20-acre Spacing Research Articles

Interference Testing to Characterize the Injection Behaviour of a 20-Acre Pattern in the Court Field

Abstract In the Court Field, the middle Bakken Sand Pool has been operated as a heavy oil waterflood for over 15 years. However, unrecovered oil volumes in the pool remain attractive for improved recovery schemes. Recently, the Court Middle Bakken Reservoir model was updated to evaluate the potential for downspacing and waterflood optimization of the reservoir. The potential for 20-acre downspacing for both infill drilling and additional water injection was identified by this study. As part of the additional development program, an injector producer well pair was drilled to create a new injection pattern with reduced inter-well spacing. Reservoir pressures, water saturation and effective permeability to water in the pattern were determined by RFT and log data. Pattern characterization was complemented by an interference test, including all the wells in the pattern. Analytical and numerical tools were used in the test design. The most comprehensive results were obtained by local grid refinement of the pattern area in the full field simulation model. Unavoidable interference with a neighboring pattern during the test was predicted. In order to account for this effect, it was decided to run the test with the new injector active intermittently. The complete test design and analysis of the results are described. In addition, a comparison of pressure measurements by downhole gauge and acoustic well sounder are presented. Introduction The Court Field, located in west central Saskatchewan, produces 17 ºAPI heavy crude from the Middle Bakken Formation, using vertical wells and a waterflood recovery scheme. The Court Bakken Sand was discovered in November 1981. The Court Bakken Sand Voluntary Unit No. 1 was formed in 1988 and waterflood commenced with only 2% of OOIP produced. There are 39 producing oil wells and 21 water injection wells currently in operation within the main pool. The current recovery factor is approximately 20%, with some wells producing up to 30m3/d oil. Recently, Majcher et al.(1) presented a geological and engineering overview of the reservoir. The Middle Bakken Formation was deposited as NE-SW trending sand ridges. The pool has undergone significant collapse of the Torquay Formation with the subsequent creation of extensive post-depositional sinkholes within the Bakken. This structural deformation interrupts the lateral continuity of the sand ridge and its characterization is the most challenging to further field development and effective waterflood management. Another important Bakken heterogeneity is the change in well log signature that represents the variation in facies at the ridge edges(2). This facies distribution within the Middle Bakken correlates with the waterflood response. Majcher et al.(1) identified the potential for infill drilling of producers and injectors near the edges of the pool. An injector-producer pair was recently drilled in Section 36-033-28W3M on 20-acre spacing. An interference test with four wells was conducted to investigate how the heterogeneities described above affect the waterflood performance of the newly configured pattern.

Microseismic Fracture Mapping Optimizes Development of Low-Permeability Sands

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 95637, "Microseismic Fracture Mapping Optimizes Development of Low-Permeability Sands of the Williams Fork Formation in the Piceance Basin," by S.L. Wolhart, SPE, Pinnacle Technologies; C.E. Odegard, SPE, Williams Production; and N.R. Warpinski, SPE, C.K. Waltman, SPE, and S.R. Machovoe, SPE, Pinnacle Technologies, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October. A study was made to improve hydraulic fracturing and field development in the Williams Fork formation, Piceance basin, Colorado. Wells in this formation usually are stimulated in multiple stages by use of limited-entry techniques. Microseismic imaging was used to assess well downspacing and to assist stimulation optimization. Introduction Microseismic mapping was performed on a four-well project during the winter of 2001–02. The mapping improved the understanding of well placement and fracture optimization for a large pilot project evaluating 10-acre well spacing in the field. The goals of the mapping were to determine fracture orientation and dimensions (height and half-length) as well as the treatment distribution in these fields. Background As shown in Fig. 1, the Williams Fork formation is part of the Mesaverde group and consists of many stacked low-permeability sandstones. Gross formation thickness can exceed 2,000 ft. These low-permeability sandstones have porosities ranging from 6 to 14% and matrix permeability ranging from 0.1 to 5.0 µd. All intervals are naturally fractured to some extent, and effective permeability is 10 to 50 µd. Natural fractures terminate at lithologic boundaries and do not connect layers vertically. Layers are limited in lateral extent, and there is little or no correlation of intervals between wells even with reduced well spacing. Gas in place averages 40 to 100 Bcf per 640-acre section. Estimated ultimate recovery is 1.3 to 1.7 Bcf/well in core areas. The recovery factor for wells on 20-acre spacing is approximately 40%, and for 40-acre spacing it is approximately 20%. At the time of this testing, the fields were developed primarily on 20- to 40- acre well spacing. Stimulation Practices Hydraulic fracturing is required to sustain commercial production from these low-permeability reservoirs. Fracture treatments usually are in multiple stages with limited-entry procedures. Each fracture stage targets three to six sands. Early treatments used crosslinked-gel fluid. Beginning in 2001, some wells were stimulated with waterfracs. Typical waterfrac designs consisted of 80,000 to 140,000 gal of slickwater plus 90,000 to 160,000 lbm of 20/40-mesh Ottawa sand pumped at 40 to 50 bbl/min. Typical gel fracture-treatment designs consisted of 60,000 to 140,000 gal of 30-lbm/1,000-gal crosslinked gel plus 300,000 to 700,000 lbm of Ottawa sand pumped at 40 bbl/min. Stages covered gross intervals of 300 to 500 ft with four to six sets of perforations. Both the waterfracs and gel fracture treatments were limited-entry designs with 18 to 20 total perforations. Average sand concentration was 1.2 lbm/gal for the waterfracs and 5.0 lbm/gal for the gel fracture treatments.

