Gas-oil Contact Research Articles

Development of a Marginal Property: Petronella Field

Summary Texaco has chosen subsea techniques to develop a small reservoir located 6.5 miles [10.5 km] from the Tartan platform in the U.K. sector of the North Sea. Water depth in the area is approximately 430 ft [131 m]. This paper is a case study that discusses evaluation criteria used in determining the development scenario. Reservoir and geologic data relative to the accumulation are reviewed. Also discussed are the development and results of the well drilling program, with emphasis on the procedure used to develop the well testing program. Reservoir simulation performed in support of project evaluation is presented and results are performed in support of project evaluation is presented and results are reviewed. We also discuss the design procedure, including selection criteria for surface and subsurface equipment, and review the economic evaluation. Introduction The Petronella field is located 6.5 miles [10.5 km] southeast of the Tartan ‘A’ production platform and 5 miles [8 km] south of Highlander field in Block 14/20b in the U.K. sector of the North Sea (see Fig. 1). Average water depth in the area is 430 ft [131 m]. Well 14/20–1, the discovery well on the block, was drilled in Feb. 1975 to a depth of 9,034 ft [2753 m] subsea. The well encountered a hydrocarbon section of Upper Jurassic Age with a gross thickness of 768 ft [234 m] (275 ft [84 m] net) at 7,269 ft [2215 m] subsea. An oil/water contact (OWC) was encountered at 7,650 ft [2331 m] subsea. A drillstem test (DST) was conducted on a 20-ft [7-m] interval from 7,354 to 7,374 ft [2241 to 2247 m] subsea. The test consisted of five flow periods: an initial cleanup flow, the main flow (4,537 B/D [721 m3/d] oil), and three higher-rate flows (5,898, 6,722, and 7,605 B/D [937, 1068, and 1209 m3/d] oil). Analysis of the data showed a variation in PI from 10 to 15 B/D-psi [0.13 to 0.34 m3/d kPa] oil (including effects from formation damage). Estimates of PI with zero skin indicated that values of 100 to 200 B/D-psi [2.3 to 4.6 m3/d kpa] oil could be expected. API gravity of the crude oil produced during the test was 40.2 degrees [0.82 g/cm3] with a GOR of 1,036 scf/STB [186 std m3/stock-tank m3]. Reservoir pressure and temperature measured during the DST were 3,340 psi and 160 degrees F [23 MPa and 71 degrees C], respectively. After completion of the test, the well was plugged and abandoned. Four additional exploratory/appraisal wells were drilled in the vicinity of Well 14/20–1 between 1975 and 1980 to delineate the accumulation (Wells 14/20–2, 3A, 10, and 11). As defined, the structure is a tilted fault block trending approximately east/west across the southern portion of Block 14/20 (see Fig. 2). It is bounded by faults that are part of the principal bounding structures on the southern margin of the Witch Ground Graben. Development Drilling Well 14/20–16. In 1985, Well 14/20–16, a development well, was drilled. The purpose of the well was to provide a productive outlet for the accumulation that had been defined by the five exploration/appraisal wells. The well was drilled to a total depth of 8,110 ft [2472 m] (8,028 ft [2447 m] subsea) and encountered 184 ft [56 m] of hydrocarbon-bearing sand of which 138 ft [42 m] is oil bearing. A simplified lithological section of the reservoir in Well 14/20–16 is presented in Fig. 3. The base of the pay zone is about 190 ft [58 m] above the OWC encountered in Well 14/20–1. The well also determined a gas/oil contact (GOC) at 7,316 ft [2229 m] subsea.

Fahud Field Review: A Switch From Water to Gas Injection

Summary The water injection schemes implemented in the Fahud field during the early 1970's led to poor recoveries because the reservoirs were both fractured and oil-wet. On the basis of the results of a thorough performance review, it was decided in 1983 to promote gas/oil gravity performance review, it was decided in 1983 to promote gas/oil gravity drainage fully by drilling rows of downdip producers and switching completely from water to gas injection. This paper investigates the reasons behind each stage of development and reviews recent efforts to evaluate the future production potential through the use of dual-porosity simulators. Introduction The Fahud field (Fig. 1), which has a stock-tank oil initially in place (STOIIP) of 1000 × 10(6) stock-tank m3 [6,300 × 10(6) STB], is an elongated monocline with an eroded fault escarpment. The field is divided by a permeability barrier into two accumulations, Fahud North-West (NW) and South-East (SE), each of which contains three fractured Natih limestone reservoirs. The three Fahud NW reservoirs (NW-A, NW-C/D, and NW-E/F/G) are separated by continuous shales but are in communication with each other across the eroded fault escarpment (Figs. 2 and 3). The same applies to the three Fahud SE reservoirs (SE-A, SE-C/D, and SE-E). The oil has a density of 870 kg/m3 [31 deg.API] with initial reservoir fluid properties as presented in Table 1. The field was discovered in 196 properties as presented in Table 1. The field was discovered in 196 and started production in 1967. To date, 12 % of the field's STOIIP has been produced. This paper reviews the field's performance during four distinct phases of development: initial, waterflood, reassessment, and present development. Initial Development 1967–71. The field was initially produced under natural depletion supplemented in 1968 by gas injection. The high offtake rates led to a rapid displacement of the gas/oil contact (GOC), which resulted in the early gassing out of a number of relatively downdip completions. Simulation studies and field trials were conducted, which concluded that better recoveries would be obtained through waterflooding. Waterflood Period-1972–80. Following the recommendations, water injection schemes were implemented in four of the six Fahud reservoirs. However, they failed to arrest either the pressure or oil production decline. Reassessment Period-1981–83. The poor performance of the waterflood led to a thorough review during which a number of thermal decay time (TDT) logs and tracer tests were conducted. It was concluded that because the reservoir rock was both fractured and oil-wet, recovery factors from waterflooding were low and could be substantially improved by reverting to full-scale gas/oil gravity drainage. Present Development-From 1984. The present policy is to promote gas/oil gravity drainage fully. This ongoing development promote gas/oil gravity drainage fully. This ongoing development requires the phasing out of water injection, the completion of downdip grids of producers, and the full replacement of voidage by gas injection. Dual-porosity simulation studies are currently being conducted to optimize the remaining development and to predict the future field performance.

