservoir management is achieved withclearly defined and endorsed plans for management of each reservoir and acoordinated process to collect, analyze, validate, and integrate reservoirdescription and performance data into optimal development and depletion plans. Use of a multidisciplinary team to identify problems and to implement timely, innovative solutions is a key problems and to implement timely, innovativesolutions is a key ingredient. Through regular reports to management andfrequent discussions among functional groups, reservoir management objectivesand stewardship performance are communicated. Introduction Reservoir management is a significant component of EPMI's developmentplanning and production operations. Reservoir management planning, which beginsduring predevelopment phases, is emphasized throughout the productive lives ofthe reservoir and field to maximize profitability and economical oil recovery. As contractor to Petroleum Nasional Bhd. (PETRONAS), the Malaysian national oilcompany, EPMI currently operates 12 oil fields with 66 active reservoirs in the South China Sea. The fields are located within the 1976 production sharingcontract (PSC) areas (Fig. 1) about 130 to 260 km [80 to 160 miles] offshore Peninsular Malaysia. Production was initiated in 1978. By the end Peninsular Malaysia. Production was initiated in 1978. By the end of 1991, 28 platformshad been installed and developed with 755 completions. Five additionalplatforms are planned to complete development of the Seligi, Guntong, Tabu, and Dulang fields. The reservoirs in all fields except Seligi, Guntong, Tabu, and Dulang are mature, having produced more than 50% of their expected ultimaterecovery. Reservoir Types and Drive Mechanisms The major reservoirs operated by EPMI can be grouped into six types (see Fig. 2). Most major reservoirs have large associated gas caps where producedgas is reinjected for gas-cap expansion to displace oil downdip to productionwells, thereby avoiding oil losses to the gas cap. The major Groups E, J, and Ksandstones of the Bekok, Pulai, Tiong, Kepong, Semangkok, and Seligi fieldshave rim or pancake-type oil columns with large overlying gas caps and moderateto strong aquifer support. The Palas Group I sandstone is similar except thatthe aquifer support is weak because of poor rock quality and continuity in thesurrounding aquifer areas. At Irong Barat, gravity drainage with gas injectionfor pressure maintenance is the predominant drive mechanism because of the highdip angle, low solution GOR, and high permeability. Full voidage replacement bycrestal gas injection is required to avoid gas-cap shrinkage. The lower Group Jsandstone at Tinggi has strong aquifer support and no gas cap, so injection isnot required. The upper Group J sandstone, however, which is in communicationwith the lower group J sandstone, has a gas ca but weak aquifer support. Consequently, gas is reinjected. At the Tapis, Guntong, and Tabu fields, the Group I and J sandstones have weak aquifer support and long oil columns, soboth water and gas are injected to maximize recovery. Reservoir Management Goal and Key Objectives The company's reservoir management program is an ongoing, dynamic process ofcollecting, analyzing, validating, and integrating process of collecting, analyzing, validating, and integrating reservoir description data andperformance data into an optimal reservoir development and depletion plan. Thegoal of reservoir management is to maximize profitability and economicalrecovery of hydrocarbons. To achieve that goal, the following three keyobjectives were established.Mitigation of production decline in existingfields. With the mature fields exhibiting a decline in productive capacity ofmore than 15%/yr, capacity enhancement is a key requirement. Several programsimplemented to mitigate decline are discussed later.Aggressive pursuit ofnew field development. The recent work completed to confirm and implementdevelopment plans for the North Seligi resource potential illustrates theapproach used.Effective exploration and exploitation of new acreage. Withthe current exploration activities in the PM-5 and PM-8 PSC areas, new acreageis being exploited effectively, but these activities are not discussed in thispaper. Reservoir Management Process Reservoir management practices are initiated before development work beginsand continue throughout the life of the reservoir through the process shownschematically in Fig. 3. JPT P. 1296

Little Sand Draw Field, Big Horn Basin, Wyoming: A Hybrid Dual-Porosity and Single-Porosity Reservoir in the Phosphoria Formation (1)

