Waterflood Project Research Articles

Performance Of South Swan Hills Tertiary Miscible Flood

Abstract A review of the performance of the tertiary hydrocarbon miscible flood which has been operating in the West Waterflood area of the South Swan Hills Unit since September 1982 is presented. The production trend clearly indicates that the tertiary flood has reversed the steady decline experienced under waterflood to the extent that the oil production has increased from 450 m3/day to as high as 1200 m3/day in 1986. The ultimate recovery factors for the project area are estimated at 38% original oil-in-place (OOIP) by waterflood and 59% OOIP by miscible flood. The projected 20% incremental recovery is based on a black oil model simulation and is in line with the incremental recovery predicted for the secondary miscible flood in the South Swan Hills Unit(1). The early performance of the tertiary flood is consistent with model simulation work and indicates that the projection in incremental recovery is achievable. Introduction The South Swan Hills Unit is located 190 km northwest of Edmonton, Alberta (Fig. I). Production is from the Swan Hills member of the Beaverhill Lake Formation which is a reef of Upper Devonian age. The unit is subdivided into three project areas (Fig. 2). The tertiary hydrocarbon miscible flood was installed in what was originally the West Waterflood Project area in September 1982. The project area encompasses approximately 4450 ha and contains 83 wells drilled on 64-ha spacing. Current plans are to inject a total hydrocarbon slug of 47.2% HCPV. This slug will comprise 15% HCPV solvent slug followed by a 32.2% HCPV dry gas slug. Both slugs are to be injected at an injection ratio with water conducive to optimum flood performance. Following hydrocarbon injection, the flood will revert to straight water injection. Geological Description The South Swan Hills reservoir is a Beaverhill Lake carbonate reef which comprises four oil-bearing geologic zones (Fig. 3). In the Tertiary Project area, only Zones 1 and 2 are of concern because, excluding the northern portion of the project area, Zone 3 (table reef zone) is predominately water-bearing. Zone 1 is a porous calcarenite which is characteristically of good porosity and high permeability. Zone 2 varies from a continuous reef front facies in the western part of the project area to a lagoonal facies in the eastern portion. Except for intermittent porous stringers, the lagoonal facies is characteristically poorer in quality. The reservoir rock averages 25 m in thickness and 8% in porosity. Waterflood Performance Waterflood operations began in 1963 at which time a semi-peripheral line drive was installed along the southwestern edge of the unit (Fig. 4). Additional voidage replacement capability was added as unit allowable were increased. Prior to start-up of the secondary miscible flood in the central portion of the unit in 1973, an estimated 5.0 × 106 m3 of oil migrated from the West Waterflood Project area into the Secondary Miscible Flood Project area due to a high pressure gradient which existed easterly across the unit(1). Waterflood operations continued in the West Waterflood area until September 1982. Figure 5 shows the production performance of the West Waterflood area since 1963.

Analytical Solutions For Vertical Fractures In A Composite System

Abstract A method is proposed to interpret the pressure transient data of injection wells in secondary arid tertiary recovery processes. A composite system is considered in which the inner region represents a swept volume and the outer region extends to infinity. The two regions are thus featured by different hydraulic diffusivities and mobility's. The well is vertically fractured and the fracture is assumed to exhibit an infinitely large conductivity. The flow behavior in the system is described by use of elliptical geometry. The model was tested against several special cases for which analytical solutions are available and very good matches were obtained. Introduction In general, oil and gas deposits are characterized by rock and fluid heterogeneities. Although the pressure transient theory based on the assumption of system homogeneity is frequently successful in interpreting the well test data, there are also well and reservoir conditions which do not permit such a simplification: formation damage or improvement near the wellbore, bubble of the natural gas injected into the formation, water bank in a waterflood project, the burned zone in an in-situ combustion project and the swept zone in steam flooding or steam stimulating scheme. In all these situations the system properties undergo an abrupt change at some distance from the wellbore. A composite system consisting of an inner region surrounding the well and the outer region characterized by unaltered reservoir properties must therefore be considered and the pressure transient theory be modified accordingly. Several studies of the composite reservoirs have already been presented in literature(1–4). In elliptical shaped reservoirs, anisotropic reservoirs and formations surrounding the vertically fractured wells, an elliptical flow geometry is assumed to occur. It is the subject of this study to investigate the transient pressure behavior in a composite system with vertically fractured wells using elliptical coordinates. Only one study has addressed this problem so far(4). The Model Development The main features of the model include:—Artificial vertical fracture of infinitely high conductivity;—Two regions, inner and outer, (within themselves considered isotropic and homogeneous) characterized by different rock properties;—The flood front of an infinitesimal thickness is stationary during the testing period; and—Single-phase fluid of constant compressibility. The two-dimensional single-phase flow equations for constant compressibility fluids in elliptical coordinates are thus considered. The dimensionless form of the flow equation for the two regions can be written as follows: Region 1: Equation (1) (Available In Full Paper) Region 2: Equation (2) (Available In Full Paper) Initial pressure distribution in both regions in uniform and equal to P1: Equation (3) (Available In Full Paper) Equation (4) (Available In Full Paper) At the inner boundary (fracture) a constant pressure is specified as: Equation (5) (Available In Full Paper) Region 2 is assumed to be infinitely large with respect to any pressure disturbance caused by the well: Equation (6) (Available In Full Paper) The two following continuity requirements must be satisfied at the two regions interface: Equation (7) (Available In Full Paper) Equation (8) (Available In Full Paper)

Depositional Environments and Diagenesis of Lower Pennsylvanian Caddo Formation, Stephens County, Texas: ABSTRACT

Since its discovery in 1916, the Lower Pennsylvanian Caddo limestone has been one of the most prolific producing intervals in the central Texas region. Favorable reservoir characteristics, with porosities from 9 to 24% and permeabilities from 0.1 to 1,000 md in the pay interval, have enabled many oil companies to initiate successful secondary recovery waterflood projects. Since its discovery, more than 200 million bbl of oil has been recovered from this formation in Stephens County alone. The Caddo reef trend developed during the Early Pennsylvanian, generally along the axis of the Bend flexure. Close examination of whole core and thin sections reveals the formation to be a series of small reef mounds characterized by wackestones. The wackestones consist of green algae, brachiopods, and some rugose corals, which are found on the leeward side (back reef). This sequence is commonly found in the top segment of the Caddo. Deeper into the formation the sequence grades into a packstone/wackestone, characteristic of an oceanward margin (fore reef), and is distinguished by red algae, foraminifera (fusulinids and miliolids), and crinoid hash. The basal sequence is a series of alternating lime mudstones and shales that are heavily silicified. Diagenesis is the key to reservoir rockmore » quality. Moldic porosity was created through dissolution of organisms composed of low magnesium calcite (brachiopods) and aragonite (corals) during periods of subaerial exposure of the back reef. During this period of low sea level, fore-reef sediments were partly cemented by CaCO{sub 3} and were not subaerially exposed. Therefore, moldic porosity was not created in the fore-reef sediments. Porosity in the fore reef was later created in places by dissolution of this cement. Secondary dolomite was later precipitated along pore walls, and in places it occluded porosity in the pore spaces.« less