Gas Chromatography as a Tool for Reservoir Continuity Determination and Field Management: ABSTRACT

Determining reservoir continuity is important for planning an effective field development program and subsequent field management. The question of where the fluids are coming from is inevitably encountered. The traditional approach to establishing reservoir continuity is a combination of wireline log correlations and pressure tests for hydraulic communication. An alternative approach, though not as well known, is analyzing the reservoir fluids. This paper deals specifically with crude oil analysis, but similar applications exist for formation waters. In the authors' worldwide experience over the past 20 years, the authors have determined that oils in a continuous reservoir have a uniform hydrocarbon composition in the C/sup 7/-C/sup 35/ range when sampled away from the oil-water or gas-oil contacts. Furthermore, oils in separate reservoirs have hydrocarbon compositions that are significantly different, although the differences may be small. The most successful technique for determining reservoir continuity is whole-oil-gas chromatography. Oil correlations using the chromatographic fingerprints can be made using various graphical and multivariate statistical techniques. The chromatographic technique is inexpensive, especially compared to other field evaluation costs. The technique is a simple and rapid analysis, which can be performed in field production laboratories by using oil samples from well tests (DST and RFT), productionmore » samples, and core extracts. Case histories illustrate how this technique has been used to solve development and production problems.« less

Theoretical aspects of cap-rock and fault seals for single- and two-phase hydrocarbon columns

Cap-rock seals can be divided genetically into those that fail by capillary leakage ( membrane seals) and those whose capillary entry pressures are so high that seal failure preferentially occurs by fracturing and/or wedging open of faults ( hydraulic seals). A given membrane seal can trap a larger oil column than gas column at shallow depths, but below a critical depth (interval), gas is more easily sealed than oil. This critical depth increases with lower API gravity, lower oil GOR and overpressured conditions (for the gas phase). These observations arise from a series of modelling studies of membrane sealing and can be conveniently represented using pressure/ depth ( P/D) profiles through sealed hydrocarbon columns. P/D diagrams have been applied to the more complex situation of the membrane sealing of a gas cap underlain by an oil rim; at seal capacity, such a two-phase column will be always greater than if only oil or gas occurs below the seal. These conclusions contrast with those for hydraulic seals where the seal capacity to oil always exceeds that for gas. Moreover, a trapped two-phase column, at hydraulic seal capacity will be less than the maximum-allowed oil-only column, but more than the maximum gas-only column. Unlike membrane seals, hydraulic seal capacity should be directly related to cap-rock thickness, in addition to the magnitude of the minimum effective stress in the sealing layer and the degree of overpressure development in the sequence as a whole. Fault-related seals are effectively analogous to membrane cap-rocks which have been tilted to the angle of the fault plane. Consequently, all of the above conclusions derived for membrane cap-rocks apply to both sealing faults sensu stricto (fault plane itself seals) and juxtaposition faults (hydrocarbon trapped laterally against a juxtaposed sealing unit). The maximum-allowed two-phase column trapped by a sealing fault is greater than for equivalent oil-only and gas-only columns, but less than that predicted for a horizontal membrane cap-rock under similar conditions. Where a two-phase column is present on both sides of a sealing fault (which is at two-phase seal capacity), a deeper oil/water contact (OWC) in one fault block is associated with a deeper gas/oil contact (GOC) compared with the adjacent fault block. If the fault seal is discontinuous in the gas leg, however, the deeper OWC is accompanied by a shallower GOC, whereas a break in the fault seal in the oil leg results in a common OWC in both fault blocks, even though separate GOC's exist. Schematic P/D profiles are provided for each of the above situations from which a series of fundamental equations governing single- and two-phase cap-rock and fault seal capacities can be derived. These relationships may have significant implications for exploration prospect appraisal exercises where more meaningful estimates of differential seal capacities can be made. The membrane sealing theory developed herein assumes that all reservoirs and seals are water-wet and no hydrodynamic flow exists. The conclusions on membrane seal capacity place constraints on the migration efficiency of gas along low-permeabiligy paths at depth where fracturing, wedging open of faults and/or diffusion process may be more important. Contrary to previous assertions, it is speculated that leakage of hydrocarbons through membrane seals occurs in distinct pulses such that the seal is at or near the theoretically calculated seal capacity, once this has been initially attained. Finally, the developed seal theory and P/D profile concepts are applied to a series of development geological problems including the effects of differential depletion, and degree of aquifer support, on sealing fault leakage, and the evaluation of barriers to vertical cross-flow using RFT profiles through depleted reservoirs. It is shown that imbibition processes and dynamic effects related to active cross-flow across such barriers often preclude quantitative analysis and solution of these problems for which simulation studies are usually required.

Sorrento-Mount Pearl-Siaana Field Complex, A Major Morrow Accumulation in Southeast Colorado: ABSTRACT

Pennsylvanian Morrow sandstones are oil and gas productive throughout a large area in southeast Colorado. The Sorrento-Mount Pearl-Sianna fields represent an area of 8200 acres (3319 ha) of continuous production at depths of 5316-5575 ft (1620-1699 m) from a middle Morrow sandstone reservoir. Recoverable reserves for the three fields are estimated to be over 20 million bbl of oil. The average ultimate recovery per well is 250,000 to 300,000 bbl of oil. On the basis of subsurface mapping, productive sandstones are interpreted to be fluvial valley-fill deposits, consisting mainly of channel sandstones. The deposits are encased in marine shale and range in thickness from 0 to 72 ft (0 to 21.9 m). The Sorrento-Mount Pearl-Sianna field complex is a large stratigraphic trap formed by a change of channel trend against regional structure. Paleostructure may have controlled the location of the valley-fill system. Present-day structure plays a minor role by creating multiple gas-oil and oil-water contacts in the fields.

Red Fork and Lower Skinner Sandstones in Northwest Tecumseh Field, Pottawatomie County, Oklahoma: ABSTRACT

The Northwest Tecumseh field, discovered in 1978, produces from the Pennsylvanian Skinner and Red Fork sandstones at 4800 ft. The 50 wells had produced 6.4 million bbl of oil and 20.8 bcf of gas through 1986. The field is 4.5 mi long, 3/4 mi wide, and the vertical section contains up to 132 ft of sandstone with greater than 10% porosity. These stacked, interconnected north-northeast-trending, channel-fill sandstones are part of a much larger fluvial/distributary system. These channels flowed to the north and cut down into underlying, fossiliferous, carbonate-bearing marine shale. A pre-Pennsylvanian structural low, trending north-northeast, existed in the southern half of the field and created a predisposition for the channel trend which continued through Red Fork and Skinner deposition. The north-northeast-trending sandstone complex, parallel with present-day regional structural strike, provides the excellent configuration for this efficient stratigraphic trap. The northern end of the field is marked by bifurcation of the channel complex and by the crosscutting of a younger clay-filled channel. Despite the lenticularity of the sandstone sequence, there appears to be a uniform gas-oil contact and minor southwestward tilt of the oil-water contact in the south part of the pool. The primary reservoir energy is provided by amore » dissolved gas drive, with some assistance from the 60-ft gas cap. The vertical oil column is 80 ft. These reservoir sandstones are fine-grained quartzarenites, and the dissolution of ferrodolomite has increased porosities up to 21%. Kaolinite is the predominant clay mineral and has a tendency to migrate and reduce permeability during production.« less

