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By C. S. Yust, J. W. Smith, J. R. Walsh, R. E. Simpson

This paper presents the results of a complete reservoir studv designed to determine a sound economic program for the conservation of oil and gas in the Pickton field, Hopkins County, Texas. The Pickton field produces from the Bacon Lime with all indications of the study being that production is predominately by dissolved-gas drive. Calculations of the total ultimate recovery to be expected under primary operations indicated only 16.7 per cent of the oil originally in place would be recovered. This unusually low recovery is due to the type of drive operating and the extremely high dissolved gas-oil ratio and shrinkage. Results are presented for six plans of returning gas to the reservoir, evaluated to determine (1) comparative recoveries and economics of (a) returning gas at a constant rate by supplementing Pickton gas with extraneous gas during the early portion of the operation, and (b) conventional gas-return operations without using extraneous gas, and (2) the optimum size of compressor plant for each type of pressure maintenance. The over-all economic program considers, for either type pressure maintenance operation. a gasoline plant to process the unusually rich casinghead gas. Since pressure maintenance will disturb equities, pooling of royalties is in the case of Pickton a prerequisite to conservation of oil by this type of operation, both from an economic and legal standpoint. In the event pooling of royalties cannot be achieved, the study considers a gasoline plant to operate under a modified primary production operation which will make the conservation of gas possible. INTRODUCTION The Pickton field, located in Hopkins County, Texas. was discovered in November, 1944. by the completion of Humble's C. D. Nichols 1, in the Bacon lime of the Lower Glen Rose formation, through perforations from 7,888 to 7.896 feet. The well initially produced 50.2 API gravity oil with a gas-oil ratio of 1,350 cubic feet per barrel. Subsurface samples of the reservoir fluid obtained soon after completion of the discovery well showed that the Pickton crude is unique in that it has an extremely high dissolved gas-oil ratio and is subject to very severe shrinkage. Calculations of the future behavior of the Pickton reservoir indicated that ultimate oil recovery by primary operations would be 3,269,000 barrels, representing only 16.7 per cent of the oil in place (19,577,000 stock-tank barrels), and that recovery could be substantially increased by returning the produced gas. The cumulative production of 1,382,694 barrels on November 1: 1947, amounted to 42.3 per cent of the estimated ultimate oil recovery from primary operations. The purpose of this study is to determine and evaluate the optimum program for conservation of oil and gas in the Pick-ton field, including the desirability of conducting gas-return operations and of installing a gasoline plant. LOCATION AND DESCRIPTION Pickton Field, The Pickton field, as shown in Fig. 1, is located in southwest Hopkins County, Texas, 12.5 miles southwest of the New Hope field, 2.7 miles northeast of the Coke field, 16 miles southwest of Sulphur Springs, and 8 miles northwest of Winnsboro, Texas.

Jan 1, 1949

By C. S. Yust, J. W. Smith, J. R. Walsh, R. E. Simpson

This paper presents the results of a complete reservoir studv designed to determine a sound economic program for the conservation of oil and gas in the Pickton field, Hopkins County, Texas. The Pickton field produces from the Bacon Lime with all indications of the study being that production is predominately by dissolved-gas drive. Calculations of the total ultimate recovery to be expected under primary operations indicated only 16.7 per cent of the oil originally in place would be recovered. This unusually low recovery is due to the type of drive operating and the extremely high dissolved gas-oil ratio and shrinkage. Results are presented for six plans of returning gas to the reservoir, evaluated to determine (1) comparative recoveries and economics of (a) returning gas at a constant rate by supplementing Pickton gas with extraneous gas during the early portion of the operation, and (b) conventional gas-return operations without using extraneous gas, and (2) the optimum size of compressor plant for each type of pressure maintenance. The over-all economic program considers, for either type pressure maintenance operation. a gasoline plant to process the unusually rich casinghead gas. Since pressure maintenance will disturb equities, pooling of royalties is in the case of Pickton a prerequisite to conservation of oil by this type of operation, both from an economic and legal standpoint. In the event pooling of royalties cannot be achieved, the study considers a gasoline plant to operate under a modified primary production operation which will make the conservation of gas possible. INTRODUCTION The Pickton field, located in Hopkins County, Texas. was discovered in November, 1944. by the completion of Humble's C. D. Nichols 1, in the Bacon lime of the Lower Glen Rose formation, through perforations from 7,888 to 7.896 feet. The well initially produced 50.2 API gravity oil with a gas-oil ratio of 1,350 cubic feet per barrel. Subsurface samples of the reservoir fluid obtained soon after completion of the discovery well showed that the Pickton crude is unique in that it has an extremely high dissolved gas-oil ratio and is subject to very severe shrinkage. Calculations of the future behavior of the Pickton reservoir indicated that ultimate oil recovery by primary operations would be 3,269,000 barrels, representing only 16.7 per cent of the oil in place (19,577,000 stock-tank barrels), and that recovery could be substantially increased by returning the produced gas. The cumulative production of 1,382,694 barrels on November 1: 1947, amounted to 42.3 per cent of the estimated ultimate oil recovery from primary operations. The purpose of this study is to determine and evaluate the optimum program for conservation of oil and gas in the Pick-ton field, including the desirability of conducting gas-return operations and of installing a gasoline plant. LOCATION AND DESCRIPTION Pickton Field, The Pickton field, as shown in Fig. 1, is located in southwest Hopkins County, Texas, 12.5 miles southwest of the New Hope field, 2.7 miles northeast of the Coke field, 16 miles southwest of Sulphur Springs, and 8 miles northwest of Winnsboro, Texas.