中国における二・三次回収法の現状について

中国における二・三次回収法の現状について

An Approach To Predict Tarmat Breakdown in Minagish Reservoir in Kuwait

Minagish Oolite reservoir, Minagish Field in Kuwait is characterized by tarmat presence at the oil-water contact. A water flooding project is planned for the reservoir. This paper discusses the possibility of tarmat break-down upon water injection below it. It was found that differential pressure at tarmat would be mainly due to water injection and that differential pressure due to oil production would be negligible. This paper suggests a technique to predict tarmat break-down time, response time at the nearest producer or observation well and the time at which water injection should be switched from below tarmat to above it. Also, the technique could be used to predict the differential pressure at tarmat anywhere in the reservoir.

Production Technology Experience in Michigan Waterfloods

Summary Waterflooding started in the Niagaran carbonate reef oil reservoirs in northern Michigan in 1978 with Shell Oil Co.'s Chester 18 waterflood. Ten waterflood projects had been installed by Spring 1983. As a result of this experience, significant production technology practices have become established. The majority of the waterflood experience has been in Shell's Gaylord Production Unit located primarily in Otsego and Crawford counties. Specifically, the projects discussed are the Chester 18, Chester 21, Frederic 10, Hayes 15, Hayes 21A, and Mid-Charlton 10 waterfloods. In general, the waterflood program can be characterized by (1) very favorable oil program can be characterized by (1) very favorable oil production response, (2) timely and definitive production response, (2) timely and definitive surveillance techniques, (3) systematic and timely well work on injectors and producers to maintain optimum reservoir withdrawal behavior, (4) innovative application of artificial lift technology, and (5) aggressive future planning to maintain and to improve oil production response. planning to maintain and to improve oil production response. This paper elaborates on these waterflood program characterizations as follows.The favorable impact that waterfloods have had on oil production is discussed.The frequency and type of surveillance techniques are described for both injectors and producers. Some of the major techniques are pressure transient analysis, inflow performance plots, produced water cut and water weight records, injection and produced fluid analysis, hydrogen sulfide monitoring, reservoir withdrawal calculations, injection profile surveys, and well-to-well radioactive tracers.As a result of the surveillance techniques, well treatments have been designed for salt, calcium carbonate scale, gypsum scale, paraffin, and bacterial wellbore impairment. Surveillance has also resulted in continuous chemical injection programs to combat corrosion, scale, salt, oil/water reverse emulsions, bacterial formation, and H, S formation. The constant calculation of reservoir withdrawals has led to alterations in the various project operating policies.Withdrawal surveillance, inflow performance monitoring, and reservoir simulation have indicated that greater ultimate recovery, maximum operating income, and maximum present value profit will be achieved in spite of increasing volumes of water with high fluid withdrawals. Recent improvements in submersible pump technology (rotary gas separator and variable speed control) have enabled high withdrawal rates to be achieved efficiently (3,000 to 4,000 B/D [477 to 636 m'/d] fluid).An aggressive program for future activity has necessitated considerable short- and tong-term planning. Items such as facility sizing, disposal zone testing, produced water handling, electric power supply for northern produced water handling, electric power supply for northern Michigan, and source water development are some of the major items that have been studied. Introduction Waterflooding was initiated in a Niagaran carbonate reef oil reservoir in northern Michigan in 1978. Ten projects throughout the reef trend had been installed by Spring 1983. As a result of this experience, effective production technology practices have become established. This paper reviews the major production technology paper reviews the major production technology surveillance techniques and highlights some of the results. The Silurian Niagaran reefs, in which there are 600 separate fields, are located along the northern rim of the Michigan basin. Fig. 1 shows the reef trend with the locations of the five major waterflood projects. The reservoir consists of dolomite and limestone rock of the Silurian Niagaran reef and the overlying A-1 carbonate. The reservoir seal is an anhydrite bed called the A-2 evaporite. A more complete description of the carbonate reef geology is offered by Huh et al. A recent discussion of the total Niagaran reef play is given by Aminian et al. The size of the Niagaran reefs under waterflood range from 50 to 560 acres [202 344 to 2 266 249 m2 ]. The smallest has only two wells, whereas the largest has 20 wells. The design and operating programs initially planned for the waterflood projects have proved planned for the waterflood projects have proved successful. The operating data from the more mature projects have enabled development of effective production projects have enabled development of effective production technology practices. The projects discussed specifically are the Chester 18, Chester 21, Frederic 10, Hayes 15, Hayes 21A, and the Mid-Charlton 10 waterfloods that are operated by Shell Oil Co. in Otsego and Crawford counties. This paper reviewsthe favorable effect waterflooding has had on oil production;the frequency and type of production surveillance techniques;the results of some of these techniques;artificial lift considerations; andfuture planning of more waterflooding in the northern Michigan reef trend. Effect of Waterflooding on Oil Production Waterflooding has substantially increased oil production in the past 3 years. JPT P. 1446

Microprocessors Play a Major Role in Optimizing the Intermittent Gas Lift System in the Ventura Avenue Field