A Full Field Model Study of the East Velma West Block Sims Sand Unit Reservoir

Summary A full-field numerical model of the East Velma West Block Sims Sand Unit (EVWBSSU) reservoir was developed. The three-dimensional, four-component, heterogeneous, 3,200-cell model will aid in the evaluation, analysis, and operation of a CO2 flood now in progress. CO2 is being injected in a continuous mode in the updip portion of the steeply dipping reservoir, A specially portion of the steeply dipping reservoir, A specially constructed grid, detailed reservoir description, and multiple fluid property tables were used to account for the variation in the reservoir's structure, geology, and fluid properties. The present state of the reservoir was properties. The present state of the reservoir was determined after 33 years of production history were matched. Methods of production included primary depiction under gravity drainage, secondary production using gas injection for pressure maintenance, and waterflood. From the history-matched model, field performance predictions were made for continued waterflood and various operating scenarios under the present CO2 injection scheme. Results include the effect Of CO2 pipeline supply rate, allocation Of CO2 and water to injection wells, and uncertain parameters on reservoir performance. From these projections it was concluded that the amount of injected projections it was concluded that the amount of injected CO2 required to produce an incremental barrel of oil over waterflood was not strongly dependent on CO2 pipeline supply rate or allocation of injected fluids to pipeline supply rate or allocation of injected fluids to injection wells. This conclusion seems reasonable mechanistically because the miscible displacement was dominated by gravity, the areal variation in predicted updip oil saturation was not great, and the continuous injection coupled with high permeability updip caused uniform distribution of CO2. Introduction The EVWBSSU reservoir was studied using a four- component numerical reservoir model. The steeply dipping reservoir is located in Stephens County, OK, and was discovered and developed during 1949–50. Methods of production during the life of the field included primary depletion under gravity drainage (1949–62), secondary production using gas injection for pressure maintenance production using gas injection for pressure maintenance (1962–72), and waterflood (1972–82). Field recovery through all phases of production history was 32.3%. Currently, the field is being flooded with CO2 and water. A pipeline supply of CO2 from a fertilizer plant in Enid, OK, along with recycled CO2 and gas obtained from a field processing plant, is being injected continuously into seven updip injection wells. The field model was developed as a planning tool to aid in the evaluation, analysis, and operation of the CO2 flood. A history match of the field production data yielded an estimate of the present state of the reservoir:current fluid saturations by tracking gross fluid movement during the life of the reservoir andverification of the reservoir and fluid descriptions. The most important mechanisms to history match for realistic predictions were the gas/oil gravity drainage and waterflood oil-rate decline. The gravity-drainage calculation gives an estimate of the location and movement of the gas/oil contact (GOC) during the first 23 years of production. This information is important in the sweeping production. This information is important in the sweeping of residual oil with the updip CO2 injection scheme. The waterflood oil-rate decline yields a forecast of how the reservoir would decline under present operating conditions. One can then evaluate how much better performance is with CO2 injection. performance is with CO2 injection. From the results of the history match, simulations to analyze the current updip CO2 injection operations were performed. Deliverability Of CO2 from the Enid fertilizer performed. Deliverability Of CO2 from the Enid fertilizer plant has been up to two-thirds less than anticipated. The plant has been up to two-thirds less than anticipated. The model was used to predict the effect of lower CO2 pipeline supply rates on reservoir performance. Then pipeline supply rates on reservoir performance. Then cases were run to evaluate current operations. Finally, sensitivity studies were performed on uncertain model parameters. parameters. Model Development A complex and carefully constructed reservoir model was required because of EVWBSSU's steep and variable dip, variation of fluid properties, and heterogeneity. A special grid was constructed to account for the field's structural variation. Multiple tables were used for some fluid properties. A detailed geologic description was constructed properties. A detailed geologic description was constructed from core and log data. Incongruent field data were compiled into a form suitable for history matching. Grid Construction. Gridblocks were constructed by a method that accounts for both the variation in the field's dip and its thickness. In addition, if it is assumed that the reservoir was deposited in layers parallel to the bedding plane, the resulting grid orientation is such that the plane, the resulting grid orientation is such that the permeability tensor contains only diagonal elements. permeability tensor contains only diagonal elements. JPT P. 1429

Exploration, Development, and Reservoir Engineering Studies for the Tapis Field Offshore Peninsular Malaysia

Summary This paper presents the rationale for oil development in the sandstone reservoirs of the Tapis field offshore Peninsular Malaysia. Pressure maintenance plans, well Peninsular Malaysia. Pressure maintenance plans, well spacing, and completion plans have been modified in response to data from exploratory and development drilling. Reservoir simulation has been a valuable tool in optimizing field development. Introduction The Tapis field is located in the South China Sea, 130 miles (209 km) off the east coast of peninsular Malaysia in 210 ft (64 m) of water (Fig. 1). Esso Production Malaysia Inc. (EPMI) has explored and developed the field as a contractor to Petroleum Natl. Berhad (PETRONAS), the Malaysian national oil company. Development plans for the field have been modified several times on the basis of data obtained from ongoing exploratory and development drilling. The producing reservoirs at Tapis are Miocene Age Group J (Tapis formation 1) sandstones that contain rim-type oil accumulations with associated gas caps. The three primary reservoirs, J-20, J-25, and J-30, are shoreface/barrier bar deposits separated by shale sequences. Both faulting and stratigraphic variations cause localized discontinuities across the field. Development wells from 4 platforms and 10 exploration wells have delineated most of the field. Reinjection of casinghead gas and waterflooding are being used to increase ultimate oil recovery. Two fieldwide reservoir-simulation studies have helped to optimize field development. These modeling efforts enabled selection of optimal waterflood pattern and determination of water-injection requirements, relative merits of commingled production vs. selective completions, benefits of gas injection, and recovery efficiency for the field. Detailed reservoir description work allowed assessment of reservoir continuity and assisted in selection of workovers needed to implement the waterflood. Exploration Exploration History The Tapis field was discovered in 1969 with the drilling of Tapis Well 1 near the crest of the structure (Figs. 2 and 3). The well, Esso's first in the Malay basin, found gas in the sandstones of Groups J and K. In 1974, Tapis Well 2, drilled downdip to Tapis Well 1, discovered oil in the Group J sandstones. It encountered a gas/oil contact (GOC) in J-20, establishing a hydrocarbon column of 740 ft (226 m) and a proved oil column of 170 ft (52 m). Pressure and fluid data indicated that the lower Group J sandstones (J-20, J-25, and J-30) had common fluid contacts and were in a separate fluid/pressure system from the upper Group J sandstones (J-10 and J-15). In 1975, Tapis Wells 3 and 4 were drilled to delineate the Group J oil columns on the flank of the structure. Both wells encountered oil in the Group J sandstones and the lower Group J proved-oil column was extended to 1,516 ft (462 m). JPT P. 1051