A Proposal To Improve recovery Efficiency

To substantiate our recommendations for secondary recovery by infill drilling and waterflooding, it was necessary to show that there is some relationship between spacing and ultimate recovery. This is a problem that has perplexed the industry since the problem that has perplexed the industry since the 1920's. The last serious attempt to find such a relationship was made in 1967 by the API Subcommittee on Recovery Efficiency. The 103 reservoirs analyzed by Craze and Buckley in 1945 were expanded to 312, and relationships between recovery efficiency, reservoir characteristics, and fluid characteristics were established for depletion-drive as well as water-drive reservoirs; however, a spacing/ ultimate-recovery relationship could not be determined, possibly because heterogeneity was not considered.Our recommendations for secondary recovery of oil do not involve new technology; however, they do require larger capital investments than do tertiary-recovery projects of similar size. Oil recovered by tertiary methods gets upper-tier prices because of the magnitude of the investment prices because of the magnitude of the investment required. If size of investment is the criterion used to obtain world prices, then modern infill-drilling programs more than meet this requirement. When mentioned in this paper, secondary recovery or infill drilling always means infill drilling combined with waterflooding to maintain pressures at or above saturation pressure. Such pressures at or above saturation pressure. Such infill drilling easily could result in spacing as dense as 20 acres per unit, where a unit consists of one production well and one injection well. This means that, with 20-acre spacing, there would be four times as many wells in a field as there are now with 40-acre spacing. Because one well now costs three times as much as it did in the early 1970's, requirements for receiving world prices for this method appear fully satisfied.The only methods effective for large-scale improvement of oil recovery are the secondary method of infill drilling as proposed here and the application of heat in viscous-oil reservoirs. There is at present no tertiary method ready to be used on a large scale. The CO2-WAG project in the SACROC Unit is the only CO2 project in operation on a large scale; a close look at the data on this unit causes considerable doubt about claims regarding the success of the project. project. Infill drilling, if done properly, can be used to recover at least as much oil as the U.S. already has produced. All reservoirs are heterogeneous to some produced. All reservoirs are heterogeneous to some degree i.e., not all portions of the reservoir are connected to one another. Infill drilling will permit production of oil from parts of the reservoir that production of oil from parts of the reservoir that might be bypassed by standard, low-density well spacing. Water must be injected in all portions of the reservoir simultaneously to keep the entire reservoir contents at least at, and preferably above, bubblepoint pressure. The water produced must be collected pressure. The water produced must be collected and cleaned for recirculation, and "short circuits" between injectors and producers must be located and repaired if possible. During production, some producers must be converted to injectors, and vice producers must be converted to injectors, and vice versa, depending on productive behavior in a particular portion of the reservoir. At all times, the particular portion of the reservoir. At all times, the engineer should determine the particular section of the formation into which water should be injected; the water's path from the injector to the producer should not be left up to formation permeability. For successful recovery, the number of producers should be equal to or less than the number of injectors, and the wells should be spaced on a regular pattern. Obviously, if the injection wells are widely spaced, only the most permeable channels are used. With regularly and densely spaced injectors, water will be forced into the less-permeable portions of the reservoir and will push the oil out. Openhole completions of water-injection wells never should be made, and such wells should not be fractured. If secondary recovery is carried out in this manner, operating costs will be far above normal; however, production also will be far above normal. production also will be far above normal. Although waterflooding is applicable everywhere except where heat is required to reduce oil viscosity, the most logical places to begin flooding operations are the limestone/dolomite reservoirs of New Mexico and west Texas. There are four reasons for this. p. 1164