Summary Microprocessor-assisted programmable controllers have been installed as time-cycle control devices in Getty Oil Co.'s intermittent gas lift operation in the Ventura Avenue field. Electric clock intermitters located at each well site were replaced by centralized programmable controllers. intermittent gas lift cycles for 125 wells are now controlled by nine programmable controllers that use microprocessors as the timekeeping mechanism. With accurate control by the programmable controllers and the use of a specially designed computer program. individual well gas lift cycles are scheduled so that the demand for compressed gas at the compressor station is constant. A constant demand for compressed gas has eliminated compressor discharge rate and pressure fluctuations, therefore providing more efficient gas lift operations. In addition to accurate control of gas lift cycle timing, the centralized programmable controllers offer a much faster method of changing cycle length and cycle frequency. It is now more feasible to experiment with combinations of cycle length and frequency for each well to achieve the optimum gas-liquid ratio (GLR). As a result of more efficient well operations, the total system efficiency has improved, and compressor fuel gas requirements have dropped significantly. Introduction The Ventura Avenue field is located in southern California approximately two miles north of the city of Ventura in Ventura County (Fig. 1). Getty Oil Co. operates that portion of the field located at the east of the riverbottom area portion of the field located at the east of the riverbottom area of the Ventura River. The Ventura Avenue field produces from two major zones or "blocks"-C Block and D Block. Wells completed in C Block produce from depths between 5,000 and 8,000 ft [ 1.5 and 2.4 km]. D Block wells produce from 8,000 to 13,000 ft [2.4 to 4.0 km). The development of the D Block zones began in 193 1. Early development was rather slow owing to deep drilling problems, but active development continued into the early 1960's. Wells usually came in flowing at 200 to 900 BFPD [32 to 143 m3/d fluid] and continued to flow for 7 to 10 years. It was for these D Block wells that the current gas lift system originally was developed. Not only was there plenty of produced gas to be processed as fuel for the gas-fired compressor engines, but there was also plenty to be used in the compressors as recycle gas. The plenty to be used in the compressors as recycle gas. The wells were produced originally on continuous lift. but as production rates declined, intermittent lift proved to be production rates declined, intermittent lift proved to be more economic. D Block currently produces approximately 9,000 BFPD [ 1431 M3 /d fluid], 5,800 BFPD [922 m 3/d fluid] by rod pump and 3.200 BFPD [509 M3 /d fluid] by intermittent gas lift. Waterflood operations recently were initiated in D Block, although approximately 72 % of the current D Block production is still considered primary production. Many waterfloods ultimately will be primary production. Many waterfloods ultimately will be required to develop D Block because of numerous fault blocks and massive zone thickness (greater than 1,000 ft [300 m] in some wells) of D Block. The first D Block waterflood was initiated in Jan. 1980. injection into the second and third waterfloods began in Jan. 1983 and Dec. 1983, respectively. Eleven more potential D Block waterflood projects have been identified potential D Block waterflood projects have been identified for future consideration. A major impact of the waterflooding operations is the expected increase in fluid production and the corresponding decrease in gas production. An analysis was made to estimate the remaining effective life of the gas lift system operation in conjunction with the waterflooding operation. The analysis projected that the fuel gas and recycle gas required to lift the expected fluid volumes will be greater than the produced gas volumes within the next five years. Intermittent gas lift can be less expensive than rod pumping, especially at depths associated with D Block. pumping, especially at depths associated with D Block. For this reason, an investigation was conducted into ways to improve the efficiency of the current gas lift system operation, thus extending the remaining life of the system. The recommendations from the investigation were as follows.Conduct a diligent search for gas line leaks and repair immediately.optimize single-well GLR'S. Recycle gas requirements will be minimized, thus reducing fuel gas usage.Minimize compressor discharge pressure and rate fluctuations. A balanced system must be achieved for maximum system efficiency. On the basis of these recommendations, a search for gas line leaks was carried out. All lines were pressure tested and leaks repaired. Because of the age of the gas JPT P. 696

Design Concepts of a Heavy-Oil Recovery Process by an Immiscible CO2 Application

Summary Bati Raman oil field, in southeast Turkey, represents Turkey's biggest single oil reserve. The rapid production decline of the field and increases in the price of crude oil has led Turkish Petroleum Corp. (TPAO) to consider intervening with EOR techniques. Since 1967, various recovery schemes have been attempted, including steam and water injection. Extensive laboratory, modeling, and comparative engineering studies of various immiscible CO2 application techniques resulted. This paper presents the reservoir engineering aspects of immiscible CO2 application as applied to Bati Raman oil field. Introduction Bati Raman Oil Field. Bati Raman field, discovered in 1961 in southeast Turkey (Fig. 1), contains low-pressure, low-gravity (12 deg. API [0.986-g/cm3]) oil at an average depth of 4,300 ft [1310 m]. It is the largest oil field in Turkey, with an estimated initial reserve of about 1.85×10–9 STB [300×10–6 stock-tank m3]. The producing formation is Garzan limestone, a long, partly asymmetric anticline oriented in the east-west partly asymmetric anticline oriented in the east-west direction. The field is 10.5 miles [17 km] long with a width of 2.5 miles [4 km]. The reservoir is limited by an oil/water contact (OWC) at 1,970 ft [600 m] subsea in the north and west, by a fault system in the southwest and south, and by a permeability pinchout in the southern and southeastern part of the field (Fig. 2). The formation has a gross thickness of 210 ft [64 m]. The oil column from the top of the structure to the OWC is about 690 ft [210 m]. The Garzan limestone is of Cretaceous age, has a reefal origin, and exhibits rather pronounced heterogeneities both areally and vertically. The reservoir rock is a fractured vuggy limestone in the western and central parts, but is chalky and tighter to the east. Average porosity is 18% and mainly vugular and fissured in type. The typical matrix permeability by core analysis is 10 to 100 md; however, well tests show effective permeabilities in the range of 200 to 500 md, confirming the contribution of secondary porosity (fractures, vugs, and connecting cracks). In the central and western parts of the field, a well-developed system of secondary porosity and copyright 1985 Society of Petroleum Engineers permeability is believed to exist. In these areas, a permeability is believed to exist. In these areas, a secondary vugular porosity interconnected by fissures appears to be superimposed over a low primary porosity matrix. The main production mechanism is rock and fluid expansion. Water drive appears to be insignificant, except for a very weak aquifer influence at the central north-flank wells. The solution GOR is 18 scf/bbl [3.24 std m3/m3], resulting in a low bubblepoint pressure of 160 psi [1100 kPa]. There is practically no solution gas drive below the bubblepoint. The reservoir oil is just above the bubble-point pressure with a viscosity range of 450 to 1,000 cp [0.45 to 1.00 Pa s]. The original reservoir pressure was about 1,800 psi [12.4 MPa] at a datum of 1,970 ft [600 m] subsea. The average reservoir pressure has now declined to 400 psi [2758 kPa], after a cumulative production of 30 million STB [4.8 × 106 stock-tank m3] oil production of 30 million STB [4.8 × 106 stock-tank m3] oil (Fig. 3). The field was developed on 62 acres [251 000 m2] per well spacing. There are 103 active producers. All are on pump with a total oil production of 2,600 B/D [413 pump with a total oil production of 2,600 B/D [413 m3/d], compared with a peak rate of about 9,000 B/D [1431 m3/d] in 1969. Initial well producing rates ranged up to 400 B/D [64 m3/d] but now are averaging about 25 B/D [4 m3/d]. Reservoir and fluid characteristics are summarized in Table 1. Because of the unfavorable oil properties (such as low gravity, low solution gas, and high viscosity), low reservoir energy, and the type of driving mechanism, primary recovery prospects are very low. It is estimated that ultimately 1.5 % of initial oil in place (IOIP) can be produced from Bati Raman field through primary production. produced from Bati Raman field through primary production. The current trend in primary recovery and the rapid decline in reservoir pressure suggest the need for a suitable EOR method to produce a significant fraction of the vast reserve. In the past, we carried out laboratory and engineering studies as well as some field tests to enhance recovery, including water injection, steam cycling, steamdrive, and air injection (for in-situ combustion). Most of these studies, however, were empirical, exploratory in nature, and of limited scope. Of these, only the five-spot waterflood project proved conclusive. About 3.2 million bbl [500 000 m3] water were injected in the central area of the field between 1971 and 1978. JPT P. 275