Numerical Simulation Of The North Ricinus Cardium A Reservoir

Abstract The North Ricinus Cardium A Pool is a beach barrier system located on the edge of the disturbed belt, approximately 130, km northwest of Calgary, Alberta. The current operating mode for the pool involves a cycling scheme in the retrograde gas cap with the oil leg on primary depletion. A standard 3D-3 phase black oil model, modified with several specialized subroutines, was used to simulate the cycling scheme in the history match and prediction modes. Pseudo-relative permeability curves were used to describe displacement of rich gas by lean gas in the gas cap, while two sets of relative permeability curves were required to match oil production. The model was subsequently utilized to establish reserves and to optimize natural gas liquid recovery by infill drilling in the gas cap. Introduction The Ricinus Cardium A Pool, discovered in January 1969, is located approximately 130 kilometres northwest of Calgary, FIGURE 1. Location map. (Available in full paper) FIGURE 2. North Ricinus geology.(Available in full paper) Alberta (Fig. 1). The pool initially was considered to be a large retrograde condensate gas cap in association with a relatively small oil leg containing a high shrinkage oil. An application in June 1971(1) to concurrently produce the gas and oil based on good production practice was refused by the ERCB. In July 1972 a scheme to cycle the gas cap was subsequently approved with the provision that the operator show cause after one year of production why a VRR of unity need not be maintained(2). Gas cap cycling commenced in April 1973 and a performance review submitted in July 1974(3) indicated that a VRR of between 0.85 and 1.00 had no appreciable effect on gas cap liquid recoveries and the ERCB did not impose a full voidage replacement ratio at that time. Subsequent step out drilling to the north indicated that the oil leg was much larger than previously estimated; and in May 1979, the ERCB(4) requested a study to determine the effect of VRR on the oil recovery and also an updated estimate of original reservoir volumes. A black oil reservoir simulation study, incorporating special modifications, was initiated in June 1979 to address the ERCB's concerns. The model was subsequently utilized to establish pool reserves and to investigate optimization of natural gas liquid recovery by infill drilling. Geology The Ricinus Cardium Pools occur in the Cardium A Sand of Upper Cretaceous age. The reservoir is a beach barrier system trending 20 km in a northwesterly direction and averaging 3 – 5 km in width at a mean depth of 1325 m ss (Fig. 2). The reservoirs are complex structural traps occurring at the edge of the disturbed belt. The Cardium A Pool consists of a retrograde gas cap condensate overlying a volatile oil pool in a weakly folded synclinal structure that plunges gently to the northwest with the gas oil contact occurring at 1463 m ss. A major under thrust forms a pressure barrier to the Cardium K pool to the southwest with porosity pinchouts forming the reservoir boundaries in other directions (Fig. 2).

North Cross (Devonian) Unit CO2 Flood - Review of Flood Performance and Numerical Simulation Model

Although the North Cross (Devonian) Unit CO2 flood has not performed as dramatically as predicted, response to CO2 injection has been encouraging. Sharp, sustained production increases in responding wells and minimal CO2 breakthrough indicate that CO2 is displacing oil efficiently. No major operating problems have been encountered so far. CO2 injectivities have been significantly below initial predictions. Introduction The Crossett Field (Crane and Upton counties, west Texas) was discovered in 1944 with the Texaco Hobbs A-1 well. Development of the 28-well field essentially was completed by the mid-1950's. The major producing horizon is the Devonian "Main Pay," a classical Archie Type 11-A rock composed of microscopic, tripolitic chert grains bound by limestone cement. The formation is characterized by high porosity, averaging 22%, and low uniform permeability, averaging 5 md. Connate water saturation averages 35%. The Crossett Devonian is a stratigraphic trap, bounded on the north, south, and west flanks by a deterioration of porosity, and on the east flank by the producing water porosity, and on the east flank by the producing water level of - 3,040 ft (Fig. 1). The reservoir oil was initially saturated (PVT properties are presented in Table 1), and a gas-oil contact existed at -2,860 ft. The gross pay distribution is described in Fig. 2. Net-to-gross pay ratios for individual wells range from 70 to 100%, and pay continuity among wells is very good. The primary producing mechanism of solution gas drive ultimately will recover 12.9% of the original oil in place. The field was developed on regular 40-acre spacing and produced under primary recovery until 1964. Crossett Field was unitized in 1964, when the North Cross (Devonian) Unit (operated by Shell Oil Co. with a working interest of 58.3%) was formed. Simultaneously, a program of partial pressure maintenance by updip program of partial pressure maintenance by updip residue-gas injection began. That program added 45% of the field's ultimate recovery to its recoverable reserves. Waterflooding is not feasible because of the reservoir's extremely low permeability to water; various other means of enhanced recovery were studied. Of these, miscible displacement by CO2 injection was the most attractive. When a CO2 source became available in 1970, a comprehensive CO2-flood design began. Initial Flood Design Implementation A leasing agreement was signed between Shell and Canyon Reef Carriers (CRC), operator of the SACROC CO2 pipeline, whereby up to 20 MMcf/D of that system's capacity would be made available for CO2 transport to North Cross Unit. The CO2 was to be supplied from Shell's production in the JM and East Brown Bassett gas fields. The 20 MMcf/D (93% CO2, 7% methane) was to be delivered over a 10-year period and would constitute an ultimate solvent slug of 73 Bcf (about 40% of an oil-column hydrocarbon pore volume). Shell's miscible reservoir simulator was used to try to define an optimum flood plan. The field's past production performance was history matched, and project production performance was history matched, and project predictions for several injection patterns and operating predictions for several injection patterns and operating policies were generated and compared. An inverted policies were generated and compared. An inverted nine-spot pattern was found optimal. Wells 46 and 62 were converted to CO2 injection initially, with Wells 44 and 64 to be converted after 4 years of flooding. Continuous solvent injection with recycling was planned. JPT P. 1706