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

Coalinga Nose Pressure Maintenance Project

A large gas injection program in this unitized field in California has improved gravity drainage, resulting in an ultimate recovery approaching half the oil in place. Deliberate water production has reduced a natural water influx that would have reduced recovery if not checked. Few "giant" oil fields can match the performance of the Coalinga Nose field. Introduction The Gatchell pool of the Coalinga Nose field provides a 34-year case history of a gravity drainage reservoir. The field is approximately 6 miles northeast of the town of Coalinga in Fresno County, Calif. After 12 years of competitive operations, the field was unitized in 1950. The most unusual feature of the Gatchell pool's production history is that since unitization, it pool's production history is that since unitization, it has been operated in a manner to maximize the gravity drainage potential and arrest natural water encroachment. Crestal gas injection was begun in 1950 and has continued to the present. A pilot waterflood was attempted but was short lived because it proved less efficient than gravity drainage. Further, large volumes of water have been produced from edge wells to prevent natural water encroachment from reducing recovery. In 1969, the gas injection was supplemented with a large-scale program of nonindigenous-gas injection. More than 58 Bcf of natural gas has been injected under this program. Cumulative oil production exceeds 425 million bbl, or 42.7 percent of the production exceeds 425 million bbl, or 42.7 percent of the original oil in place, and the current production is about 10,000 BOPD. An ultimate recovery of 470 million bbl, or 47.2 percent of the oil in place, is expected; this is an increase of 79 million bbl over the calculated primary recovery. Development History and Method Of Operation The pool was discovered with the completion of well Gatchell No. 2 (now 1-18F) on June 26, 1938. Development progressed rapidly until Dec. 1941, at which time 157 wells had been drilled. Most of the field was developed on 20-acre spacing, but some closer spacing along the east flank and the southwest area has reduced the average spacing. A total of 192 wells had been completed as of July 1, 1972. In June of that yea, 75 of those wells were active producers, 21 were used for gas injection, 15 had been abandoned, and 81 were idle. During World War II the maximum efficient production rate (MER) for the pool was set by the production rate (MER) for the pool was set by the Petroleum Administration for War (PAW). Petroleum Administration for War (PAW). Controversy between the PAW and the operators developed over what the proper production rate should be to minimize pressure decline. MER's set during this period ranged from 15,000 to 50,000 B/D. To meet period ranged from 15,000 to 50,000 B/D. To meet the wartime demand, production in excess of the MER was permitted to as high as 59,000 bbl. The MER was 30,000 B/D when the PAW was dissolved on Sept. 30, 1945. MER recommendations were made by the Conservation Committee of California Oil Producers as the successor of the PAW. From 1945 until 1953 the operators produced at rates ranging from 43,000 to 54,000 B/D. The production history for the pool is shown graphically in Fig. 1. JPT P. 1147