Petroleum reservoir engineering for crude oil and natural gas developments.

This paper presents characteristic studies that should be considered in oil and gas field developments. Several significant articles are illustrated and discussed, covering the following items; (1) reservoir rock properties, (2) waterflooding, (3) underground natural gas storage and (4) petroleum reserves and techno-economics. The effects of clays and clay minerals on relative permeability curves are clarified. The new porosity measurement of shaly sand cores is devised. At the planning stage, A and B blocks in Sarukawa oil field were given the priority of waterflooding projects by means of application of reservoir engineering data, in addition to the usual geological and geophysical information. The reservoir engineering study on Sekihara gas field has contributed to research for underground natural gas storage. The proposed procedure on moving boundary problem may be required in relatively smaller reservoir. The developed probability model on estimation of oil reserves and techno-economical appraisal method are discussed.

Design and Operating Factors That Affect Waterflood Performance in Michigan

Tinker, Gordon E.; SPE; Shell OilCo. Summary Water flooding started in the carbonate oil reservoirs of the northern Michigan Salina Niagaran reef trend in 1978 with Shell's Chester 18waterflood. Ten projects had been installed by the end of 1982, so operational results are available to expand and to reinforce the reservoir-simulation-based design and operating program. The small areal size of these pinnacle reef fields. variations in rock quality, and uncertain reservoir continuity have made successful water flood design difficult to achieve. Some existing wells are being, redrilled at the stall of a project and others may have to be redrilled later in the life of a water flood to allow the various porosity zones to be fully exploited within the flood pattern and to maintain adequate well spacing for oil bank formation. The operating strategies for these projects are based on a reservoir simulation study that stressed increased oil recovery and project economics. The operating procedures planned for these projects have been proved successful as evaluated by 4.5 year, of actual water flood performance in the Chester 18 water flood and from preliminary results from other projects. One of the most successful of these operational techniques has been the use of high-volume submersible pumps to maintain oil production response with increasing volumes of water, to give flexibility to injection pattern design, and to increase ultimate recovery. The mobility ratio in these reservoirs is very favorable, so water production results from channeling and, in some cases, bottom water coning rather than fingering. Well-completion strategy, a part of fluid-production and water-injection control, depends on knowing the location of secondary gas caps and the water zone. Water injection into even thin gas caps should be avoided to prevent gas trapping at the top of the reservoir and excessive early water production. Coning of gas and water, potential problems in many reservoirs, can result in reduced oil-recovery. Project monitoring procedures were carefully planned to facilitate project evaluation and changes in operating policy. It is believed that the design and operating policies as developed in this study have continued application for the many water floods planned in northern Michigan and to some extent for projects in other areas, but they may not be optimal for other types of reservoirs. Introduction Waterflooding for Shell started in Michigan during 1978 with the Chester 18project. Ten projects had been installed by the end of 1982, so operational results are available to expand and reinforce the early design and operating program based on reservoir simulation. The various projects located in northern Michigan (Fig. 1) range in size from two wells on 50acres to 17 wells covering 560 acres. This wide size range has led to some variation in results and problems, but it has been possible to develop a system of design and operating factors that pertain to the program as a whole. Shell's initial success in water flooding is expected to develop into a program that could eventually include as many as 50 water flood projects in northern Michigan. JPT P. 1884^

Application of Integrated Reservoir Analysis to Design of a Waterflood Project in Miocene LL3 Field, Lake Maracaibo, Venezuela: ABSTRACT

Integrated Reservoir Analysis is a procedure where interpreted stratigraphic and facies frameworks are combined with structural analysis to produce more accurate and appropriate reservoir maps. The result is a three dimensional interpretation of the thickness, shape, lateral extent, and internal distribution of porosity and permeability in individual reservoir units. The principal steps of the procedure are: (1) planning, (2) data gathering, (3) determination of the stratigraphic framework, (4) determination of the facies framework, (5) structural analysis, (6) data manipulation, and (7) mapping. The stratigraphic framework is developed by combining pattern correlation techniques with knowledge about the influence of specific facies on stratigraphic patterns. A network of cross sections are designed utilizing correlation grain and/or depositional strike. Correlations on these sections develop a framework of horizons which ideally will isolate, in a stratigraphic envelope, individual reservoir units resulting from a unique depositional episode. The facies framework results from environmental facies analysis and the use of electric log facies. The proper identification of reservoir facies is required for the mapping of reservoir geometry and the determination of the internal distribution of porosity and permeability. Facies-biased contouring techniques and the lateral extension of facies relationships along cross sections were used in the planning and design of a waterflood project by Lagoven, S.A., in fluvial-deltaic clastics of the Miocene La Rosa Formation in the LL3 field, Lake Maracaibo, Venezuela. Important clastic reservoir facies recognized in cores were (1) stream-mouth-bar, (2) distributary-channel-fill, and (3) fluvial point-bar deposits. These environmental facies often occurred in various combinations in deltaic obes and displayed the electric log shape of the deltaic couplet. Characteristic electric log shapes of specific reservoir facies were an essential part of the study. The pilot waterflood was designed to inject into stream-mouth-bar facies and withdraw from centrally located distributary-channel-fill deposits with their better porosity and permeability. Critical to the design and subsequent performance of the waterflood project were (1) the distribution of porosity within the various reservoir facies, and (2) the occurrence, attitude, and lateral distribution of clay laminations within the lower stream-mouth-bar and upper fluvial deposits. The influence of clay laminations in lower stream-mouth-bar facies was particularly critical to waterflood performance. They were deposited on the distal slope of the stream-mouth-bar at a slight angle to the rock unit boundaries and therefore could mask parts of the reservoir from waterflood treatment. The amoun of masking was determined by calculations from facies geometry. After one year's operations, radioactive tracers indicate that the flood is operating as designed only at a reduced rate--probably as a result of the clay laminations. Figure Integrated Reservoir Analysis can be useful not only to production operations such as waterflood projects, infill drilling, recompletions, and reserve estimates, but a similar procedure could also be applied to exploration activity in mature areas with plentiful log data. End_of_Article - Last_Page 555------------