Review of Bell Creek Waterflood Performance - Powder River, Montana

This case history of the Bell Creek field reviews the performance of six contiguous Muddy Sand sandstone reservoirs before and during waterflood. An edge-drive waterflood has been in progress for 5 years. Reservoir geology and properties are discussed, along with investigations of the potential for micellar-polymer flooding. potential for micellar-polymer flooding. Introduction The Bell Creek field consists of six Muddy Sand reservoirs unitized as six units. A line-drive waterflood from the west edge of each reservoir has been in operation since 1970. Oil production in Nov. 1974 was 26,000 B/D. Cumulative production to Dec. 1974 was 66.9 million bbl of oil. Tertiary recovery by a micellar process is under active consideration. process is under active consideration.The Bell Creek field is located 60 miles north of Gillette, Wyo., in Powder River and Carter Counties, Montana (see Fig. 1). The field is 15 miles long and 3 1/2 miles wide, encompassing 17,000 productive acres contuning 305 active producing and injection wells The current 26,000-BOPD rate accounts for nearly one-third of the oil production in Montana. History Bell Creek field was discovered June 4, 1967, by Exeter Drilling Co. on a farm-out from Samuel Gary. The discovery well, 33-1 Federal-McCarrel, was completed for an initial pumping potential of 230 BOPD from perforations at 4,524 to 4,537 ft. perforations at 4,524 to 4,537 ft.The Montana Oil and Gas Commission designated 40-acre spacing for Bell Creek field, which resulted in drilling and completing 405 oil wells and 10 gas wells. The average depth of a Bell Creek well is 4,500 ft. Discovery of the Bell Creek field started extensive exploration of Wyoming's Powder River Basin that led to the discovery of 30 to 40 Muddy Sand reservoirs. Geology and Reservoir Characteristics Bell Creek field is located on the northeastern flank of the Powder River Basin. The regional structure dips to the west-northwest at 100 ft/mile. Fig. 2 is a structure map of the Muddy Sand. Geologic data indicate Bell Creek field is a complex of northeast-southwest trending, offshore sand bars and deltaic sand deposits. The Bell Creek Muddy Sand reservoirs, except Unit E, are characteristic of barrier bar complexes. Unit E is a mixture of channel or deltaic deposits and sand bars. The six reservoir sand bodies and the locations of water-oil contacts and gas-oil contacts are shown in Fig. 3. The gross sand thickness within the field reaches a maximum of 30 ft, with a maximum net pay of 27 ft. Average net pay throughout the units varies from 7.4 ft in Unit E to 12.5 ft in Unit B. Fig. 4 is an isopach map of the Muddy Sand. Table 1 lists average net pay, productive acres, and bulk volume for each unit. productive acres, and bulk volume for each unit.Two distinct sand sections, Zones 1 and 2, are present in all units except Unit E. In comparing the two zones in each unit in order of magnitude, Zone 1, the upper interval, has the higher clay content and a permeability of 100 md. Zone 2 is a cleaner sand with a permeability of 1.5 darcies. Zones 1 and 2 are shown in Fig. 5. Unit E has three distinct zones that vary in permeability from 195 to 1,450 md. These three zones are very lenticular because of the complex geologic deposition. P. 1443

Down-Dip Waterflooding of an Oil Reservoir Having a Gas Cap

The presence of gas in a reservoir under waterflood can reduce the residual oil saturation significantly. A study, of the feasibility, of trapping gas ahead of a waterflood front in dipping oil reservoirs is accompanied by an investigation using numerical models to study the rate sensitivity of down-dip waterflooding oil reservoirs with gas caps. Introduction That the presence of gas in a reservoir during a waterflood can significantly reduce the residual oil saturation is well known in the oil industry. In 1922, Russell first found experimentally that waterflooding of oil reservoirs by a mixture of water and gas yielded higher oil recoveries than water or gas displacement alone. In 1973, Dandona and Morsel studied the effects that water injection rates and gas saturation have on ultimate oil recoveries for horizontal reservoir systems. Meltzer reported on additional oil recoveries obtained by waterflooding in the presence of gas in the Brookhaven oil field in Mississippi. Other investigators have also established that the presence of gas during a waterflood results in more oil recovery than when no gas is present. The purpose of this work is to study the feasibility of trapping gas ahead of a waterflood front in dipping oil reservoirs by forcing a zone of high gas saturation ahead of the waterflood front. Such a reservoir may have a sufficient quantity of gas available in a gas cap. If it does not, a high gas-saturation zone can be introduced by injecting gas into the crest of the structure. Special problems exist when a waterflood is contemplated in dipping problems exist when a waterflood is contemplated in dipping oil reservoirs with an initial gas cap. Although such a displacement involves the movement of all three fluids (gas, oil, and water), analysis can be made under certain conditions by using available theories for two-phase flow. If a zone of high gas saturation exists between the oil zone and the waterflood front, the gas-oil and watergas displacement processes can be considered separately. At the gas-oil contact, oil is being displaced by gas, while at the water-gas contact gas is displaced by water. Available theories can be used to predict each of these displacements provided the velocities of the gas-oil and the water-gas contacts are such that distinct interfaces are formed. One of the earliest methods of predicting the displacement of one fluid by another from porous media was provided by Buckley and Leverett. This method is provided by Buckley and Leverett. This method is applicable to one-dimensional flow systems only. Dietz developed a theory that is applicable to two-dimensional flow systems. He indicated that, within a range of fluid flow rates, the interface between two moving fluids in an inclined system is a plane inclined at an angle that can be predicted. Hawthorne applied the Dietz theory to derive equations that were analogous to the Buckley-Leverett equations but, unlike Buckley-Leverett, included gravitational effects perpendicular to the angle of dip. He also developed a theory for calculating the slope of a fluid interface under stable displacement conditions. The results predicted by this theory were in good agreement with the performance of a laboratory model. Wilson applied the Dietz theory to find the conditions under which stable displacement will exist when all the three phases have mobility in the reservoir system. JPT P. 1005