Jan 1, 1949

By E. A. Swedenborg

The unit agreement for the Wertz Dome field, Wyoming, was approved by the Acting Secretary of the United States Department of the Interior on November 4, 1937, effective on December 1, 1937. The stated objectives of the agreement are to conserve and put to beneficial use all oil and gas produced; to make possible a uniform withdrawal of oil and gas in order to maintain equalized reservoir pressures; to provide for an orderly determination of the structural features of the productive horizons; and to permit the injection of gas for pressure maintenance. The purpose of this paper is to show by a discussion of the problems involved and the engineering practices employed by the unit operator, how well the objectives of the unit agreement have been accomplished in the development and production of oil and gas from the field. HISTORY AND DEVELOPMENT The Wertz Dome oil and gas field is located 88 miles southwest of Casper and 38 miles north and westerly from Rawlins, Wyoming. It is served by a state secondary oiled road connecting with U. S. Highway No. 220 at Lamont, a distance of 3 miles from the field. It has been a producing field for 27 years, first as an important producer of gas and more recently of oil. The Producers and Refiners Corp. completed Well No. 1, NE1/4SW1/4 sec. 7, T. 26 N., R. 89 W., the first productive well in the field, in September. 1921, in the Muddy sandstone of Upper Cretaceous age, at a depth of 3435 feet for an initial production of 42,000,000 cu. ft. of gas per day. In 1922 pipe lines were laid to Casper, Wyoming, for supplying fuel to the Standard of Indiana refinery, 'the adjoining town of Mills. and the Producers and Refiners Corp. pump station No. 6 in Mills; and to Parco (now Sinclair), Wyoming, for supplying that refinery with fuel. The gasoline content of the gas was extracted in an absorption plant located near the town of Mills. No compressors were used as the line pressure was sufficiently high to flow the gas through the absorbers. As high as 30,000,000 cu. ft. of gas per day were treated in the plant extracting 6000 gallons of gasoline. In September 1937, the pipe line was discontinued and the plant was dismantled at which time 61,000,000,000 cu. ft. of gas had been produced from the seven Muddy, Cloverly, and Sundance gas wells drilled in the field. Of this volume of gas 800,000,000 cu. ft. were produced from the Frontier formation, 34,200,000,000 cu. ft. from the Muddy sandstone, 24,000,000,000 cu. ft. from the Cloverly, locally called Dakota, and 2,000,000,000 cu. ft. from the Sundance formation. The pipe line was discontinued because of the near depletion of the gas reserves in Wertz and nearby fields, and hecause of the local field requirements demanding the retention of the remaining gas reserves. In December 1936, the Sinclair Wyoming Oil Co. completed Well No. 10, SE1/4NW1/4 sec. 7. T. 26 N., R. 89 W., at a depth of 5886 feet. as the first Tensleep sand producer with an intial of 1700 barrels of oil per day. The well was originally drilled only 14 feet into the sand and in August 1939 was deepened to a depth of 6161 feet, 289 feet in the sand, and the daily produe tion increased to 8350 barrels of oil. In February 1948 Well No. 22, SE1/4 SE1/4 sec. 1. T. 26 N., R. 90 W., was deepened from the Tensleep to the Basal Amsden sand and completed at a depth of 6635 feet for an intial of 600 barrels of oil per day in the Basal Amsden. In April 1948, Well No. 2. SW1/4 NE1/4 sec. 1, T. 26 N., R. 90 W.. was deepened from the Tensleep to the Madison limestone and was completed at a depth of 7193 feet for an intial of 1145 barrels of oil per day in the Madison. Well No. 26, SE1/4SE1/4 sec. 1, T. 26 N.. R. 90 W., was deepened from the Ten-sleep to the Cambrian and in October 1948 it was completed in the Cambrian for an intial of 277 barrels of oil per day. GEOLOGY AND PRODUCTIVE ACREAGE The surface is Steele shale of Upper Cretaceous age, covered in part by gravel beds. The topography of the field is that of a rolling hill with a steep draw or gulch along the northern edge of the field. The Steele shale lies conformably on the lower formations as

Jan 1, 1949

By E. A. Swedenborg

The unit agreement for the Wertz Dome field, Wyoming, was approved by the Acting Secretary of the United States Department of the Interior on November 4, 1937, effective on December 1, 1937. The stated objectives of the agreement are to conserve and put to beneficial use all oil and gas produced; to make possible a uniform withdrawal of oil and gas in order to maintain equalized reservoir pressures; to provide for an orderly determination of the structural features of the productive horizons; and to permit the injection of gas for pressure maintenance. The purpose of this paper is to show by a discussion of the problems involved and the engineering practices employed by the unit operator, how well the objectives of the unit agreement have been accomplished in the development and production of oil and gas from the field. HISTORY AND DEVELOPMENT The Wertz Dome oil and gas field is located 88 miles southwest of Casper and 38 miles north and westerly from Rawlins, Wyoming. It is served by a state secondary oiled road connecting with U. S. Highway No. 220 at Lamont, a distance of 3 miles from the field. It has been a producing field for 27 years, first as an important producer of gas and more recently of oil. The Producers and Refiners Corp. completed Well No. 1, NE1/4SW1/4 sec. 7, T. 26 N., R. 89 W., the first productive well in the field, in September. 1921, in the Muddy sandstone of Upper Cretaceous age, at a depth of 3435 feet for an initial production of 42,000,000 cu. ft. of gas per day. In 1922 pipe lines were laid to Casper, Wyoming, for supplying fuel to the Standard of Indiana refinery, 'the adjoining town of Mills. and the Producers and Refiners Corp. pump station No. 6 in Mills; and to Parco (now Sinclair), Wyoming, for supplying that refinery with fuel. The gasoline content of the gas was extracted in an absorption plant located near the town of Mills. No compressors were used as the line pressure was sufficiently high to flow the gas through the absorbers. As high as 30,000,000 cu. ft. of gas per day were treated in the plant extracting 6000 gallons of gasoline. In September 1937, the pipe line was discontinued and the plant was dismantled at which time 61,000,000,000 cu. ft. of gas had been produced from the seven Muddy, Cloverly, and Sundance gas wells drilled in the field. Of this volume of gas 800,000,000 cu. ft. were produced from the Frontier formation, 34,200,000,000 cu. ft. from the Muddy sandstone, 24,000,000,000 cu. ft. from the Cloverly, locally called Dakota, and 2,000,000,000 cu. ft. from the Sundance formation. The pipe line was discontinued because of the near depletion of the gas reserves in Wertz and nearby fields, and hecause of the local field requirements demanding the retention of the remaining gas reserves. In December 1936, the Sinclair Wyoming Oil Co. completed Well No. 10, SE1/4NW1/4 sec. 7. T. 26 N., R. 89 W., at a depth of 5886 feet. as the first Tensleep sand producer with an intial of 1700 barrels of oil per day. The well was originally drilled only 14 feet into the sand and in August 1939 was deepened to a depth of 6161 feet, 289 feet in the sand, and the daily produe tion increased to 8350 barrels of oil. In February 1948 Well No. 22, SE1/4 SE1/4 sec. 1. T. 26 N., R. 90 W., was deepened from the Tensleep to the Basal Amsden sand and completed at a depth of 6635 feet for an intial of 600 barrels of oil per day in the Basal Amsden. In April 1948, Well No. 2. SW1/4 NE1/4 sec. 1, T. 26 N., R. 90 W.. was deepened from the Tensleep to the Madison limestone and was completed at a depth of 7193 feet for an intial of 1145 barrels of oil per day in the Madison. Well No. 26, SE1/4SE1/4 sec. 1, T. 26 N.. R. 90 W., was deepened from the Ten-sleep to the Cambrian and in October 1948 it was completed in the Cambrian for an intial of 277 barrels of oil per day. GEOLOGY AND PRODUCTIVE ACREAGE The surface is Steele shale of Upper Cretaceous age, covered in part by gravel beds. The topography of the field is that of a rolling hill with a steep draw or gulch along the northern edge of the field. The Steele shale lies conformably on the lower formations as