Little Sand Draw field produces hydrocarbons from an asymmetric anticline located on the southwestern margin of the Big Horn basin. This 479-ac, 32-well field has produced 10.4 million bbl of oil. Most production is from the Ervay Member of the Permian Phosphoria Formation. On the basis of gamma-ray logs and textural evidence, the dolomitized, 90-100 ft (27.5-30.5 m) thick Ervay Member can be subdivided into six reservoir zones. Zones are bounded by marine-flooding surfaces, and each zone is laterally consistent throughout the field. Lower Ervay zones, which were deposited under low-energy open-marine conditions, are predominantly mud-supported rocks. Higher energy, yet more restricted marine conditions occurred during deposition of the upper Ervay and resulted in a domin nce of grain-supported rocks. Moldic and micro-intercrystalline porosity occurs in four zones. Moldic pores dominate total porosity and have significant hydrocarbon storage capacity. Intercrystalline pores control matrix permeability, which is generally less than 20 md. Such permeabilities cannot account for observed production rates of several hundreds to thousands of barrels of fluid per day. Open fractures are present in all zones and contribute significantly to reservoir drainage. Fracture intensity is controlled by lithology and structural position. Silicified strata are the most highly fractured. Structurally, wells with the greatest fracture intensity are aligned along the northwest-trending hingeline of the fold. However, in much of the reservoir, flow behavior is dominated by east-northeast-trending fract res which are recognized on borehole-imaging logs and as directional permeabilities from pressure-interference tests. Most, but not all, wells are at or near virgin reservoir pressure. This, along with high water-production rates, suggests strong aquifer support for reservoir pressure. A comparison of pressure and water-cut data shows that those wells with depleted reservoir pressure also had water cuts that rose relatively slowly. Geographically, these wells define dual-porosity compartments in which matrix porosities and permeabilities, as well as fractures, affect flow. Elsewhere in the field, fractures are the dominant control on flow in what appears to be single-porosity behavior.

Impact of a CO2‐induced climatic change on river flow variability in three rivers in Belgium

AbstractA hydrological conceptual model developed by the Royal Meteorological Institute of Belgium has been run to assess the potential hydrological impacts of an hypothetical doubling of the atmospheric CO2 concentration. The simulated scenarios were derived from the predictions of climatic change currently provided by General Circulation Models (GCMs).Three typical drainage basins in Belgium have been selected for assessing their common responses and bringing out possible specific behaviours attributable to catchment characteristics.The study dealt essentially with modifications of the streamflow and with alterations of the flood and low‐flow regimes.In catchments with prevailing surface flow the considered change in climate could induce: An increase in flood frequencies during the winter season together with a strengthening of the extreme river stages leading to greater flooding risks; A decrease in streamflow during the summer season and, as a corollary, increased risks of water pollution; Possible restraints, in summer and autumn, on water availability from local groundwater storages. In catchments with high infiltration rate and with strong aquifer the impact could be: An increase in groundwater storage, bringing about an increase in the base flow throughout the year, which in turn involves increased flood risks; A reduction of the number of low‐stage occurrences in summer, resulting in reduced river pollution; A possible increase in water availability from the aquifers.