A Study of the Conroe Field

A study of fluid movement in the complex Conroe field indicated that gas was migrating from the Main Conroe sands to the lower-pressure Upper Cockfield sands, causing shrinkage of the Main Conroe gas-caps and loss of oil as residual saturation. Interim measures have been successful in temporarily stopping gas-cap shrinkage, and studies of long-range solutions are under way. Introduction The Conroe field is a 30-sq-mile, highly faulted structure producing from Cockfield sands that are prorated as two producing from Cockfield sands that are prorated as two separate fields. The thin Upper Cockfield sands have produced primarily as a depletion-drive gas reservoir, produced primarily as a depletion-drive gas reservoir, while the thick Main Conroe sands have produced more than 500 million bbl of oil by combination water and gas cap drive. A study of fluid movement indicated that gas was migrating from the Main Conroe sands to the lower-pressure Upper Cockfield sands, causing shrinkage of the Main Conroe gas caps and loss of oil as residual saturation. A computer model of this complex field showed that unless remedial action was taken migration would continue and future shrinkage losses could amount to more than 40 million bbl of oil. As an interim measure to alleviate the shrinkage, the Texas Railroad Commission increased the Main Conroe MER from 50,000 to 60,000 BOPD, which will slightly accelerate pressure decline and expand the remaining gas caps enough to offset the gas migration loss. A joint technical subcommittee is now studying the need for injection projects to stop permanently the migration and the need to form a field-wide permanently the migration and the need to form a field-wide unit for this purpose. Field Description The Conroe field is located 40 miles north of Houston on the upper Texas Gulf Coast. The structure is a large domal uplift, probably underlain by a deep-seated salt dome, and is highly faulted, as shown by the structure map in Fig. 1. The field produces from sands of the Cockfield formation of Eocene age at an average depth of 5,000 ft. Fig. 2 is a type electric log depicting the sandshale sequence, which is remarkably uniform across the structure. The field was discovered in 1931 and was developed rapidly on 20-acre spacing with 1, 100 wells. Essentially all the drilling took place before development of the electric log, and screened open-hole completions were made, generally through several sand members. The field currently consists of 150 leases operated by 27 companies. The Cockfield sands are prorated as two mews, as shown on the right side of Fig. 2. The Conroe field consists of six, thick, high-permeability sands that have provided 95 percent of the cumulative oil production. provided 95 percent of the cumulative oil production. For study purposes, they are designated the First through Sixth Main Conroe sands. Overlying the Main Conroe sands is the Conroe (Upper Cockfield) field. which consists of two thin, shaly sands that are primarily gas productive. productive. Production History and Reservoir Behavior Production History and Reservoir Behavior The Main Conroe sands had a thick (160-ft) original oil column, with uniform gas-oil and oil-water contacts in all sands. The original gas-cap/oil-zone volume ratio was 0.37. Cumulative oil production to Jan. 1, 1971 (the effective date of this study) was 461 million bbl. At that time, the field's assigned reservoir MER was 50,000 BOPD, produced from 600 active wells. JPT P. 813

Borregos Field Surfactant Pilot Test

A pilot test of petroleum sulfonate flooding was conducted during the mid-1960's in the Borregosfield, Kleberg County, Tex. The test was run in a heterogeneous Frio sand containing considerable montmorillonite. Oil recovery was limited by excessive fractionation of the injected petroleum sulfonate and by poor sweep efficiency. Introduction A tertiary surfactant pilot test was conducted during 1965 and 1966 in the Borregos field, Kleberg County, Tex. Results of a more recent pilot test have been published. Aqueous surfactant flooding uses a preferentially water-soluble surfactant capable of drastically reducing water-oil interfacial tensions and, therefore, of reducing capillary forces trapping discontinuous residual oil. Although success with dilute petroleum sulfonate solutions had been demonstrated in laboratory core floods, a field test was needed to define the status of the process and to identify possible problem areas. Surfactant adsorption and process sweep efficiency were two major concerns. Description of Pilot Area Zone F-4 in the Borregos field is a thin Frio sand. Structurally, the field is a broad anticline. In the pilot area (Fig. 1), the F-4 sand has a gross thickness of about 8 ft. Elevation of the top of the sand at its highest point in the pilot (Well 238) is 4,998 ft subsea. Fluid contacts were pilot (Well 238) is 4,998 ft subsea. Fluid contacts were far removed from the pilot area. The oil-water contact was at 5,089 ft subsea and the gas-oil contact was at 4,972 ft subsea. At the time pilot operations were initiated in 1965, Zone F-4 was producing by gas-cap expansion and solution-gas drive. Reservoir pressure had dropped to 2,000 psi from a discovery pressure of 2,500 psi. psi. The pilot pattern was a 1.25-acre, isolated five-spot. An existing well, Well 238, was converted to an injector and four new wells were drilled. These wells were conventionally cored with natural mud to avoid alteration of rock wettability. One-hundred-percent core recovery was obtained in Wells 411, 412, and 414. Core recovery was very low in Well 420. Hole deviations during drilling caused the down-hole pattern to be somewhat skewed. Bottom-hole locations (Fig. 2) were determined by multishot directional surveys during drilling, except for Well 238, where a cased-hole survey was performed.A pressure coring operation conducted upon termination of the surfactant flood provided additional reservoir description. Core Hole 441-1 and Deviations 441-2 and 441-3 were drilled to determine residual oil saturations. The bottom-hole locations of these postflood core holes are also shown in Fig. 2. Geologic Study A detailed environmental-facies study was undertaken to provide a geologic framework for the pilot area. The provide a geologic framework for the pilot area. The external form of the F-4 sand is a tabular sheet; internally, it consists of a number of elongated, individual channel deposits that coalesce and cross one another. Each channel consists of an impermeable basal clay-clast bed, fine-to medium-grain sandstone, and another impermeable bed of siltstone. Channel-to-channel communication occurs through the sides of the channels and across erosional boundaries. The clay minerals are chiefly montmorillonite. Matrix (less than 0.03 mm) clay content is unusually high, averaging 8.5 weight percent. Porosity and permeability are also influenced by local zones of calcite cementation. Calcite cement was most prevalent in Well 414 and, to a somewhat lesser extent, in Well 412. JPT P. 695