Jan 1, 1949

By E. P. Burtchaell

A method is presented for evaluating the effect of gravity drive upon the reservoir performance of a high relief pool. Conventional forms of reservoir analysis do not consider the alterations in the basic material balance data caused by gravity segregation of reservoir fluids. A procedure is outlined for structurally weighting physical and chemical data for use in the material balance equation. It is demonstrated how actual pool performance data can be utilized to evaluate the future reservoir performance of a gravity drive pool. INTRODUCTION Conventional reservoir engineering. procedure is inadequate for the analysis of an oil pool which has considerable structural relief, steep dips, and good permeability development. In, pools of this type, gravity drainage has an important part in the movement of oil to the wells and the effects of gravity on the overall pool performance should be included in any analysis of reservoir behavior. Many engineers have the opinion that the force of gravity in the movement of oil is not important until the later life of a pool.' Probably the basis for this belief is that gravitational effects may not be readily discernible until a pool is nearing depletion. This would be especially true for pools not having a high degree of structural relief and permeability development. Actually the effects of gravitational forces are at a maximum when the pool pressure is high, for during this period the hydrostatic head of the oil column is at a maximum and the viscosity of the oil is at a minimum. Oil recoveries from pools having favorable gravity drive characteristics may equal or even exceed recoveries which might be expected from water displacement. Field evidence indicates that in some reservoirs gravity drive has resulted in recoveries greater than that which could have been expected from gas expansion or water drive.'.3 Unfortunately, the possible effects of gravity drive on pool performance have been underestimated and other reasons have been sought to explain the high recoveries obtained. There are unquestionably many reservoirs to which the principles of gravity drainage can be effectively applied. It is the purpose of this paper to illustrate one method whereby gravity drive is included in the reservoir analysis of an oil pool. A hypothetical pool, typical of many California reservoirs, is used as an example. As used in this paper, "gravity drive" is defined as the overall effect of gravitational influences on the recovery of petroleum from the reservoir; "gravitational segregation" as the gravity separation of oil and gas within the reservoir; and "gravity drainage" as the downward movement of oil as caused by the force of gravity. SAND VOLUME DATA Fig. 1 presents a structural contour map of the pool under study. Maximum closure is 1950 feet with dips on the south flank approaching 45". The original gas-oil interface was set at -5200 feet. Average thickness of the producing sand was 200 feet. For use in subsequent calculations ill this paper, the pool was subdivided into 100-foot vertical increments and the sand-volume content of each increment was obtained. If the gross sand thickness is small, under 100 feet, the sand-volume content can be obtained by superimposing an isopachous map upon a structural contour map and planimetering the average thickness of each 100-foot increment. For sand thicknesses over 100 feet, one approacli would be to construct a sufficient number of cross-sections of the pool from which the weighted sand-volume of each 100-foot increment could be obtained. Variations in the sand body with depth, as determined by core data, can also be included in the above process. Table I presents a summary of sand-volume calculations, core data, and the original distribution of reservoir hydrocarbons in the pool. Fig. 2 illustrates the structural distribution of the sand-volume content. A total of 171,398 acre-feet is contained within the productive limits of the pool. Assuming an average porosity of 25% and an interstitial water content of 20%, the original hydrocarbon content was computed to be 227,075,000 barrels. DEPTH-PRESSURE DATA The determination of the initial vertical pressure arrangement in the pool is necessary for PVT and material balance calculations. Whenever sufficient data are available, a plot of pressure versus subsea depth of measurement should be made. From this plot a representative fluid pressure gradient can be established. Lacking sufficient initial pressure data, an initial pressure gradient may he estimated or calculated from avail-

Jan 1, 1949

By E. P. Burtchaell

A method is presented for evaluating the effect of gravity drive upon the reservoir performance of a high relief pool. Conventional forms of reservoir analysis do not consider the alterations in the basic material balance data caused by gravity segregation of reservoir fluids. A procedure is outlined for structurally weighting physical and chemical data for use in the material balance equation. It is demonstrated how actual pool performance data can be utilized to evaluate the future reservoir performance of a gravity drive pool. INTRODUCTION Conventional reservoir engineering. procedure is inadequate for the analysis of an oil pool which has considerable structural relief, steep dips, and good permeability development. In, pools of this type, gravity drainage has an important part in the movement of oil to the wells and the effects of gravity on the overall pool performance should be included in any analysis of reservoir behavior. Many engineers have the opinion that the force of gravity in the movement of oil is not important until the later life of a pool.' Probably the basis for this belief is that gravitational effects may not be readily discernible until a pool is nearing depletion. This would be especially true for pools not having a high degree of structural relief and permeability development. Actually the effects of gravitational forces are at a maximum when the pool pressure is high, for during this period the hydrostatic head of the oil column is at a maximum and the viscosity of the oil is at a minimum. Oil recoveries from pools having favorable gravity drive characteristics may equal or even exceed recoveries which might be expected from water displacement. Field evidence indicates that in some reservoirs gravity drive has resulted in recoveries greater than that which could have been expected from gas expansion or water drive.'.3 Unfortunately, the possible effects of gravity drive on pool performance have been underestimated and other reasons have been sought to explain the high recoveries obtained. There are unquestionably many reservoirs to which the principles of gravity drainage can be effectively applied. It is the purpose of this paper to illustrate one method whereby gravity drive is included in the reservoir analysis of an oil pool. A hypothetical pool, typical of many California reservoirs, is used as an example. As used in this paper, "gravity drive" is defined as the overall effect of gravitational influences on the recovery of petroleum from the reservoir; "gravitational segregation" as the gravity separation of oil and gas within the reservoir; and "gravity drainage" as the downward movement of oil as caused by the force of gravity. SAND VOLUME DATA Fig. 1 presents a structural contour map of the pool under study. Maximum closure is 1950 feet with dips on the south flank approaching 45". The original gas-oil interface was set at -5200 feet. Average thickness of the producing sand was 200 feet. For use in subsequent calculations ill this paper, the pool was subdivided into 100-foot vertical increments and the sand-volume content of each increment was obtained. If the gross sand thickness is small, under 100 feet, the sand-volume content can be obtained by superimposing an isopachous map upon a structural contour map and planimetering the average thickness of each 100-foot increment. For sand thicknesses over 100 feet, one approacli would be to construct a sufficient number of cross-sections of the pool from which the weighted sand-volume of each 100-foot increment could be obtained. Variations in the sand body with depth, as determined by core data, can also be included in the above process. Table I presents a summary of sand-volume calculations, core data, and the original distribution of reservoir hydrocarbons in the pool. Fig. 2 illustrates the structural distribution of the sand-volume content. A total of 171,398 acre-feet is contained within the productive limits of the pool. Assuming an average porosity of 25% and an interstitial water content of 20%, the original hydrocarbon content was computed to be 227,075,000 barrels. DEPTH-PRESSURE DATA The determination of the initial vertical pressure arrangement in the pool is necessary for PVT and material balance calculations. Whenever sufficient data are available, a plot of pressure versus subsea depth of measurement should be made. From this plot a representative fluid pressure gradient can be established. Lacking sufficient initial pressure data, an initial pressure gradient may he estimated or calculated from avail-