A Reservoir Study of the Friendswood Field

To temporarily stop migration of oil into the original gas cap, the existing gas injection project in this Texas Gulf Coast field was expanded. For the purpose, water turned out to be a more efficient displacing medium than gas. By unitizing the field and then injecting 80,000 barrels of water a day, oil migration can be stopped and 55 million more barrels of oil will be recovered. Introduction The Friendswood field (sometimes referred to as Webster) was discovered by Humble in 1937. It is located on the upper Texas Gulf Coast immediately south of Houston (Fig. 1), and has productive sands originally encompassing more than 4,100 acres. Approximately 215 wells were required to fully develop the field to 20-acre spacing. The sands are very prolific and the average well exhibits a productivity index of approximately 29 B/D per psi productivity index of approximately 29 B/D per psi drawdown. Cumulative Frio sand oil production has been 310 million bbl, and reservoir pressure has dropped only 340 psi since discovery. Principal production has been from upper Frio sands of Miocene age. Although prorated together, these sands have been divided into 17 members for reservoir control purposes. A small amount of oil (2 million bbl) has been produced from the Marginulina sands, which lie just above the Frio. The field contains several fault systems, and, because of fault juxtaposition, communication occurs between some of the sand members. Several studies, resulting in MER hearings, workover programs, and a gas injection program, have been conducted in the past. For the study discussed here, those past programs were reviewed and additional necessary programs were determined. Current fluid contacts for each sand member were ascertained on the basis of conventional neutron logs, pulsed neutron logs, induction electric logs, and well production histories. Oil and gas volumes were then production histories. Oil and gas volumes were then mapped for original and current conditions. Material balance and unsteady-state water influx calculations were used to match past reservoir behavior and to predict future performance. predict future performance. JPT P. 685

A Proven Squeeze-Cementing Technique in a Dolomite Reservoir

Data on squeezed injection wells in a Grayburg-San Andres reservoir of West Texas indicate that a high final standing pressure is not a prerequisite for a successful squeeze. Profiles made a year after repair indicate that the wells have maintained the desired injectivity profile despite continued injection at fracturing pressure. Introduction The reservoir being discussed is located in West Texas and produces from the Grayburg-San Andres dolomites of Permian age at an average depth of 3,400 ft. The formation has low porosity and permeability (average 8 percent and less than 1 md, respectively) and is vertically fractured. Gross pay thickness ranges from 100 to 400 ft. Connote water saturations approximate 40 percent. The field, discovered in the 1930's, remained small until the advent of hydraulic fracturing in the 1950's. By 1960, development on 20-acre spacing was virtually complete. Completion Practices Except in the early wells, primary completion practices consisted of setting 5 1/2-in. casing at total depth and circulating cement. Float collars were used, and in many of the wells scratchers and centralizers were put over the pay section. The common cement put over the pay section. The common cement program consisted of API Class C-HSR 4-percent gel program consisted of API Class C-HSR 4-percent gel over the pay and Class C 8-percent gel as a filler to the surface. All of the wells were hydraulically fractured with lease or refined oil on completion. All of the jobs were one stage. Volumes ranged from 5,000 to 30,000 gal at rates from 15 to 30 bbl/min down the annulus between tubing and casing. Sand concentrations varied from 1 1/2 to 4 lb/gal. Acid was spotted in the hole before fracturing commenced. The majority of the wells were perforated either with one 30- to 60-ft interval at the base of the gross pay section or "blanket" perforated over the whole zone. Some wells have 4 shots/ft over intervals as great as 300 ft. Detection of Wellbore Channeling Pilot waterflooding operations in this reservoir were Pilot waterflooding operations in this reservoir were not successful. Other than two cases of direct communication to producing wells, no effect was observed. Several sets of radioactive tracer surveys were run, all of which showed that the water was confined to the desired intervals. No channeling was detected. Detailed studies were made to review primary performance and evaluate locations for one or more additional performance and evaluate locations for one or more additional pilots. In the course of these studies it became evident pilots. In the course of these studies it became evident from a review of the production history, workover success, bottom-hole pressures, and core analyses that the wells that were initially perforated low were in communication with other portions of the pay section. Failure of primary cement jobs or connection of vertical fractures in the formation were believed to be responsible for the communication. Based on the inference of wide-scale mechanical problems from these data, temperature logs were then run on the pilot water injection wells. These surveys showed that most of the injected water was being lost into nonproductive intervals in all of the injection wells. The search was then begun for a suitable squeeze-cementing technique to confine the water to the pay zone at the wellbore in hopes that this would provide the key to successful waterflooding. Subsequent performance data have shown conclusively that the problem is at or near the injection wellbore. JPT P. 1341

Reservoir Pressure Data Used To Justify Infill Drilling in a Low Permeability Reservoir