Summary of Performance and Evaluations in the West Burkburnett Chemical Waterflood Project

Abstract In late 1973, Mobil Producing Texas and New Mexico Inc. and Mobil Research and Development Corp. initiated a cooperative, low-tension waterflood (LTWF) project in Mobil's West Burkburnett waterflood, Wichita County Regular field. TX. The LTWF project encompasses ten 20-acre, five-spot patterns. A low-concentration surfactant slug was injected from Oct. 1975 to June 1976, followed in turn by biopolymer and freshwater drives. Tertiary oil production response first was noted near the completion of surfactant injection. and, to date, 17 of the original 20 producers are yielding incremental oil. Four producing wells outside the LTWF area have also shown some oil production response. The total tertiary oil production to the end of 1980 (actual) and to anticipated project termination in 1984 (projected) are estimated to be 238,000 and 320,000 bbl, respectively-equivalent to recovery factors of 17.6 and 24% of the OIP at project initiation. These figures pertain to total oil production, since the project area would have been abandoned if the LTWF project had not been initiated. To the end of 1980, the oil recovery attributed directly to effects of the LTWF process is 105,000 bbl, that projected to the anticipated project termination in 1984 is 180,000 bbl. The corresponding recovery factors are 8 and 13%, respectively. This paper summarizes the engineering studies associated with this chemical waterflood field test. Introduction Mobil's West Burkbunett waterflood is about 4 miles southwest of Burkbunett (TX) and is classified in the Wichita County Regular field. The pool discover)/ well was C. Schmoker No. 1. completed in June 1912. The producing sand is found at 1,600- to 1,800-ft depth and is designated the Gunsight sand in the Cisco series of Pennsylvanian age. The structure of the Gunsight sand in the area is lenticular, with the major axis running east and west. The sand dips approximately 250 ft from the south to the north. The producing sand is interspersed with shale and lenses into shale on all sides of the pool. Waterflooding began in 1944 with a pilot flood developed on 20-acre five-spot patterns. Expansion to full development occurred during 1948–50. The current waterflood is a group of 100% Mobil working-interest leases being waterflooded on a cooperative 20-acre five-spot pattern arrangement. In 1971, all the leases in the waterflood project either had become uneconomical to operate or were being projected to reach the economic limit by 1972 or 1973. Several leases on the east side of the project already had been abandoned. As a final step in exploitation. the project was evaluated for tertiary recovery by our LTWF multislug process. The functions of each of these slugs have been described by Foster and by Murphy et al. Plans were developed for application of the LTWF process in 10 adjacent, 20-acre patterns with 10 injectors, 20 producers, and 2 observation wells. This 200-acre development is shown in Fig. 1 as the enclosed area on a partial field map. Mobil Producing Texas and New Mexico operated the project, with personnel from Mobil Research and Development serving as technical consultants. The LTWF project began in Nov. 1973 with a freshwater preflush. Injection of the surfactant slug started in Oct. 1975 and ended in June 1976. This was followed by a polymer drive until April 1978. Since then, fresh water has been injected and is continuing. The injection schedule of this chemical flood is summarized in Table 1. From 1974 through 1977, an injection rate of approximately 3,000 B/D into 10 injectors was being maintained. JPT P. 2495^

GUPCO'S Experience in Treating Gulf of Suez Seawater for Waterflooding the El Morgan Oil Field

Summary Pressure maintenance by waterflooding in some reservoirs may be considered essential for satisfactory oil recovery. The main objective of waterflooding is to place water into a rock formation at both the desired rate and pressure with minimal expense and trouble. This objective, however, cannot be achieved unless this water has certain characteristics. The water, therefore, should be treated and conditioned before injection. This treatment should solve problems associated with the individual injection waters, including suspended matter. corrosivity of water scale deposition, and microbiological fouling and corrosion. Gulf of Suez Petroleum Co. (GUPCO) is waterflooding two fields, El Morgan and July, with Gulf of Suez (GOS) water. The paper addresses the treatment phases adopted to improve seawater quality before injection, and to control problems associated with untreated seawater. Also discussed are GUPCO'S experience in seawaterfloods, problems encountered, and corrective actions taken to overcome these problems. The chemical treatment programs adopted are presented along with final conclusions and recommendations that can be applied to similar floods in Egypt with GOS. Introduction Any treatment should be designed to solve the problems associated with individual injection waters. These problems involve suspended matters in the water, corrosivity. scale deposition, and microbiological fouling and corrosion. Additional problems that may result from water injection are injection well plugging and scale deposition both downhole in the oil producers and at surface in production equipment because of incompatible water mixing. Historically, in injection projects subsurface and/or makeup waters, river waters, and lake waters have been used. Seawater also has been used in many waterfloods. Pacific Ocean water, North Sea water, and Gulf of Mexico water have been used in similar waterflooding projects. ADMA has one seawater injection project in Abu Dhabi making use of Arabian Gulf water, which also is used in a large ARAMCO water injection project in Saudi Arabia and in Dubai as well. GUPCO has two injection projects for the El Morgan and July fields involving use of Gulf of Suez water. There is no published information on the characteristics of GOS water the treatment requirement for injection, or GUPCO'S operational experience with these projects. The main purpose of this paper is to introduce some information relative to GUPCO'S seawater injection system for the El Morgan field. Water Injection and Formation Plugging The quality of an injection water depends on its properties-e.g., suspended matter (turbidity caused by organisms and particulates), corrosivity in the system handling this water, and the tendency of the water to deposit scale. Hence the net water quality is dependent on all these properties simultaneously and is primarily connected with its capability to plug the formation rocks. Jones discussed rock plugging by solids. Generally, the tendency of an injection well to become plugged is dependent on the characteristics of both the formation and the injection water. The matrix of any rock is a fine filter for solids in the injection water (free or suspended). This is generally true in spite of differences in pore sizes that formation porous rocks may have. Consequently, the formation face of the water injection well is a good filter for the suspended solids present in the injection water and can become clogged. JPT P. 1449.