Jan 1, 1949

By W. Tempelaar Lietz

The Ten Section oil field is located in the San Joaquin Valley in Kern County, California. about 12 miles southwest of Bakersfield in Township 30 South, Ranges 25 and 26 East. The accumulation is in a low relief anticlinal dome and has a productive area of approximately 2,200 acres. Discovered in 1936 as a result of seismic work, it was the first field on the floor of the Valley to obtain production. It had a small primary gas cap, and since its inception has been produced by depletion with controlled withdrawal from the gas cap to minimize blowthrough. STRUCTURE AND STRATIGRAPHY The Ten Section structure is an elongated anticlinal dome with flank dips of only about 7 degrees. A map of the field, now fully developed, and a composite log are shown in Figs. 1 and 2. Contours shown on the map are on the top of the first zone, or Marker XA as indicated on the composite log. As shown, the field has a productive closure of only some 350 feet, and there apparently is no faulting in the reservoir. The productive measures in Ten Section are of Upper Miocene age and are known as the Stevens sand. They contain thin, irregular shale or siltstone streaks which vary considerably in stratigraphic position and thickness and apparently are rather discontinuous. As a result, individual sands and shales cannot be correlated over any appreciable area, which makes it difficult to subdivide the sand body into separate zones which are distinct throughout the field. However, there are two fairly persistent siltstone bodies that at the time of development were considered to divide the productive measures into three - zones. The first, or uppermost zone is productive over the entire field and has an average thickness of 180 feet, of which some 65 per cent is sand. It had a primary. gas cap in the crestal area with an areal extent of 930 acres. The second zone has a productive area somewhat smaller than the first zone, but it did not have any original gas cap. It has an average thickness of about 360 feet, of which 55 per cent is sand. The third zone has a very limited areal extent and a maximum productive thickness of 100 feet, of which 80 per cent is sand. Recently, a deeper oil accumulation, termed the "53" sand, was discovered, but it is not discussed in this analysis. In the first and second zones the water table was at 7,980 feet subsea, while in the third zone it was at 8,080 feet subsea. RESERVOIR CHARACTERISTICS Sand Characteristics The Stevens sand in Ten Section is hard and well consolidated, and numerous wells were cored for core analysis. Core data on four representative wells are shown, plotted beside the electric logs in Figs. 3 to 6. The average porosity is 20 per cent, with porosities ranging from 15 to 30 per cent. It is estimated, from cores taken with oil base muds, that the interstitial water content is about 40 per cent. The average weighted permeability is approximately 140, with measured permeabilities ranging from 10 to 3,000 md. As might be expected with practically no correlation of individual sand

Jan 1, 1949

By W. Tempelaar Lietz

The Ten Section oil field is located in the San Joaquin Valley in Kern County, California. about 12 miles southwest of Bakersfield in Township 30 South, Ranges 25 and 26 East. The accumulation is in a low relief anticlinal dome and has a productive area of approximately 2,200 acres. Discovered in 1936 as a result of seismic work, it was the first field on the floor of the Valley to obtain production. It had a small primary gas cap, and since its inception has been produced by depletion with controlled withdrawal from the gas cap to minimize blowthrough. STRUCTURE AND STRATIGRAPHY The Ten Section structure is an elongated anticlinal dome with flank dips of only about 7 degrees. A map of the field, now fully developed, and a composite log are shown in Figs. 1 and 2. Contours shown on the map are on the top of the first zone, or Marker XA as indicated on the composite log. As shown, the field has a productive closure of only some 350 feet, and there apparently is no faulting in the reservoir. The productive measures in Ten Section are of Upper Miocene age and are known as the Stevens sand. They contain thin, irregular shale or siltstone streaks which vary considerably in stratigraphic position and thickness and apparently are rather discontinuous. As a result, individual sands and shales cannot be correlated over any appreciable area, which makes it difficult to subdivide the sand body into separate zones which are distinct throughout the field. However, there are two fairly persistent siltstone bodies that at the time of development were considered to divide the productive measures into three - zones. The first, or uppermost zone is productive over the entire field and has an average thickness of 180 feet, of which some 65 per cent is sand. It had a primary. gas cap in the crestal area with an areal extent of 930 acres. The second zone has a productive area somewhat smaller than the first zone, but it did not have any original gas cap. It has an average thickness of about 360 feet, of which 55 per cent is sand. The third zone has a very limited areal extent and a maximum productive thickness of 100 feet, of which 80 per cent is sand. Recently, a deeper oil accumulation, termed the "53" sand, was discovered, but it is not discussed in this analysis. In the first and second zones the water table was at 7,980 feet subsea, while in the third zone it was at 8,080 feet subsea. RESERVOIR CHARACTERISTICS Sand Characteristics The Stevens sand in Ten Section is hard and well consolidated, and numerous wells were cored for core analysis. Core data on four representative wells are shown, plotted beside the electric logs in Figs. 3 to 6. The average porosity is 20 per cent, with porosities ranging from 15 to 30 per cent. It is estimated, from cores taken with oil base muds, that the interstitial water content is about 40 per cent. The average weighted permeability is approximately 140, with measured permeabilities ranging from 10 to 3,000 md. As might be expected with practically no correlation of individual sand

Jan 1, 1949

By Sam N. Dewitt, Albert S. Trube

This paper presents a discussion of the pressure maintenance operations which were begun in the New Hope Field. Franklin County. Texas. in 1944. The project has required the injection of extraneous waters at depths from 7.300 to 8.000 ft with intake well-head pressures up to 4.000 psi in three different reservoirs — the Bacon. Hill. and Pittsburg. Records of oil and water production. water injection and the GOR have been kept for each reservoir and reservoir pressures were taken at regular intervals. These data indicate that the Bacon Reservoir had no apparent water encroachment up to the time of water injection. However. the Pittsburg and Hill reservoirs had some natural water influx hut not sufficient to prevent pressures from declining below the bubble point. The Bacon and Hill reservoirs responded almost immediately to water injection. while the Pittsburg which is the least permeable. has shown good pressure response only since .August, 1948. The principle objective of the project has been to increase ultimate recovery. Success of the project to date also has resulted in reduced lifting costs. Esti- mates based on the initial water breakthrough patterns indicate that the primary objective of substantial additional recovery will he accomplished, and there is a possibility that the original estimates elf oil recovery with pres-sure maintenance will he exceeded. INTRODUCTION This pressure maintenance project was one of the earliest primary pressure maintenance programs to he attempted on a multiple zone field. There are three producing reservoirs into which water is being injected for the purpose of maintaining pressure and increasing the ultimate recovery- from each. This paper is limited in scope to al1 account of the development of the project. the pressure production relationship prior to the injection of water and the effect of water injection on the producing reservoirs. Also discussed are the nature of the injection system and the indicated results on initial water break-through in the Bacon Reservoir. FIELD CONDITIONS The New Hope Field, which is located about 12 miles northeast of Winusboro, Franklin County, Texas, is an elongated symmetrical anticline containing four known oil reservoirs. The reservoirs are of the Trinity group of the Comanchean or Lower Cretaceous period and are found in Table I. The oil productive portion of each reservoir is not present in all of the producing wells because their areas and positions vary with respect to one another. Fig. 1 shows the relative position of the four reservoirs and illusIrate? how some wells could penetrate all four, while others are restricted to three. two. or perhaps one. depending on structural location. The first three reservoirs contain undersaturated oil. The deepest. the Elledge, has a primary gas cap. Although this reservoir covers a considerable area of the field. it has a very thin section and a low order of permeability. Elledge producing wells have generally been characterized by an early increase in GOR, making it necessary to recomplete them in other reservoirs. (At present. one well is completed in the Elledge. which is still producing.) Because of the difficulties en-countered in producing oil from this reservoir. and the small quantity of oil actually present. future attempts at producing it will probably be on a salvage basis during the later life of the program. For this reason, the remainder of this report will be confined to a discussion of the Bacon, Hill and pius-burg reservoirs.