The initial development spacing for a field may or may not be the optimum spacing, depending upon the reservoir and producing characteristics and upon the development economics of that particular field. Reservoir pressure data can be helpful in determining the best pattern. pressure data can be helpful in determining the best pattern. Introduction Engineers and conservation officials in the various oil and gas producing states have been concerned for some time with the efficient development of our oil and gas resources through optimum well spacing. Usually this concern has centered on justifying wider spacing than is authorized by the various state oil and gas regulatory agencies. Surely each reader of this paper knows of a field, or fields, where engineers, paper knows of a field, or fields, where engineers, through the presentation of sound engineering principles and data, have succeeded in obtaining wider principles and data, have succeeded in obtaining wider spacing rules to develop oil and gas reservoirs more efficiently and economically and to make maximum profits. In recent years the case for wider spacing has profits. In recent years the case for wider spacing has been recognized by most regulatory agencies; for example, in Texas in 1965, the Statewide Spacing Rule for oil wells was changed from 20 acres to 40 acres. In general, this has been a wise decision; however, it is still the responsibility of the engineer to evaluate each developing field to determine the optimum spacing for that field. The Sacatosa (San Miguel-1 sand) field, which initially was developed on 40-acre spacing, represents a case in which infill drilling on 20-acre spacing was justified by the use of reservoir pressure data. Development of the Sacatosa field has generated considerable interest, particularly in Southwest Texas, not only because of its size, but also because of the challenge it has presented to the engineering and production people to extract efficiently and economically production people to extract efficiently and economically the petroleum hydrocarbons from this shallow, low-permeability oil reservoir. Location and Geology The Sacatosa (San Miguel-1 sand) field, henceforth referred to as the Sacatosa field, is in Maverick County in Southwest Texas and is approximately 20 miles from the Rio Grande River or Mexican border (Fig. 1). Locally the field is more generally known as the Chittim field, because most of the San Miguel-1 sand, development is on Continental Oil Co.'s lease on the N.J. Chittim ranch. Fig. 2 is a structure map of the San Miguel-1 sand, which shows that the formation dip is to the southeast and varies from 140 to 200 ft/mile. Minor faulting occurs in the field with the fault traversing Sec. 42, providing closure for a small, isolated gas cap around providing closure for a small, isolated gas cap around Well 42-7. Although not shown in Fig. 2, the San Miguel-1 sand pinches out updip against the Chittim arch, thereby forming a stratigraphic trap for the accumulation of oil. The present productive limits of the Sacatosa field are defined by an oil-water contact on the east and southeast, or downdip, side of the field and by permeability and sand thickness that decrease on all other sides of the field. Geologically, the San Miguel-1 sand is generally considered a member of the Upper Taylor formation in the Gulf Series of the Cretaceous system of Mesozoic Age. P. 267

Application of an Alarm and Data Telemetering System For Production Control

Abstract An alarm and data telemetering system was installed in the 30-year-old London field, Illinois, to monitor producing operations. Basic system components includesensing devices, located at waterflood plants, produced water gathering sites, LACT units, tank batteries and lease headers,transmission equipment consisting of field transmitting stations and a telephone cable system, andbase station equipment that includes a digital computer. Alarm sensors are on-off switches installed on electrical loops terminating at field transmission stations. Each transmitting station scans 16 alarm loops and reports the status of each to the base station via an underground network of telephone cable. Oil production and waterflood plant discharge pressure are also transmitted to the base station. Rapid detection of field malfunctions is possible with the computer that is also used to accumulate and report daily and monthly production data. Improved operational efficiency afforded by alarm and data telemetering permitted application in the established, relatively old London field. Introduction An alarm and data telemetering system was incorporated into producing operations at London field, Illinois, approximately 80 miles east of St. Louis, Mo. The computerized London system was engineered to improve over-all operational efficiency. To accomplish this objective the system performs three basic functions. It monitorsoperational status of 1,200 potential problem locations,oil production through lease automatic custody transfer (LACT) units anddischarge pressure at waterflood injection plants. Installation of the alarm and data transmission facility has allowed more efficient use of field personnel since manpower is now essentially relieved of searching for problems, and is directed to the tasks of preventive maintenance and rapid correction of problems when they do occur. This application of alarm and data transmission techniques is significant because London is an older field, in the latter stages of secondary depletion. London was discovered in Oct., 1937, developed on 10- and 20-acre spacing and produced on primary until 1950 when the first waterflood pilot was initiated. Production is from formations of the Chester series, Mississippian system, which, in this area of the Illinois basin, are found at a depth of approximately 1,500 ft. Waterflood operations in the field include 319 leases that extend over an area of about 60 sq miles. Oil production from 924 pumping wells is currently sold through 64 LACT units and 87 conventional tank batteries. Produced water is gathered at 18 sites and pumped to 747 water injection wells from 14 waterflood plants. Eleven water source wells also are used to make up required water injection volumes. Currently, 165,000 bbl of fluid are being handled each day. The London alarm and data telemetering system can be divided into three basic parts: field alarm and data sensors, transmission equipment and base station equipment. All alarm and data sensors are owned and maintained by Humble Oil and Refining Co., while transmitting and base station equipment are owned and maintained by a local telephone company and leased to Humble. Alarm and Data Sensors Alarm sensors installed at London are mechanical-electrical devices that reflect only on-off conditions. Mechanically, the sensors vary depending on the application. Electrically, the sensors are switches that are closed under normal operating conditions. Alarms are indicated when the switches open. Twelve hundred points are alarmed at five basic types of installation throughout the field. JPT P. 19ˆ