Reservoir Simulation of Horizontal Wells in the Helder Field

Summary. Results of a reservoir simulation study of horizontal wells in a field that is entirely underlain by water and has a highly unfavorable mobility ratio are compared with about 4 years of actual field data. Finely gridded single-well models were used to investigate the short-term performance of the horizontal wells and to generate pseudofunctions for performance of the horizontal wells and to generate pseudofunctions for use in the field model. Introduction The Helder oil field, on the Dutch Continental Shelf, was brought on production 1982 and developed with 13 conventional wells. To improve oil recovery and to minimize water coning, the field was redeveloped during 1987 and 1988 with the drilling of 10 horizontal wells by sidetracking from existing wells. The simulation study described here was initiated to answer the following questions posed as a result of observing the performance posed as a result of observing the performance of the horizontal wells.Is the water-cut performance adversely affected by producing the wells at high gross rates?What effects do various well and reservoir parameters have on short-and long-term well parameters have on short-and long-term well behavior? Parameters to be considered are horizontal-well length, height above the water/oil contact (WOC) reservoir heterogeneity, localized vertical permeability barriers, and drainage area shape.Is water production distributed evenly along the horizontal wellbore, or does it enter preferentially at one or more intervals?Can production performance be improved by water shutoff treatments on existing wells or by modified completion design in future wells?Can the ultimate recovery be improved with additional infill horizontal wells? Field Description. The Helder field is an Block Q/1 of the Dutch North Sea, about 62 miles northwest of Amsterdam in 85 ft of water. The structure is a slightly faulted anticline at a depth of 4,600 ft. Formation dip along the northwest/southwest axis of the field is generally less than 1 degree. The field is underlain by water over its entire 1,140 acres of closure and has a maximum oil column of 131 ft. The reservoir is supported by a strong aquifer. Two other fields, Helm and Hoorn, brought on production at the same time as Helder, share the same aquifer. The original oil in place us estimated to be 72 × 10(6) STB. Oil gravity is 22 degrees API, and initial viscosity at reservoir conditions is 30 cp. Production is from the Vlieland sand, which has permeabilities ranging from 500 to 6,000 md. Production History With Conventional Wells. Production History With Conventional Wells. Helder was put on production in Oct. 1982. During 1982–84, the field was developed with 12 conventional (vertical/deviated) wells from a centrally located platform. In 1986, a previously drilled appraisal well (Well B1) was tied back to the platform by use of satellite tripod tower. Early water breakthrough and rapidly increasing water cut were expected in the conventional wells because of the unfavorable mobility ratio (M=25), flat field structure, and high vertical permeability. The majority of the wells produced water within a few days of production startup. This performance was predicted by initial computer simulations of single-well models, which showed that the critical rate to prevent water production had to be exceeded if the field was to be produced economically. produced economically. Subsequent simulations and preliminary history matching predicted that water-cut performance was not rate-sensitive for practical performance was not rate-sensitive for practical purposes. This led to the conclusion that purposes. This led to the conclusion that maximizing gross fluid off-take was necessary to improve economics. Individual wells were produced at rates up to 12,000 BFPD with water cuts from 85 to 97%. Some of the implications of the high-gross-fluid/ high-water-cut production strategy were decline in reservoir pressure and increase in workover frequency with conversion to larger pumps. To overcome these extreme coning conditions, Unocal Netherlands investigated the feasibility of redevelopment with horizontal wells. Redevelopment With Horizontal Wells. The first horizontal well (Well A4RD) was put on production in Jan. 1987. After the success of this well, nine more wells were horizontally sidetracked. Figs 1 and 2 show the locations of the original wells and the horizontal sidetracks. Table 1 summarizes the horizontal-well parameters. The performance aspects of parameters. The performance aspects of the Helder horizontal wells were the subject of a previous paper. Model Rock and PVT Properties. Seven layers were used in the field model and 15 layers in the single-well models. JPT P. 906

Oil and Water Production in a Reservoir With Significant Capillary Transition Zone

Summary Analytical and numerical methods are used to investigate the mechanism of water production in a high-permeability sandstone reservoir that has a capillary transition zone height comparable to formation thickness. Production rates are well above those for transition-zone water production alone. Consequently all wells are affected production alone. Consequently all wells are affected by coning shortly after the start of production. It is found that water cut is largely insensitive to total fluid production rate for the same recovery. The depth of well penetration and the effect of radial capillary pressure gradients are shown to be of secondary importance pressure gradients are shown to be of secondary importance in these circumstances. The predictions are confirmed by the results of a long-term pilot production test. Introduction This paper considers the mechanism of water production in a highly permeable sandstone reservoir with a 22API [0.9-g/cm3] under saturated oil and a strong edge aquifer drive. The findings are drawn from a study recently performed on the M-1 Sand reservoir of the Fanny field, performed on the M-1 Sand reservoir of the Fanny field, which is located on the eastern flank of the Oriente basin in Ecuador. M-1 Sand belongs to the Napo formation of the Cretaceous Age and consists of moderately to poorly cemented quartzose sands of high permeability. Reservoir depth is approximately 7,700 ft [2347 m]. A characteristic feature of the reservoir is the wells' predisposition to develop substantial water cuts after predisposition to develop substantial water cuts after short periods of production. Attempts have been made in the past to reduce water production by squeeze cement jobs and recompletions. However, these operations have not been effective but for the very short term and consequently the study has concentrated on attempting to define the nature of fluid movement within the drainage area of the wells. Reservoir Description M-1 Sand shows lithological features characteristic of a fluvial channel depositional environment. These features are exemplified by the Induction Electrical Survey of Well 18-B-2 (Fig. 1), which shows a basal unit 45 to 55 ft [14 to 17 m] thick, overlain by a variable number of smaller units that are separated by shale breaks and tight streaks. These upper units are of poor quality and limited lateral continuity. In contrast the basal unit contains no correlatable shale breaks although thin shales were encountered in some wells and early completion practices attempted unsuccessfully to make use of them. Because of this early experience and the absence of correlation it has been concluded that such shale breaks are of limited lateral extent and do not contribute materially to the prevention of water-cone development. prevention of water-cone development. The basal unit contains more than 90% of the original oil in place, estimated at 48 × 10(6) STB [7.6 × 10(6) stocktank m3]. Currently all wells are completed in this unit, which has provided all production to date. The upper units have been neglected for the purposes of this paper. The structural configuration of the reservoir is a faulted asymmetrical anticline of low structural amplitude. Fig. 2 represents the structure on top of the basal sand unit and shows the intersection of the oil/water contact (OWC) with this surface, giving rise to a maximum oil column of 65 to 70 ft [20 to 21 m]. A comparison of sand thickness with oil column height indicates that the base of the sand is everywhere close to the OWC and that all wells have high basal water saturations. Pressure support is by edge aquifer influx, but with strong underrunning giving behavior characteristic of a bottom aquifer. Reservoir and Fluid Properties The basal unit is variable in quality but characterized by high porosity and permeability averaging 20 to 25% and 2 to 3 darcies, respectively. Figs. 3 and 4 are capillary-pressure and relative-permeability curves representative of the basal unit. These curves are typical of a sandstone that contains large, well-interconnected pores. Sands of this unit are generally poorly cemented and friable. No fractures are evident from either cores or logs. There is no evidence of any fracture-induced effects on pressure buildup data, which correspond to a single permeability intergranular system. Average oil and water fluid properties are presented in Table 1. The oil and water viscosities at reservoir conditions are 12 and 0.35 cp [12 and 0.35 mPas] respectively, which give a very unfavorable endpoint mobility ratio. The displacement of oil by the encroaching aquifer is thus an unstable displacement and the strong underrunning of water quickly results in high producing water cuts in the wells. JPT P. 1559