Jan 1, 1950

By W. G. Frailing, W. P. Sims

The Lakeview Pool of Kern County, California, was discovered in 1910 with the drilling of Lakeview No. 1 which blew out and produced an estimated 8,250,000 bbl of oil in 544 days of uncontrolled flow. The well has since been known as the Lakeview Gusher. Full exploitation of the pool did not take place until about 25 years later. A total of 112 producing wells were completed in the Lakeview sand through April 30, 1949. As of that date, about 30 per cent of the total wells drilled were still producing, with an average pool production rate of approximately 2000 bbl per day. The cumulative oil production was about 41 million bbl of oil, or 55.3 per cent of the tank oil originally in place. The pool is bordered on its down-structure side by a body of inactive edgewater and water production where present has been principally the result of coning. Since the depletion of the greater portion of the gas energy by the Lake-view Gusher, the pool has operated under gravity drive. Relatively high angle dips, good permeabilities and favorable fluid characteristics have made gravity drainage particularly effective. Since January, 1942, the oil recovery -has been relatively constant at about 53,000 bbl per ft drop in fluid level. Correlations between the volume of reservoir space drained and the cumulative oil produced indicate that an ultimate recovery of 63.3 per cent of the tank oil originally in place is attainable. INTRODUCTION The Lakeview Pool is an outstanding example of gravity drainage. It is one of many productive reservoirs of the Midway-Sunset Field, and is located in Kern County, approximately five miles southeast of Taft and two miles north of Maricopa, California. Its position rel- ative to surrounding pools and to the Thirty-Five anticline is shown on Fig. 1. The northern portion of the pool lies in sections 32 and 33, Township 32 South, Range 24 East, Mt. Diablo Base and Meridian, while the southern portion lies in sections 25, 26, 35 and 36, Township 12 North, Range 24 West, San Bernardino Base and Meridian. As no two sections bear the same number, they will hereafter be referred to by section number alone. The purpose of this paper is to review the performance of the Lakeview Pool in an effort to evaluate the effectiveness of gravity drive as a recovery mechanism. REGIONAL STRATIGRAPHY AND STRUCTURE The oustanding structural feature is this area is the Thirty-Five anticline, the axis of which plunges South 75" East through the center of Section 35. As shown on Fig. 2, the following zones are oil and gas bearing in the Thirty-Five anticline area: Pleistocene Basal Tulare Tar Sands Pliocene San Joaquin Mya Sands Top Oil or Scalez Zone Etchegoin Kinsey Sand Wilhelm Zone Gusher Sand Calitroleum Sand Miocene Reef Ridge Lakeview Sand Sub-Lakeview Miocene Sands Monarch Sands or fractured shale equivalent Maricopa Webster Sand or fractured shale equivalent Fractured Shale-Uvigerina Zone C Obispo Sand and fractured shale equivalent Pacific Shale Zone The productive interval of the Lakeview Pool is limited to Upper Miocene and Lower Pliocene deposition. In this general area, the most prevalent type of accumulation results from stratigraphic traps or permeability pinchouts. As is the case of the Lakeview Pool, strati-graphic traps resulting from angular unconformities are present. The structure within the Miocene does not parallel that of the Etchegoin (Pliocene), as the Miocene beds were folded, and in places faulted, and subjected to erosion prior to Pliocene deposition. The Lakeview horizon consists of truncated sands which occur on the northeast flank of the Thirty-Five anticline. The direction of strike is west and northwesterly through sections 25 and 36 and continues northwesterly through sections 26 and 33, to the approximate center of section 32. At this point the strike swings to the northeast and the horizon re-enters section 33. in the northwest corner. The change in strike in section 32 affords synclinal accumulation at that point. The Lake-view sand is truncated updip by the Etchegoin overlap. To the southeast, the sand shales out, while to the northwest, the productive interval appears to be limited by a combination of stratigraphic pinchout and permeability barrier. Structurally, the Lakeview reservoir presents three areas of interest, as shown on Fig. 3. Area I in section 32 is a region in which a productive Sub-Lakeview Miocene sand is present. It occurs from 10 feet to 30 feet below the base of the Lakeview sand and attains a maximum thickness of 25 feet in Well No. 21, section 32. The producing characteristics of the Sub-Lakeview Miocene sand differ radically from those of the Lakeview sand. Water production at high structural locations and abnormally high fluid levels indicate that there was no communication with the Lakeview sand. Wells in Area I penetrated this sand and produced it in conjunction with the Lakeview sand. In Area 11, the Lakeview sand is a

Jan 1, 1950

By F. H. Allen, R. P. Roe

The performance history of a volumetric gas condensate reservoir is presented. Curves depict the pressure-production relation and illustrate the phace behavior of the reservoir fluid. This performance is compared to calculated performance. This Bacon Lime Reservoir was discovered in 1941 and has been produced to field separators and gas sales. Reservoir performance has been observed by periodic bottom hole pressure sur. veys and companion sample analysis of well effluents, in addition to gas and condensate production data. , The pressure-production history demonstrates that the reservoir has produced under volumetric control. The "retrograde" behavior of the reservoir fluid is illustrated by decreasing butanes-plus content of the well effluent, followed by revaporization as the reservoir pressure approaches abandonment. Calculated performance predictions are compared to actual performance and some discussion offered on apparent discrepancies. INTRODUCTION Since the late 1930's, many gas condensate reservoirs have been developed, the retrograde theory of phase behavior has been generally accepted, and a number of cycling programs have been initiated. Numerous technical papers have since appeared in the literature dealing with the theory and application of cycling the gas condensate reservoirs. Some cycling operations have now advanced to a stage where it is possible to determine performance characteristics to a fair degree of accuracy. Field performance data for gas condensate reservoirs operated by pressure depletion have not been so extensively reported in the literature, although their probable behavior has been discussed in explanation of the retrograde theory. It is the purpose of this paper to compare calculated theoretical reservoir performance with field observations and well stream analyze; which have been obtained throughout the practical producing life of a small volumetric gas condensate reservoir. The reservoir under study is the Bacon Lime Zone of a field located in East Texas. The Bacon Lime occurs in the Lower Glen Rose Formation of Cretaceous Age. This Bacon Lime Reservoir is encountered at an average depth of 7600 ft (7203 ft subsea elevation) and comprises approximately 3100 acres located on a structural high with 80 ft of productive closure. The producing formation consists of approximately 50 ft of dense crystalline fossiliferous dolomite of generally low permeability with typical wide variation in both permeability and porosity, the more permeable stringers measuring 30 to 40 millidarcys. The average porosity is extimated to be 10 per cent with a connate water saturation of approximately 30 per cent of the pore space. The reservoir temperature was found to be 220°F and the original pressure was 3691 psia at -7200 ft elevation. The re ervoir was discovered in November, 1.941, and is now essentially depleted, Throughout most of its productive life, from the standpoint of cumulative withdrawals, the reservoir has been produced by five wells. During its latter stages of depletion, 16 wells were completed in the Bacon Lime.