Waterflood Behaviour of the Low-Gravity Wainwright Pool

Abstract This paper outlines the development and performance of the Wainwright fieldin east-central Alberta, where the Wainwright sand produces 20–22-gravity oilfrom a depth of approximately 2,100 feet. The field was the first heavy oilpool in Alberta in which pressure maintenance by waterflooding was undertaken.Although pressure maintenance has been in progress for only three years, theperformance during this period is indicative of the project's success. To forestall the adverse effects of rapid pressure decline and increasinggas-oil ratios in this solution gas drive reservoir unitization as aprerequisite to full-scale pressure maintenance was instituted. The field wasunitized as five separate units, with pressure maintenance conducted by two operators. To the end of 1965, the cumulative oil production from the field wasapproximately 8,600,000 barrels. In December, 1965, oil production was 4,560barrels per day, with pressure maintenance accounting for approximately 70 percent of this. The ultimate recovery (primary plus waterflood) for the field hasbeen estimated at 31,300,000 barrels, which is more than double the recoveryanticipated by natural depletion. Introduction The Wainwright Sand reservoir is located on the southwestern flank of theheavy oil region of east-central Alberta. This is shown in Figure 1. Thefield was the first heavy oil pool in Alberta in which pressure maintenance bywaterflooding was undertaken. The reservoir was developed on 20-acre spacing, and the unitized areas include 202 producing wells. Reservoir characteristicsare included in Table I. The reservoir has a gas cap and an aquifer. During primary depletion, itproduced principally as a solution gas drive reservoir with some gas capexpansion. This was evidenced by rapidly declining reservoir pressures andincreasing gas-oil ratios. Although some water was produced from down-dip wellsalong the southwest rim of the present producing limits, and there was anoticeable encroachment of water before unitized operations began, there was noappreciable recovery resulting from the water influx. Early in 1959, it wasobvious that the natural energy of the reservoir was going to produce only asmall fraction of the original oil-in-place.