Strontium Sulfate Scale Control by Inhibitor Squeeze Treatment in the Fateh Field

Abstract With the increasing number of pressure-maintenance and waterflood projects throughout the world, seawater is being used more and more as the injection water. We have operated one of the oldest seawater injection projects at Bay Marchand, offshore Louisiana, since 1963. Much experience has been gained from this successful projectin the areas of corrosion and bacteria control, filter operations, and reservoir effects. More recently, we initiated an offshore seawater injection program at the Ninian field, U.K. North Sea. Water-treating requirements inherent to this offshore area have had to be considered in this project. There are similarities between the two projects but also significant differences because of differences in project size, age, and geography. Introduction The Bay Marchand field is situated off the coast of Louisiana, 55 miles (88 km) southwest of New Orleans. Development of the field in the 1950's was carried out by drilling directional wells from 12- and 24-wellplatforms and 4-well satellite units. Boreholes commonly are platforms and 4-well satellite units. Boreholes commonly are drilled at angles of 15 to 20 degrees from vertical, and lateral kickout is often 1,000 to 2,000 ft (300 to 600 m), and sometimes as much as 5,000 ft (1520 m). The six major reservoirs under injection are Miocene sand developments on the east flank of a large piercement saltdome. The injection wells are 11,000 to 12,000 ft (3350to 3660 m) deep. Porosity averages 29% and permeabilities range from less than 100 md to 2,000 md. permeabilities range from less than 100 md to 2,000 md. Pressure maintenance at Bay Marchand by using Pressure maintenance at Bay Marchand by using seawater as the injected fluid began in 1963. In 1969, Jordan et al. described the solution of subsequent problems that occurred. Since that time, very few changes problems that occurred. Since that time, very few changes have been made in the system, and the 50,000-B/D(7900-M3/d) seawater injection project has become one of the oldest and most successful. The Ninian field is located in Blocks 3/3 and 3/8 of the U.K. sector of the North Sea, 105 miles (169 km)north- east of the Shetland Islands at a water depth of approximately 460 ft (140 m). Production began near the end of 1978. The oil reservoir, which is about 10,000 ft (3050m) below sea level in Middle Jurassic sandstone, is 12 miles (19 km) long and 4 miles (6.4 km) wide, with anaverage thickness of 240 ft (73 m). The Ninian structure(Fig. 1) is a faulted block elongated along a north-south axis. The porosity and permeability average 20% and850 md, respectively. The reservoir is being developed as two separate units designated upper and lower reservoirs, the latter making up about 73% of the productive sand. Of the 108 wells planned for the field, 32 are in the upper reservoir (25 planned for the field, 32 are in the upper reservoir (25 producers and 7 injectors) and 76 are in the lower producers and 7 injectors) and 76 are in the lower reservoir (49 producers and 27 injectors). Pressure maintenance, required for economical production from this field, is accomplished by seawater injection. Seawater-treating facilities and injection pumps are located on each of the three platforms in the field. Injection pumps on the southern and central platforms are designed to deliver a total of 440,000 bbl(70 000 m3) of treated seawater per day at a discharge pressure of 4,200 psi (29 MPa). Similar pumps are pressure of 4,200 psi (29 MPa). Similar pumps are installed on the northern platform, with an initial capacity of 132,000 B/D (21 000 m3/d), expandable to 220,000B/D (35 000 m3/d). In the following, only the central and southern platforms are discussed, because operations at the northern platform began very recently. Seawater injection began at the southern platform in July 1979 and at the central platform in Dec. 1979. Discussion Bay Marchand A unit structure map, of the Bay Marchand field showing the locations of the platforms and satellite units is presented in Fig. 2. Structures AA, BB, U, W, and X are presented in Fig. 2. Structures AA, BB, U, W, and X are 12-well units, while Y and Z are 24-well units. JPT P. 2265

Lick Creek Meakin Sand Unit Immiscible CO2 Waterflood Project

Summary This paper reviews the early performance of an immiscible CO2 /waterflood project conducted for the past 5 years at the Lick Creek Meakin Sand Unit, AR. The project is currently in the third of four distinct phases. The conclusions drawn are that the project is successful and that the immiscible project is successful and that the immiscible CO2 /waterflood process is a viable process for thin, heavy oil sands. Introduction The Lick Creek field in southern Arkansas in Bradley and Union Counties (Fig. 1) was discovered in 1957. The unit was formed in 1975 for an immiscible CO2 /waterflood project. The reservoir is the Meakin sand of the Ozan formation of the Cretaceous Age. During the early 1970's, the oil production under primary methods was approaching abandonment primary methods was approaching abandonment rates and various secondary recovery methods were considered. A favorable response from a small- volume, immiscible CO2 project conducted by U.S. Oil and Refining CO2. in the nearby Ritchie field in a similar-type reservoir caused CO2, to be considered for the Lick Creek field. Theoretical considerations] and reservoir simulation indicated an immiscible CO2/waterflood process would be the preferable secondary recovery method for the Meakin sand, using alternate CO2/water injection at pattern injectors, cyclic CO2 stimulation of the producers, followed by a waterflood. The 16 injection patterns with the 38 producers are shown in Fig. 1. The project is being conducted in four distinct phases, using the 16 in - jectors and 38 producers on phases, using the 16 in - jectors and 38 producers on 1,640 acres (6.6 × 10 m). The phases are (1) cycling all wells with CO2, (2) CO2 injection into the permanent injectors, (3) CO2 /water injection into the permanent injectors, (3) CO2 /water injection into the permanent injectors, and (4) water injection into the permanent injectors, and (4) water injection into the permanent injectors. The project currently is in permanent injectors. The project currently is in Phase 3. Future plans are to drill nine additional Phase 3. Future plans are to drill nine additional producers, to rearrange the injection patterns, and to producers, to rearrange the injection patterns, and to double the recycling capacity. After 5 years of operation, 7.6 Bscf (0.22 × 10-9 std m3) of source CO2, and 6.5 Bscf (0. 18 × 10 std m3) of recycle CO2 have been injected, and more than 1 MMbbl (0.16 × 10-6 m3) of oil have been produced. About 755,000 bbl (120 000 m) are considered additional oil resulting from the process. Field rates have been as high as 1,400 BOPD (223 m /d oil), with the present rate being 833 BOPD (132m3/d oil). Reservoir Characteristics The Meakin sandstone reservoir is a fault-trap structure limited on the south by a fault and on the north, east, and west by low permeability and the water/oil contact. The Meakin sand is of beach origin, unconsolidated, and fine grained and is located in the Ozan formation near the top of the Upper Cretaceous. The under- and overlying shales are impermeable and represent a reservoir seal. Formation depth is 2,550 ft (777 m), net thickness averages 9 ft (2.7 m), permeability averages 1,200 md, porosity is 33%, and the connate water saturation is 32%. The reservoir produces a 17 deg. API (0.95 g/cm3) Oil and has a viscosity of 160 cp (0.160 Pa s) at the reservoir temperature and pressure of 118 deg. F (48 deg. C) and 1,200 psi (8274 kPa). Original oil in place (OOIP) was 23.3 MMbbl (3.7 × 10-6 m3), with about 4.5 MMbbl (0.7x 10 m), or 19% of OOIP, being produced by pressure depletion and a weak water produced by pressure depletion and a weak water drive in the 20 years before the project (see Table 1). Before CO2 injection, the field was pumped at a rate of 230 BOPD (36.6 m /d oil), a low GOR, and a WOR of 21. During the huff ‘n’ puff phase, all wells flowed naturally. JPT P. 1723