Methods for Determining Residual Oil with Pulsed Neutron Capture Logs

The special techniques described here appear to be promising for determining precise quantitative residual oil saturations - under certain reservoir conditions. A field test of one method was encouraging. The PNC logs showed saturations that agreed with other measurements, and the degree of uncertainty in the estimates approached theoretical expectations. Purpose and Scope The basic physical principles of pulsed neutron capture (PNC) logging and descriptions of logging instrumentation and operation have been documented in earlier publications.3,4 In addition, several methods of PNC data interpretation for petroleum engineering applications have appeared in the literature.6 These latter reports demonstrate that PNC logging has become a valuable technique for formation evaluation. The most significant use of PNC logging has been to discriminate among gas-bearing, oil-bearing, and salt-water-bearing formations in cased holes. For example, gas-oil, gas-water, and oil-water contacts have been found and followed. Unsuspected hydrocarbon migration between zones also has been detected. In addition, water saturations have been calculated from PNC log data when porosity, rock type, formation hydrocarbon type, and formation water salinity were known or could be estimated. Interpretations of PNC log data are often precise enough for decisions regarding recompletion or for a qualitative assessment of reservoir mechanism and performance. But how useful are these data when we must decide whether or not to conduct a tertiary recovery project in the flooded-out portion of a reservoir? In comparison with waterflooding, tertiary recovery is more complicated; thus its performance is harder to predict. Also, the process costs are higher, so there is much less margin for error. Therefore, many of the parameters must be measured with great accuracy for designing a tertiary recovery project. One of the most important parameters is the residual oil saturation - the target for profit. A decision to undertake a tertiary recovery project could depend entirely on the estimate of residual oil saturation and the margin of error associated with the estimate. Minimum expected errors in oil saturation and saturation distribution (among other parameters) are essential for a tertiary recovery project. The purpose of this paper is to describe in some detail the possibility of using PNC data to estimate more precisely the residual oil saturation remaining at the end of a waterflood (either natural or induced).

The quasistationary one-dim ensional motion of aerated oil and gas

The problem of the one-dimensional motion of aerated oil and gas arose in connection with the design of a development of the Samotlorsk oilfield, level A of which is a single massive stratum with a gas cap in the upper part and ground water in the underlying part. It is assumed that the area of the field is covered with a network of wells at a given spacing. The well filters are located arbitrarily in a single area which is called the plane of oil sampling. The position of the gas-oil contact and the water-oil contact are considered as functions of the time in the sampling plane in order to determine the depletion of the stock of oil and also to locate the sampling plane most advantageously in depth.

Propane-Gas-Water Miscible Floods In Watered-Out Areas of the Adena Field, Colorado

Results of the field tests described here showed that within the contacted pore volume the injected propane mobilized essentially all the oil left pore volume the injected propane mobilized essentially all the oil left behind by the waterflood. This residual oil was recovered profitably in the ratio of more than two barrels of reservoir oil for each barrel of propane. Introduction The Adena reservoir (Fig. 1), Colorado's second largest field and the largest in the Denver-Julesburg basin, was produced by gas-cap expansion, solution-gas drive, and waterflooding. The waterflood was conducted early in the primary life of the field by injecting water into wells just above the gas-oil contact in a line drive pattern (see Fig. 1). Details of this flood are given by Weyler and Sayre. The important reservoir, rock, and fluid properties for the Adena reservoir are listed here in Table 1. Although the waterflood-pressure maintenance program had been highly successful in recovering oil program had been highly successful in recovering oil from the Adena reservoir, it was estimated that half the original oil in place would remain when the economic limit of the waterflood was reached. A literature search and laboratory study of tertiary recovery methods were made to determine the one process best suited to recover additional oil at the reservoir conditions that were found at the time of the study - 1961. Solubility data for propane, methane, and recombined Adena reservoir oil showed that miscible displacement of the oil by propane and gas could be achieved at pressures above 1,000 psi at reservoir temperature (180 degrees F). The mobility ratio in the reservoir between oil and propane was calculated to be 6.4, and that between propane and gas was 4. Miscible floods conducted in 8-ft-long Berea sandstone cores at these conditions recovered more than 90 percent of the oil left after a waterflood. A detailed economic study of such a tertiary recovery program indicated that with propane available at 4.5 cents gal, the profitability prospects of the program warranted pilot testing of the miscible displacement process. Two separate field tests of the propane-gas-water process. Two separate field tests of the propane-gas-water recovery process were conducted from 1962 to 1965. This paper presents the results of those tests. paper presents the results of those tests. Clar A Test Fig. 2 shows the portion of the Adena reservoir in which the first pilot test of the propane-gas miscible flood was conducted. Table 2 gives pertinent reservoir properties for this area. The waterflood front had moved past the Clar A lease and Clar A-5 had been shut in; Clar A-2 was expected to be watered out and shut in when the test flood started. A potentiometric model study of the proposed potentiometric model study of the proposed propane-gas-water flood was made to determine the propane-gas-water flood was made to determine the total pore volume that would be swept by a 5 percent PV slug of propane followed by alternate gas and water PV slug of propane followed by alternate gas and water injection (see Fig, 2). The model study showed that to achieve the swept areas shown in this figure, it would be necessary to reduce injection of water into Injection Wells W-17, W-18, W-19, W-20, and W-44 from about 1,000 B,/D each to the rates shown, The cross-hatched area in Fig. 2, denoted as 1, was the area expected to be contacted at the time of propane breakthrough in Clar A-2; Area II is the additional area to be contacted by propane at the time of breakthrough in the second location, Crone 1. (Also see Table 2.) JPT P. 1264