Pilot Water Flooding in a Dolomite Reservoir, The McElroy Field

Abstract The McElroy field, discovered in 1926, is one of the major oil reservoirs of West Texas. Production is obtained from the Permian Grayburg-San Andres dolomites at an average depth of 3,000 ft. Two gas injection and four waterflood pilots have been conducted in the field. Both of the gas injection projects were unsuccessful because of high free-gas saturations in the reservoir. Three of the pilot water floods have sufficient performance histories to permit thorough evaluations. Pilot I, an inverted seven-spot installed in 1947, and Pilot II, a 20-acre five-spot installed in 1953, have proved the old, better part of the field could be successfully flooded. The best wells in these pilots have produced large volumes of oil at water-oil ratios of approximately one. This performance is thought to be more the result of gravity effects than stratification. Pilot III, two contiguous 40-acre, five-spots, was installed in late 1959 and has proved the floodability of the tight, anhydritic portion of the reservoir. Injectivity problems were encountered but were remedied by increases in pressure. Pilot IV was initiated late in 1959 to determine if the old part of the field could be flooded on wide spacing. It consists of four injection wells closing 160 acres which contain nine producers. There have been some individual well responses; however, interference between injection wells is still one to two years in the future. Introduction and History of Development The McElroy field, one of the major oil reservoirs of West Texas, is located in northeastern Crane County and west-central Upton County (see Fig. 1). It is elongated in a northwest-southeast direction with the center portion located along the Crane-Upton County line, immediately east of the city of Crane. Geologically, the field lies on the eastern edge of the Central basin platform and is situated on a roughly north-south trending asymmetric anticline with the steep limb to the east. The trap is stratigraphic as well as structural. For the most part, the productive limits are controlled by porosity and permeability development. Production is obtained from the Grayburg-San Andres dolomites of Permian age at an average depth of 3,000 ft. During the early development, three portions of the present McElroy field were classified as individual fields. First production was obtained in April, 1926, from the Church and Fields No. 1 University in the Church-Fields area in the northern portion of the field. In June, 1926, the Gulf Oil Corp. completed its J.T. McElroy No. 1 in the Gulf-McElroy area in the south-central portion of the field. In Nov., 1928, production was discovered in the McClintic area in the southern part of the field by the Duffy Investment Co. No. 1 McClintic. As development continued, the merging of these three productive areas led to their consolidation and subsequent classification as the McElroy field on March 5, 1941.Drilling in the northern and southwestern areas of the field has been mainly on 10-acre spacing. The Gulf properties, which are concentrated in the southern half of the field, have been developed mostly on 20-acre spacing. At the present time, the reservoir encompasses some 30,000 acres containing approximately 1,800 wells. JPT P. 1345ˆ

Recent Developments in Guijarral Hills Field: ABSTRACT

The Guijarral Hills field is one of several large stratigraphic oil fields on the prolific Coalinga anticline. Within and adjacent to the field five new pools have been discovered in the past 2 years, all of them stratigraphic in nature. The two most important of these new pools are the North Leda and the Bourdieu. The North Leda pool embraces 600 acres with 37 wells currently producing 6,800 barrels per day. The producing zone is in the Leda sand of lower Miocene age at an average depth of 8,750 feet. Only the westerly updip pinchout line in the gas-cap area remains undefined. The Bourdieu pool is in the Polvadero area southeast of the main Guijarral Hills pool. Production is from the Gatchell sand of middle Eocene age at depths ranging from 10,550 feet to 10,965 feet. To date, eight wells have been completed on a 20-acre spacing pattern, proving about 200 acres. Current production averages about 500 barrels per day per well under restriction. Field limits have been established only in a westerly direction although a recent test well 1½ miles north of the present limits was a failure. Neither bottom water nor edge water has been encountered to date. These two new-pool discoveries have added a substantial reserve to the Guijarral Hills field. End_of_Article - Last_Page 434------------

Recent Development at Guijarral Hills: ABSTRACT

The Guijarral Hills oil field, located on the Coalinga anticline midway between Pleasant Valley and Kettleman Hills, was discovered by the Barnsdall Oil Company on September 19, 1948. The discovery well produced from the Leda sand. Since then there have been 36 Leda sand wells completed in the field on a 20-acre spacing program. The development has demonstrated that the accumulation is stratigraphic and only the updip or northwest limit of the field has been located. At present, approximately 800 acres of Leda sand production have been proved. On April 28, 1949, a new zone was discovered by the Barnsdall Oil Company with the completion of Allison A73-34-2 in a sand in the Basal Temblor which was logged approximately 500 feet above the Leda sand. To date, 11 wells have been completed in this zone on a 20-acre spacing program. Indications are that the accumulation is stratigraphic. Approximate limits of production have been defined only on the southeast and at present about 360 acres may be considered as proved. End_of_Article - Last_Page 2062------------