Water Quality Aspects of North Sea Injection Water

Summary This paper discusses current water quality assessment methods and some of the parameters that can affect the suitability of North Sea water as an injection fluid. Also included are general comments on the North Sea and its biomass. Examples are drawn from tests carried out during the commissioning of the Forties field seawater injection system in 1976-78. Introduction The use of seawater for subsurface injection is well known in many oil production areas. An area of particular interest at the present time is the North Sea, where the number of offshore seawater injection facilities is increasing rapidly. The high expense of offshore operations plus the high capital cost of the platform very often impose severe constraints on the design engineers, particularly in terms of the size and weight of treatment facilities. An important factor affecting the success of a waterflood project is the quality of the water being injected. Generally, the design basis is such that the water quality should enable injection for the life of the project at a minimum injection pressure and minimum cost. However, very often the quality standards required for injecting a particular water into a particular formation are not known in the early stages of the project. Design Considerations The water quality requirements for successful injection of seawater into North Sea reservoirs is a highly controversial topic at the present time. Water quality is affected by several types of contaminants including suspended solids, scale, oil, bacteria, corrosion products, and marine organisms. Generally, the major water quality problems associated with a seawater flood are due to colloidal iron formation and the presence of organisms. In the past, such problems have been overcome by using other sand or diatomaceous earth filters or by hydraulic fracturing of the formation. However, some operators have experienced problems with the latter approach due to sand influx into the injectors and fracture breakthrough into the producing wells. In an offshore situation, sand or diatomaceous earth filters can be employed only at considerable cost due to their size and weight. In this respect it is essential, therefore, that water quality specifications and designs are adequate but not ultraconservative.North Sea water generally is good quality, containing between 0.2 to 0.8 mg/L suspended solids as determined by membrane filtration techniques. The Forties field seawater injection system has been described previously, and a schematic diagram of the system (capable of handling 150,000 B/D of water) is shown in Fig. 1. Because of the general good quality of water present in the Forties area and weight limitations on the platform, two back-washable cartridge filters are employed. A four-pod filter containing an 80-micron stainless steel element located downstream of the seawater winning pumps provides the first stage of filtration (coarse). A second stage of filtration (fine) is achieved using another filter skid, containing a fiber element, located immediately upstream of the main injection pumps.Initially, there were several problems associated with the fine filters, mainly concerning the backwash and filtration efficiency. To overcome those problems, a considerable development effort was carried out by BP Petroleum Development during 1976–1978. Although that study was aimed primarily at obtaining an efficient backwashable filter element, the data also were employed to investigate present water quality prediction methods. This is of considerable importance as there is very often the need to assess water quality in an unknown environment. JPT P. 1141^

Innovative Reservoir Management - Key to Highly Successful Jay/LEC Waterflood

Summary A comprehensive surveillance program and detailed reservoir description data were combined to provide innovative reservoir management for the Jay/Little Escambia Creek (LEC) waterflood. As a result of effective management, this waterflood has proved highly successful. Benefits of surveillance and data gathering have outweighed costs greatly. Introduction Following discovery of the Jay/LEC field Smackover reservoir in June 1970, an early decision was made by field operators to obtain extensive reservoir description data during field development. Consequently, 102 development wells were cored conventionally from 1970 to 1974. This resulted in the procurement of a wealth of reservoir rock data available for use in describing the reservoir to provide a basis for unitization and to plan and justify a waterflood project.1 During 1973, as planning for waterflood operations progressed, it became apparent that comprehensive surveillance was needed to complement the reservoir description data fully and, thereby, optimize recovery through effective reservoir management. A surveillance program was developed to monitor and control waterflood conformance in the thick-layered reservoir. Cased-hole logging tools along with pressure buildup and production tests are used extensively, in conjunction with permeability data from core analyses, to provide vertical conformance data. Areal conformance surveillance techniques employ radioactive tracers, reservoir pressure data, and interference tests. Use of surveillance information together with the reservoir description data yielded many new insights into water movement and zone depletion. Fluid movement analysis technique were developed, and several methods to improve recovery were defined. These include drilling, workovers, facility modifications, and injection balancing. These efforts have been responsible for maintaining field producing capability and delaying production decline until late 1979 and 75% of the estimated ultimate recoverable reserve had been produced. Field History The discovery well for the field, St. Regis No. 1, was completed in the Smackover formation in June 1970. A total of 102 wells was drilled on 160-acre (65-ha) well spacing during the development period from 1970 to 1974. Eighty-nine wells were producers, and 13 were dry holes. The Jay/LEC field was unitized on March 1, 1974, to implement a waterflood, and a 3:1 staggered line drive pattern was selected.2 Ultimate recovery expected is 346 million STB (55×106 stock-tank m3) or 47.5% of the 728 million STB (116×106 stock-tank m3) of original oil in place. This represents 222 million STB (35×106 stock-tank m3) more recovery than from primary operations. Water injection began on March 5, 1974. The basic operating plan was to open the entire productive section in both injection and production wellbores and, thereby, waterflood all Smackover zones simultaneously. Injection wells were acid fractured using large staged treatments to create connecting vertical fracture systems between spaced sets of perforations. In production wells, the entire productive section was opened without acid fracturing to maintain the flexibility to control future water production. The 3:1 line drive pattern has operated very successfully. The rapid reservoir pressure decline experienced during primary operations was arrested quickly, and maximum oil allowable rates were sustained.3