Jan 1, 1950

By R. C. Craze

During the past 20 years. research and development in the study of reservoir behavior have dealt principally with flow of oil through sandstones. Many reservoir studies of sand fields have proved valuable in promoting recovery efficiency. This paper discusses fundamental principles governing oil and gas production from sandstone and limestone alike and presents the results of investigations relating to the application of analytical techniques used for sandstone reservoir studies to the study of limestone reservoir performance. The characteristics of limestone porous systems, porosity-permeability relationships, distribution and occurrence of oil, and characteristics of flow through such systems are discussed. Recognition is made of the similarities or differences which these factors exhibit in limestone and sandstone systems. Comparisons between operating data for typical limestone and sand reservoirs are presented. It is indicated that the distribution and movement of fluids in and through porous limestones follow the same fundamental principles underlying such processes in sandstones. This fundamental similarity may readily be discernible in the performance of many limestone reservoirs. The volumetric balance and unsteady state radial flow equation, the fluid displacement equation, use of electrical analogue devices, and other analytical techniques to study the behavior of limestone fields appear fundamentally applicable, but do require thorough understanding of the properties of the formation, of the fluids, their behavior during flow, and adequate production operating data. Need for more complete coring and comprehensive examination of core properties is stressed. The results of "active oil" studies, and of flow and interference tests are presented. Well spacing, well completion, and efficient rates of production in limestone reservoirs are briefly discussed. INTRODUCTION Limestone and dolomite reservoirs constitute the largest source of supply of crude oil in the world. an estimated 60 per cent of present production coming from carbonate reservoirs. In many large geologic provinces such as Mexico. the Middle East, and more recently Canada, almost all the oil is found in this type of rock. In the United States, all of the major oil-producing areas except California and Pennsylvania contain oil-bearing carbonate formations. The discovery in recent years of large oil reserves in the Silurian, Devonian, and Ordo-vician formations in West Texas, in addition to the large reserves in the Permian, has accentuated the interest of operators, geologists, and engineers in limestone formations and in the many problems associated with understanding the performance of these reservoirs. The rapid increase in discovery of oil in limestone formations and the present-day position of prominence held by these fields in the production and reserve picture in all parts of the world emphasize the horizons opened to the reservoir technologist in the field of geological and production research. Pertinent to an interpretation of the behavior of limestone reservoirs are the methods of analysis which may be utilized and a possession of full knowledge of the many factors which influence the analytical procedures. During the past 20 years a well-developed science of reservoir engineering has been built upon the research of many workers who studied the fundamental nature of oil reservoirs, characteristics of the porous media, properties and behavior of the contained fluids, and the mechanics of flow. Application of these studies to production practice has resulted in greater recoveries and more efficient field operation. The major portion of this evolutionary process has been founded upon studies of sand fields. The applicability of these more thoroughly developed techniques for studying sand fields to the study of the behavior of limestone fields becomes a factor of technical and practical significance. In the light of the technological background available to the reservoir analyst, this paper discusses fundamental principles governing oil and gas production from sandstone and limestone alike and presents the results of investigations relating to the application of analytical techniques used for sandstone studies to the study of limestone reservoir performance. LIMESTONE RESERVOIR CHARACTERISTICS The characteristics of limestone and sandstone reservoirs are similar in many respects and they both may occur under similar structural conditions. Fundamentally, the distribution and movement of fluids in and through the porous limestone media follow the same basic principles which dictate such processes in sandstones. Herein lies a fundamental similarity, which may readily be discernible in the performance of many limestone reservoirs. In some limestone fields, as in many sand fields, widely varying formation properties and distribution may reveal themselves in deviations in the performance of the reservoir, in the behavior of wells, and in fluid flow through the rock, and make difficult the delineation of reservoir behavior. Only by reservoir studies, core analyses, and coordinated laboratory and field experimentation can the effects of the many influencing factors upon the nature of limestone production be determined. FORMATION CHARACTERISTICS The chief difference between limestone and sandstone, aside from their chemical compositions, is the difference in the geometry and origin of the porous systems in the two kinds of rock. In sandstone the porous system results entirely from the openings among individual sand grains which occur during deposition. The geometry of the openings between the sand

Jan 1, 1950

By John W. Crutchfield, Emil F. Bowers

This paper presents the initial results of a pressure maintenance by water return project in the Lower Pawelek reservoir of the Falls City Field, Karnes County, Southwest Texas. Production is from the Lower Wilcox section at an average depth of 6,030 ft on the downthrown side of a "down to the coast" fault. Of particular interest is that the reservoir oil is high gravity and low viscosity but far undersaturated with gas at the original reservoir pressure and temperature. The early pressure and production history indicated only a partial or limited water drive, and this fact, coupled with the characteristics of the reservoir fluid and artificial lifting problem.. made advisable the water injection program to maintain reservoir pressure. The paper includes a description of the reservoir and reservoir fluids, the pressure and production history, a description of the water injection facilities, and the results of reservoir calculations involving Hurst's unsteady state flow and the material balance equations for calculation of water influx and prediction of the pressure-production relationship at various rates of withdrawal. The reservoir calculations and initial field results indicate that reservoir pressures in excess of 85 per cent of original pressure can be maintained by control of water injection even at very high rates of production. INTRODUCTION The purpose of this paper is to report the initial results of a pressure maintenance by water return program in the Lower Pawelek reservoir, Falls City Field, Karnes County. Texas, and to calculate an empirical relationship between pressure and production in this limited or partial water drive reservoir. Location The Falls City Field (Fig. 1) is located two miles north of the town of Falls City in Karnes County, Texas, and is approximately 50 miles south-southeast of San Antonio on U. S. Highway 181. Discovery and Development The initial block of leases was taken after a surface geological survey identified a major east-west fault and closure on the south or downthrown section. The discovery well, Southern Minerals Corporation's Joe F. Bartosch 1; was completed at 4,650 ft in the Lower Bartosch sand in December, 1944. Drilling was continuous until December, 1946, and resulted in the discovery of 12 oil reservoirs between 4,600 and 6,050 ft in the Middle and Lower Wilcox formations. These are shown on the cross-section (Fig. 2). As of the current date there are 64 oil wells completed as follows: Southern Gulfshore Magnolia Minerals Oil Petroleum Reservoir Corp. Co. Corp. Total Upper Bartosch 0 0 0 0 Lower Bartosch 16 0 0 16 Shulze 7 0 1 8 Upper Faires 2 0 0 2 Lower Faires 4 0 0 4 Upper Moczygemba 0 0 0 0 Lower Moczygemha 2 0 0 2 Olinick 2 0 0 2 Upper Martinez 0 0 0 0 Lower Martinez 5 0 0 5 Upper Pawelek 0 0 1 Lower Pawelek 27 1 3 31 Total 65 2 4 71