St. Jacob Field, Madison County, Illinois: ABSTRACT

The St. Jacob field, on the west flank of the Southern Illinois Coal basin 23 miles east by northeast of St. Louis, Missouri, was discovered in May, 1942. Accumulated production on October 1, 1947, was 1,847,966 barrels of oil and the average production during September was 567 barrels of oil daily from 48 wells. The field is on 20-acre spacing and the productive area covers approximately 1,000 acres. The oil occurs in porous zones in the Trenton (Kimmswick or Galena) limestone formation, and the wells are completed at an average depth of 2,370 feet. The St. Jacob field comprises two distinct pools separated by a pronounced saddle and characterized by differences in oil-water contact levels, reservoir energy, volume of water, and corrosive nature of the water. The structure of the north pool is a dome-like anticline, slightly elongate east-northeast and west-southwest, and the structure of the south pool is an asymmetrical anticline with north and south elongation. Reverse or west dip of 186 feet has been established on the south anticline which is an indication of the amount of closure. The strata below the Pleistocene till or glacial drift are represented by the following sequence of beds in descending order: the Pennsylvanian series, the Upper Mississippian or Chester series, the Lower Mississippian including the St. Louis limestone, Salem limestone and Osage group, the New Albany shale, the Devonian limestone, the Silurian limestone and dolomite, the Maquoketa shale, and the Trenton (Kimmswick or Galena) limestone. End_of_Article - Last_Page 303------------

Engineering Features of the Schuler Field and Unit Operation

Abstract A summary of the reservoir engineering and related geologic data on the Schulerfield, Union County, Arkansas, is presented here in a manner intended tointerest both technical and nontechnical readers. The Cotton Valley formation and the Reynolds oolite are oil-productiveformations in the Schuler field, but the Jones sand pool, at a depth of 7500ft., developed with I46 wells on 20-acre spacing, is the reservoir of principalinterest. The Jones sand sandstone reservoir is an anticlinal trap typically gas-drive ordepletion type in performance. The core analyses from 88 per cent of the wellsdrilled, together with drilling time and electric-log data, yield an accurateestimate of the "productive" sand thickness and its areal distributionover the pool. Accurate production statistics, monthly reservoir-pressuresurveys, and bottom-hole sample analyses when correlated by the "material-balance equation" show unusually good agreement with thatprinciple. Estimates of oil initially in place made by the material-balancemethod and the sand-volume method are in good agreement at 1I6 to I20 millionbarrels. The reservoir-pressure history of the pool reflects the reaction of areservoir to production, proration and secondary-recovery practices. The cost of the extensive program of reservoir study in the Jones sand pool hasbeen estimated, in order to emphasize the value derived from such an investmentthrough better understanding of a reservoir's reaction to productionpractices. Unit operation of I40 of the I46 Jones sand wells made possible an effectiveunitized gas injection pressure-maintenance program. Reservoir-pressure declinewas arrested, natural flow was maintained, and pumping and lease equipment wereconserved. An increased ultimate recovery of 20 million barrels beyond theestimated 34 million barrels primary recovery is indicated at present. Extension of the Jones sand unit to include the undeveloped Cotton Valleyformation will permit additional recovery of otherwise uneconomic reserves ofoil through wells no longer required in the Jones sand operations. Introduction The Schuler field comprises approximately 4000 acres in and about sec. 18, T.Ig S., R. 17 W. in west central Union County, Arkansas. Three reservoirs areproductive of oil and gas: the Cotton Valley formation, the Jones sand, and theReynolds oolite section of the Smackover limestone. The Jones sand pool is themost important reservoir from an engineering viewpoint. It possesses thetraditional and somewhat classic characteristics usually associated with ananticlinal trap. Development and operations have followed the dictates ofadvanced 'engineering practices. maintenance operation now being carriedout. T.P. 1605

Geology and Development of Keokuk Pool, Seminole and Pottawatomie Counties, Oklahoma

The Keokuk pool, which is located in Seminole and Pottawatomie counties, about 10 miles north of the town of Seminole, Oklahoma, in Ts. 10 N., R. 6 E., is unique in that it was the first pool in Oklahoma to maintain reservoir pressures through voluntary restriction in the rate of production. It is located in one of the few areas where the Misener sand is of sufficient thickness to afford good reservoir conditions. The structure of the Keokuk pool is anticlinal and is faulted on the east side. This area was probably affected by at least three periods of structural adjustment, but the one which is probably the chief cause of the faulting and folding in the Keokuk pool occurred in early Pennsylvanian or late Mississippian time. From 106 wells producing from the Misener sandstone and the Hunton limestone the pool has produced 6,362,224 barrels of oil to January, 1938. This is equivalent to 60,021 barrels per well on a basis of 20-acre spacing covering practically all of the productive area. A final recovery of 8,000 barrels of oil per acre is anticipated.