Production Technology Experience in a Large Carbonate Waterflood, Denver Unit, Wasson San Andres Field

Shell Oil Co. currently is operating a large waterflood project in the Permian San Andres dolomite reservoir in west Texas. The project comprises 900 producers and 360 injectors. In addition to major infill drilling programs, a substantial remedial and reconditioning program has been carried out. Highlights of production technology experience are presented. Introduction The Denver Unit waterflood project in the Wasson San Andres field in West Texas ranks among the largest supplemental recovery projects currently operating in the U.S. (Fig. 1). Shell Oil Co. is the operator and holds the major working interest. The paper has evolved through several phases of infill development drilling and flood pattern modifications that have been carried out in the course of conducting the waterflood project. The paper is divided into two parts. The first deals with a brief history of the waterflood with the objective of providing the project setting for the production technology practices currently being followed. The emphasis is placed not on the statistical data per se but rather on the evolutionary process through which present procedures have been developed, as well as their interrelationship with the geologic, petrophysical, and reservoir aspect as as they pertain to the project. The second part describes the specific practices of well completion, well stimulation, injection profile control, artificial lift, flood surveillance, and related drilling, remedial, and reconditioning operations now being used and how they have contributed to the enhancement of ultimate recovery from the project. Historical Background The Wasson San Andres field was discovered in 1936. The bulk of primary development at 40-acre (162 000-m2) well spacing was completed by the early 1940's. Supplemental recovery operations were initiated with unitization and commencement of water injection in 1964 (Fig. 2). The producing horizon is the Permian San Andres dolomite formation at an average depth of 5,200 ft (1585 m). Gross oil pay thickness varies between 200 and 500 ft (60 and 150 m). The structure is an anticline capped by dense dolomite and underlain by an essentially inactive aquifer. Solution-gas drive has been the primary producing mechanism. Table 1 shows a summary of basic project data. The oil reservoir has an original gas cap. Although some production has occurred from the gas cap, primarily before unitization, Shell's policy during waterflooding operations has been to leave the gas cap unexploited to conserve reservoir energy and prevent waste by the migration of oil into the gas cap. When unitization was effected in 1964, the geologic concept of the reservoir was a simplistic one and was markedly different from the rather complex model that has evolved today. The original definition of the San Andres reservoir was based on gross geologic correlations of reservoir-quality rock and the assumption that this rock largely was interconnected over the entire extent of the unit.

A study of earthquakes in the Permian Basin of Texas-New Mexico

abstractA microearthquake seismograph network has been employed to study earthquakes occurring in the Permian Basin of Texas and New Mexico. The earthquakes are predominantly located on the Central Basin platform, although a few occur in the Delaware Basin. The majority of the earthquakes occur at the depths of sedimentary rocks, and the focal depths are also coincident with the depths at which hydrocarbon production and water-flood (secondary recovery) operations are conducted. Comparison of the historic earthquake activity with water-flood data shows that there was a possible increase in the number of large earthquakes (M > 3.0) in the mid-1960's when the number of water-flood projects and their injection pressures increased. The first felt event occurred in 1966. This tentative correlation suggests that the earthquakes are related to hydrocarbon production in this area.

Formation Evaluation Using Wireline Formation Tester Pressure Data

This paper describes the Repeat Formation Tester, a tool that can make on one open-hole trip an unlimited number of pressure determinations. Down-hole pressure data from the tool are used to monitor and enhance the effectiveness of a waterflood in Rangeley Field, CO. Data from this tool also are used in a technique to evaluate permeability; results in U.S. Gulf Coast wells are compared with those from sidewall cores. Introduction One key to meeting our future energy requirements is more efficient production of new and remaining reserves. To this end, information is needed on conditions down hole, including accurate down-hole formation pressures. The Schlumberger Repeat Formation Tester (RFT) is an open-hole wireline device capable of providing such pressure data with minimal demands for drilling-rig time. pressure data with minimal demands for drilling-rig time.The RFT may be set any number of times during a single logging run. At each setting depth, a "pretest" is made in which small samples of fluid are withdrawn from the formation. During this pretest, the fluid pressure in the formation adjacent to the wellbore is monitored until equilibrium formation pressure is reached. These RFT pressure data are recorded at the surface on both analog pressure data are recorded at the surface on both analog and high-resolution digital scales. The pretest fluid samples are not saved. However, after the pretests in a zone of interest, another larger fluid sample can be taken optionally and retained, with the possibility of retrieving two such fluid samples per trip in possibility of retrieving two such fluid samples per trip in the hole. In this paper, however, interest is directed to the large number of pressure measurements that can be made by setting the tool and going through the pretest cycle at successively different levels. Recent experience of Chevron U.S.A. Inc., in the Rangely Field of Colorado is described to demonstrate the quality of the pressure measurements and the reliability of tool operation. Chevron applies the pressure information to the planning and monitoring of pressure information to the planning and monitoring of a secondary-recovery waterflood project. Pressure data, in conjunction with other data available during the drilling of infill wells, were used to predict which flooded zones would produce with a high water cut. By eliminating these zones from production and by injecting into essentially unflooded zones, the effectiveness of the flood could be enhanced. The pressure measurements have been used with open-hole and mud-log data to predict the expected water cut. Significant pressure predict the expected water cut. Significant pressure overbalance suppresses hydrocarbon shows on the mud log. Pressure underbalance exaggerates hydrocarbon shows. Both lead to erroneous water-cut predictions. Knowledge of the pressures makes it possible to allow for such errors. Pressure profiles through the Weber sandstone reservoir were determined in a number of wells in the Rangely Field. Reservoir pressures were found to vary greatly and to be distributed erratically both vertically and horizontally. This is attributed to the field's long history of production and water injection and to the fact that many of the permeable zones are discontinuous. Plotting these pressure permeable zones are discontinuous. Plotting these pressure data on contour maps delineates areas requiring increased flooding to maintain the effectiveness of the waterflood program. program.During the drawdown phase of the pretest, when fluid is being extracted from the formation, the pressure behavior is indicative of the minimum local permeability at that depth. A simple technique is described for computation of permeability from the pressure data, based on a steady-state spherical flow model. JPT P. 25