Jan 1, 1950

By P. P. Reichert, L. S. Gournay, N. T. Burdine

An investigation of equivalent pore entry radii in typical samples of petroleum reservoir rock and the pore volume associated with each value of pore entry radius has been made. Theoretical discussions together with experimental procedures for obtaining pore entry radii and the distribution of pore volume with pore entry radii are presented. Experimental results on a number of core samples, along with typical distribution curves, are shown. Data on the per cent of the pore volume filled by mercury at a pressure of 1500 psi are included. The results of re-runs of samples, made possible by regenerative apparatus, show the repeatability of the data and indicate the amount of physical change in the samples by mercury penetration. Theoretical equations for calculating permeability from pore size distribution data were derived and the results of such calculations are compared with measured gas permeability data. The effect of the shape, surface area, and weight of the sample on the pore size distribution of reservoir rocks was investigated experimentally. Mercury capillary pressure curves are compared with those obtained by the porous diaphragm method using pas to displace water. Standard core analysis techniques, in general, lead to quantities which are statistical averages of the varying properties of the samples under examination. Although such statistical information has real value in predicting the gross performance of porous bodies. it fails to provide fundamental information concerning the properties of the porous medium itself or any processes which may be occurring in it. For example, a gas permeability measurement on a core sample is an indirect way of determining an average pore radius for that particular sample. Since there are many combinations of pore radii that will give the same radius. and, hence, the same permeability, no information is obtained on the pore size distribution. Furthermore, similar values in permeability do not imply similarity in other properties of a porous medium. For instance, it is possible to have two core samples with identical permeability which would have different residual oil contents at the end of an air-oil drive, or even different amounts of interstitial water. It has been recognized for some time by the petroleum industry that a determination of pore size distribution for porous reservoir rocks offered promise of increased understanding of fundamental flow processes in the porous matrix. and therefore of petroleum res- ervoir performance in general. There have recently been published several methods for determination of pore size distribution in porous materials. A report is given here of the modifications in equipment and technique required to adapt one of these methods to measurements on petroleum reservoir core samples. Although only a few correlations or applications of the method are available for presentation at this time, the technique is brought to the attention of the industry so that the opinions and experience of others with this or similar techniques may be exchanged. It seems possible that the method will have wide application in the future. METHOD There are three general methods which may be employed to measure the pore size distribution in naturally occurring rock formations. One method1 is based on experimentally determined adsorption isotherms for calculating the surface area of the porous medium. Knowing the surface area and the pore volume, a rough estimate of the pore radius can be made. Since this method depends on the thickness and uniformity of the adsorbed layer, the validity of the results would be highly questionable. A second method utilizes capillary pressure data obtained by static dis-

Jan 1, 1950

By W. H. Justice

Cycling operations have been successfully conducted in the La Gloria Zone for eight years. The cycling of this zone is now virtually completed. It is proposed that this report shall review the cycling operations of this reservoir so that the industry can more accurately evaluate the cycling process as a production method. The La Gloria project is one of the largest cycling operations in the State of Texas. The gas rights in the field are unitized in three operating units. By mutual agreement Magnolia Petroleum is the designated operator of the project for the 12 operators owning the gas rights. The La Gloria Corp, is the owner and operator of the cycling plant. The development and operation of the field are under the direction of an Operators Committee comprised of a representative of each operator. The Operators Committee is assisted by an Engineering and Geological Sub-Committee. The La Gloria gas field is situated approximately three miles north of Fal-furrias, Tex., and lies principally in the extreme south end of Jim Wells County, with its outer limits extending into the north end of Brookes County, Tex. It is a simple elliptically-shaped dome which has a closure of 350 ft. The field encompasses a surface area of 5,500 acres. The gas reserves are found in 20

Jan 1, 1950

By Rex W. Woods

The clue history of performance of a highly volatile type oil reservoir which is now greater than 80 per cent depleted is presented. The reservoir is at a depth of approximately 8,200 ft and includes an area greater than 7,500 acres. The reservoir has been exploited by 10 wells which to date have yielded about 10,880,000 bbl of stock tank oil by pressure depletion. Reservoir pressure has declined from an original of 5,000 psi to approximately 1,450 psi. Produced gas/oil ratio has increased from 3,200 to 23,000 cu ft/bbl with a corresponriing increase in APl gravity of the stock tank oil from 440 to 620 . Pressure and fluid data are given for different stages of depletion. INTRODUCTION In papers by Sloan,' and Cook, Spencer and Bo-browski,' properties of highly volatile type reservoir oil were discussed in detail and methods were presented for predicting performance of reservoirs containing this type of fluid. The purpose of this paper is to present performance history of a highly volatile type oil reservoir designated as Reservoir A which has been produced by pressure depletion and field separation without processing of gas GEOLOGY The reterence field which includes Reservoir A is a structural feature north of a trend of major folding along a northeast-southwest axis. In the area of development, the structure has the appearance of a dome with formation dip of three to four degrees, but structural relations between the reference field and the axis of major folding to the south have not been determined. No faulting within the field is evident. Oil and gas productive sands have been found at depths of 7,000 ft to 10,000 ft in a columnar section of Mio-Oligocene age. The sand bodies in the section are lenticular and usually continuity of sand is limited to a small area. Sand A which forms Reservoir A at a depth of 8,200 ft, however, has exceptional continuous development in the reference field. Fig. 1 shows an isopachous map of net oil sand for Reservoir A. Net thickness of oil sand at producing wells ranges from 14 to 34 ft with an average of 22 ft. Pinch-out of sand has been shown by drilling in the southwest part of the field, but extent of the reservoir on the northwest and northeast parts of the field is indicated only by thinning of the sand. The vertical oil column between the highest and lowest producing well in the reservoir is 339 ft. No water-oil contact has been found within the reservoir. As interpreted from the isopachous map, the reservoir includes about 8,900 acres with an average net sand thickness of 12 ft. Because of limited data on extent of the reservoir, the isopachous map permits only an approximation of sand volume in the reservoir. DEVELOPMENT AND PRODUCTION Reservoir A was discovered during 1938 and was developed with eight wells to the end of 1942. One well was completed during 1946 and the tenth well in the reservoir was completed during 1951. Three of the original wells and the last completion have produced from Sand A only. Six wells have produced from Sand A through the casing side of dual completions. Initial producing rates of the original wells ranged from 800 to 1,000 BOPD. Production history for the reservoir is shown in Fig. 2. Production of the reservoir was begun during 1940 and in May, 1952, peak production from seven wells was 5,300 BOPD. At the end of March, 1954. cumulative production was 10.880,000

Jan 1, 1956

By F. M. Stewart, F. H. Callaway, R. E. Gladfelter

In this paper oil initially in place is calculated by the various methods commonly used for analysis of water drive fields using data available as time progresses. Rate and pressure are predicted by means of the same methods using data available at the end of two years' history. These predictions are then compared with subsequent performance permitting an evaluation of the methods, which are Modified Schilthuis, Simplified Hurst, van Everdingen et al (1952), and the Electric Analyzer. INTRODUCTION Several variations of the material balance equation, differing in the term used to evaluate water influx, are in common use for estimating oil in place, predicting rate and volume of water influx, and forecasting producing rates and reservoir pressure in water drive reservoirs. The electric analyzer with an electrical network set up to simulate the oil reservoir and aquifer and their contained fluids may be used for the same purpose. Examples of the application of one or another of these methods have appeared in the literature. The accuracy and reliability of the material balance for calculating oil in place have been covered.' However, there have been few articles in which more than one method has been applied to an actual field allowing a comparison. It is felt that a field example, simple in nature, where the Modified Schilthuis, Simplified Hurst, van Everdingen et al (1952), and the Electric Analyzer have been applied would be of benefit in providing an evaluation of these methods as to their comparative usefulness and reliability in calculating initial oil in place and predicting performance. The Torchlight Tensleep reservoir is a small field in a large aquifer. The reservoir oil is greatly under-saturated, having a bubble point of only 55 psi and 2 cu ft/bbl of gas in solution. Changes in the reservoir volume factor in the range of pressures encountered are small, meaning little error in converting production to reservoir conditions. The pressure has declined from 1,618 psi initially to 137 psi during the first four and one-half years. Water production has been negligible. For Torchlight, the material balance equation as discussed later is considerably simplified by the omission of terms having to do with free gas. Thus with simpler equations, less variables to consider, the large pressure drop, the absence of a gas phase, and rapid pressure-rate adjustments, which mean an unusual amount of history in a short time, the reservoir appears suitable for comparing the methods listed above. GENERAL INFORMATION ON THE FIELD The Torchlight field is located on the eastern side of the Big Horn Basin, Big Horn County, Wyo., approximately 3 miles east of the town of Basin. The Tensleep reservoir was discovered in September, 1947. It lies at a depth of about 3,000 ft and produces oil of 35" API gravity. A total of five wells have been completed in the Tensleep, but only four are now producing. The reservoir is well defined in areal extent in that a total of 13 wells have penetrated the Ten-