Hydrological testing for deep shafts and tunnels

Methods of water testing for mineshaft investigations have moved away from steady state well resistance measurements towards the transient methods associated with Theis and developed by Horner and others. The commonest system in use is the drill stem test of the oil industry but alternative methods employing the measurement of the recovery of aquifer pressure following a period of borehole flow are described, which on occasion are better suited to the evaluation of very strong aquifers. Results of such tests are compared with those from a new type of probehole test carried out from the advancing excavation face.

Effect of Overburden Pressure on Flow Capacity in A Deep Oil Reservoir

Abstract Brine flow capacity of a 9,000-ft deep, loosely consolidated sandstone reservoir was only about one-seventh as high as that predicted fro in routine relative-permeability data. It was found that the discrepancy between predicted and actual flow capacities was due to compression of the reservoir rock by the overburden. A close agreement was obtained when calculating reservoir brine flow capacity by five methods:laboratory relative-permeability tests conducted at high confining pressure,actual injectivity data,combination of routine relative permeabilities with productivity-increase data,pressure fall-off analysis andwater-influx data. The findings of this study should be applicable to other similar reservoirs. The third method listed should be particularly useful to the engineer for predicting injection rates in general. Overburden pressure affects reservoir oil and gas flow capacity in much the same way as it does brine flow capacity. Introduction While trying to supplement the aquifer water drive in the Third Grubb reservoir of the San Miguelito field, Ventura County, Calif., it was noted that injection rates were only about one-seventh as high as the ones predicted from routine relative permeabilities. This discrepancy prompted the present study. It was found that the water treatment was adequate and that the wellbores of the injection wells were undamaged, thus leaving the effect of net confining pressure as a possible explanation. The net confining pressure is defined as the difference between the external and internal pressure acting on the formation. The external pressure is caused by the weight of the overburden, while the internal pressure is the counteracting force exerted by the fluids contained in the pore spaces. Although effect of confining pressure on permeability has been previously reported, this is the first known application of such data to a water-injection project. Reservoir Characteristics The Third Grubb zone is located in the San Miguelito field, which is a faulted anticline located along the Ventura field trend some four-miles northwest of Ventura, Calif. Production is from sandstone layers of the Repetto formation which are interbedded with shales and siltstones typical of the Pliocene in the area. Most of the sandstone is loosely consolidated and occurs in layers 1/2- to 3-ft thick. The reservoir is bounded on the north and east by faulting and to the south and west by the water-oil contact. As seen in the structure map (Fig. 1), structural relief is high with an average dip of 45 degrees. Rock and fluid characteristics are summarized in Table 1, and reservoir permeability distribution is shown in Fig. 2.The zone was discovered in 1950, and development was completed by the end of 1953. Reservoir performance is illustrated in Fig. 3. The predicted (dashed) curves were constructed by the Schilthius material-balance method using laboratory kg/ko data. The actual (solid) curves are typical for a field having a strong aquifer water drive. A pilot water flood was initiated in 1955, and since that time many treatments have been attempted to increase the low injection rates. JPT P. 962^