The Northwest Avard Pressure Maintenance Project

Given an honest explanation of the unique problems involved in producing the gas cap of this combination reservoir, the working interest owners, the gas purchasers, and the royalty owners all rose to the challenge, voluntarily agreeing to restrict sales until a unit could be formed. The fruits of their cooperation amount to an estimated 3 million barrels of additional oil. Introduction and Geology The Northwest Avard Hunton limestone reservoir lies approximately 10 miles west of the town of Alva, Woods County, Okla. Fig. 1 is a structure map of the top of the Hunton in the field. First Hunton production in the general area was established in March, production in the general area was established in March, 1967, in Section 23, T27N-Rl5W. Later development has proved this well to be geologically separated proved this well to be geologically separated from the unit area. A gas well in Section 16, completed in May, 1967, was the first producer from the eventual unit. The first oil production was in July, 1967, from Section 21. A total of nine oil wells and three gas wells was completed in the unit area. The average depth to the Hunton is approximately 6,200 ft. The Hunton reservoir producing in the Northwest Avard field is correlative with the Silurian Chimney Hill section in other areas where the entire Hunton group is present. This area of the Anadarko basin contains the extreme northern edge of the Hunton formation, which is truncated against the unconformity immediately overlying it. The accumulation of oil and gas in this field is associated with a stratigraphic trap characterized by truncation of the total Hunton zone in all directions except to the south where a water table is present. General dip of the Hunton is approximately 80 ft/mile to the south. (See Fig. 1.) The eastern and western limits of the reservoir are fairly well defined by dry holes or thin Hunton intervals. These limits were possibly formed by erosional channels, or drainage streams, during the time of the unconformity. The reservoir's northern limit appears by the unconformity to be defined by either a cross-drainage stream or complete Hunton erosion. Pressure surveys show a definite separation between the Hunton outlier in Sections 7 and 8 and the main reservoir. Electric logs of Unit Well 5–3 indicated the water-oil contact at a subsea elevation of −4,694 ft. The size of the aquifer is indicated by water recovery on DST's of correlative Hunton zones in dry holes from 3 to 10 miles from the field. A gas-oil contact at a subsea elevation of −4,633 ft was established by well completion data and by early performance history of some of the oil wells. Unit Well 4–1 originally produced with a high GOR until extremely high produced with a high GOR until extremely high withdrawal rates from the gas cap caused upward movement of the gas-oil contact. Subsequently, the GOR in this well fell from approximately 2,200 to 525 cu ft/bbl. A similar but less pronounced drop in GOR was exhibited by Well 5–1. Reservoir Characteristics Fig. 2 is an isopachous map of the gross Hunton zone. Most of the better porosity results from dolomitization of the original limestone. Intervals of porosity in excess of 20 percent occur randomly in porosity in excess of 20 percent occur randomly in the section, along with intervals as low as 2 percent. Core analysis indicates good permeability, even in the lower porosity ranges. P. 1074

Numerical Coning Applications

Abstract An analysis of water or gas coning behaviour is particularly important in determining the future performance of gas reservoirs and thick oil reservoirs of the Rainbow-Zama- Virgo types. Investigations of coning in these reservoirs have only recently become practical. This paper describes results from two numerical coning studies - one a gas-water problem, the other a three-phase problem in a Virgo reef. The implicit numerical model used is described in detail. INTRODUCTION THE CONTROL OF GAS AND WATER CONING in petroleum reservoirs is essential in optimizing recovery and minimizing operational costs. Coning is the result of high-pressure gradients around the producing well which cause the oil-water contact to rise and the gasoil contact to depress near the wellbore. Gravitational forces tend to segregate the fluids according to their densities. However, when gravitational forces are exceeded by the flowing pressure, a cone of water and/ or gas will penetrate the producing interval. Only recently has it become practical to investigate coning as a non-steady-state flow phenomenon with heterogeneous reservoir properties. These investigations are now practical utilizing numerical coning models. Coning is simulated with a 2D radial (R – Z) grid system extending out from the wellbore to some external radius (Re). To obtain proper definition of the gas and water cones, a fine grid is used near the wellbore. The pore volumes of these interior grid blocks are typically 1 to 10 barrels, At a normal producing rate and with a reasonable time-step size, the fluid throughput per time step of the inner blocks is many times the pore volume of the blocks. This high throughput causes large saturation changes per time step and, in the past, these large saturation changes have caused model instabilities. Normally, in a reservoir simulator the transmissibilities governing flow between blocks and the production rates of oil, gas and water are calculated explicitly using the saturation conditions existing at the beginning of the time step. If explicit transmissibilities and production terms are used in a coning model, a practical time-step size will cause the predicted saturations to become unstable and the GOR's and WOR's to oscillate, These instabilities can be controlled by treating the transmissibilities and production terms implicitly rather than excplicity. The computation required per time step increases with a totally implicit model, but the resulting increase in the time-step size which can be taken more than offsets the greater computation requirements. The net result is a numerical model which can be used routinely, at low cost, on practical problems. The Appendix describes in detail the mathematics of this coning model. The following section describes two coning studies. The first case is a gas pool with an underlying aquifer. The second is a single-well bioherm reef being produced under primary depletion. Initially, it is without a gas cap, but it does have a small underlying aq Uifer, Both studies used a fully compressible threephase 2D radial model.

Reservoir Barrier and Polymer Waterflood, Northeast Hallsville Crane Unit

As a result of field-wide polymer injection, recovery in this unit exceeded by 40 percent the estimated recovery for an ordinary waterflood, and at an average cost of just 33 cents per barrel. Introduction The Northeast Hallsville Crane unit operated by Hunt Oil Co. was one of the first field-wide applications of a polymer flood. Since this field is well along in the final stages of be flood project, it has been possible to look at the effects of polymer injection and draw some conclusions about the use of these chemicals. The original purpose of polymer use in this project was to create a viscous barrier between the oil zone and a large associated gas cap. However, flood response from nearby producers as a result of the barrier placement was encouraging enough to extend the use of polymers to the central area of the oil zone, where early water breakthrough had been experienced. Early results from these attempts at using polymers to improve waterflood recovery were favorable. Ultimately a total of 313,000 lb of polymer was injected into 10 of the 15 unit injectors. Polymer injection into the Northeast Hallsville Crane unit generally has been both technically and economically successful. Certainly, the effectiveness of the reservoir barrier has been well established. As for improvement of oil recoveries by mobility control, it was found that higher polymer amounts resulted in higher oil recoveries over the range of polymer treatments used. Substantially better results were achieved in areas where there was no water injection prior to the polymer slug injection. prior to the polymer slug injection. Development History The Northeast Hallsville Crane unit is about 3 miles northwest of the town of Marshall in Harrison County, Tex. Unit production is from the Crane zone of the middle Pettit formation, a thin oolitic limestone pay at a depth of about 6,900 ft. The map in Fig. 1 pay at a depth of about 6,900 ft. The map in Fig. 1 shows the location and areal extent of the Crane porosity development and its relation to the large porosity development and its relation to the large associated Woodlawn gas field. The Crane pay in this area was first discovered in 1950 as a gas producing reservoir in the Woodlawn portion of the field. Oil production was established portion of the field. Oil production was established in the Northeast Hallsville field in 1956 as the reservoir was developed to the west. Reservoir lists had been essentially defined by early 1960 after 42 wells had been drilled. Primary oil production peaked in March, 1959, at 42,500 bbl/month. Early withdrawals from the gas zone had caused migration of oil into the gas cap by the time of the oil zone development. As a result, the gas-oil contact was not found as a clearly defined structural level but was established as a broad transition zone between approximately 6,300 and 6,400 ft subsea. The extreme volatility of the crude oil also contributed to the lack of a clearly defined gas-oil contact. JPT P. 1130