Jan 1, 1955

By C. R. Criss, R. J. McCormick

ThiS paper .summarizes the development and perform. ance of the Coldwater Oil field, Isabella County, Mich. Production is obtained at a depth of 3750 ft from a dolomite reservoir, which is probably both Rogers City and Dundee. There appears to be no persistent barrier to vertical fluid movement between the Rogers City and Dundee, and both formations are believed to have a common original oil-water contact. No we1ls are open to production at the level of the Dundee. The discovery of the field in 1944 was followed by the drilling of 81 producing wells and nine dry holes. By the end of 1952, the field had produced 12,763,000 bbl of oil, at which time 69 active wells were producing 3600 B/D oil and 21,000 B/D water. The reservoir has an effective natural water drive, and bottom-hole pressure has declined 75 psi from an original pressure of 1453 psi. Oil is undersaturated at reservoir conditions with a solution GOR of 512 cu ft/bbl and a saturation pressure of 1190 psi. INTRODUCTION Although the Coldwater Field is now in its ninth year of production, it ranks seventh in cumulative recovery, and second in current daily oil production in the State. Following complete development of the field in 1946, it has consistently contributed approximately 11 per cent of Michigan's daily production. Coldwater appears to have a greater pay thickness than most fields producing from the Rogers City forma- tion in the west central part of the Michigan basin. Except as influenced by the extent of closure and the thickness of the oil column, reservoir performance is believed to be representative of Rogers City fields in this part of the basin. For this reason, it is felt that the following presentation of factual data for the field will be of general interest. HISTORY AND DEVELOPMENT Discovery of the Coldwater field during Aug., 1944, followed favorable subsurface geological correlations and core tests drilled to a shallow stratigraphic marker horizon. The field is located in the west central part of the Michigan Basin in Coldwater Township (T16N-R6W), Isabella County. It is 60 miles west-northwest of Bay City, and near the geographic center of the southern peninsula of Michigan. The discovery well flowed 200 bbl of oil the first 24 hours from the Rogers City dolomite at a depth of approximately 3750 ft. Field production is principally from the Rogers City with a minor amount assumed to come from the underlying Dundee dolomite, although none of the wells are open to production at the level of the Dundee. Both the Rogers City and Dundee formations belong to the Devonian system (See Geologic Column-Fig. I.) In addition to Rogers City-Dundee oil production, sweet gas is produced from the Michigan Stray sand of the Mississippian system at a depth of 1400 ft. The gas reservoir has approximately the same areal extent as the underlying oil reservoir. Although gas production is an important feature of the Coldwater field, this report is concerned only with the oil reservoir. The productive area is approximately 3200 acres. The pool is developed on a 40 acre spacing pattern with wells drilled in the center of the north half of 40 acre tracts, except for a few off-pattern wells drilled along

Jan 1, 1955

By D. R. McCord

Data of a known statistical quality has been successfully used in a system of conventional fluid mechanics equations essentially free of empirical "conformance factors to prediet early detailed field 03 in a reservoir where gravity drainage is important and oil and rock properties vary con. siderably. The system is useful where comparative recovery predictions for one or more cases of natural depletion and gas cap pressure maintenance are needed and the reservoir is not too heterogeneous. INTRODUCTION Many authors, have examined various facet* of the gravity drainage-gas cap pressure maintenance problem over the last several years. Two of them. Burtchaell and Elkins, have published practical studies. In the case described in the present paper the best development and operating plan for one of the important reservoirs of the Bolivar Coastal Field in Western Venezuela was urgently needed. It was requested that sound comparative economics be presented along with an engineering evaluation of no additional drilling, maximum drilling. several cases of gas pressure maintenance, of water flooding and combination cases. A rapid analysis of the effect on recovery of the range of crude and rock properties indicated that none of the published methods using average properties would yield adequate comparative predictions. This paper covers the predictive system developed to deal with natural depletion and gas cap pressure maintenance. The large amount of data available for this field permitted statistically reliable correlations to be made of most rock and oil properties, and the evident smooth areal variations of these properties encouraged the construction of a lineal mathematical model of material balance and fluid flow equations, which could be manipulated by a modified iterative procedure. The manipulation is much more adaptable to computing machines than manually operated calculators and subsequent studies have been prepared for the IBM Card Program Calculator. A matrix as opposed to linear model has been tentatively worked out by other members of our group to deal with more heterogeneous reservoirs. It is more adaptable to computers such as IBM-701 or the Remington-Rand Univac. In 1950, when the system reported below was developed, no rapid computing machines were available to the author. Their existence and promise encouraged an initial approach by hand. Some details of oil and rock Property correlation are included because there are a surprisingly large number of medium-sized reservoirs in the world that show systematic property variations which are significant for a rigorous analycon. All large reservoirs (over half a billion barrels recovery) with which the author is familiar contain at minimum a significant temperature variation. Using the rock and oil property correlations, past pressure and production, the gas-oil ratio history of the reservoir was computed and found to be in close agreement with field measurements. The future performance under cases of natural depletion, gas injection of 100 MMcf/day, and of 130 MMcf/day, was then computed; a 70 MMcf/day case was also carried far enough to provide data for comparative economics. The 130 MMcf/day case proved to be the most attractive. A 50,000 horsepower gas turbine driven centrifugal compressor plant to take this quantity of adjacent field gas from 30 to 1,950 psia and inject it into the reservoir is under construction. The total cost of the project will exceed 20 million dollars.

Jan 1, 1953

By W. H. Ashby, R. W. Cassingham, C. R. Blomberg, J. B. Justins

The Brookhaven field is one of several Basal Tuscaloosa reservoirs located in south-central Mississippi. It is a standstone reservoir, of erratic deposition and with several faults, having an approximate subsea depth of 9,800 ft. A large variation in permeability exists with a weighted average being 256 md. Estimated average interstitial water saturation is 45 per cent. The undersaturated reservoir fluid exhibits marked differences in physical properties with measured saturation pressures ranging from 733 to 2,255 psi. Early rapid decline in reservoir pressure caused the operating interests to unitize the field and initiate a program of pressure maintenance by gas injection. At the time gas injection was commenced, the reservoir pressure had fallen to nearly half of the original pressure with only 4.5 Per cent of the original oil in place produced. The reservoir pressure has since been maintained at approximately 2,750 psig, and cumulative production to date is 17 per cent of original oil in place. An analysis of field performance during gas injection is presented in detail. The program of pressure maintenance by gas injection is considered to be a success, since the expected ultimate recovery has been increased and the current production rate is in excess of 2 per cent of original oil in place per year. Performance has been better, anticipated ultimate recovery is larger, and total production costs are lower than for a similar Basal Tuscaloosa reservoir nearby, even though that field appears to have a more effective natural water drive. INTRODUCTION The history of the Brookhaven Unit is a testimonial for unitization and for the application of engineering techniques in the operation of an oil field. The operating and royalty interests in this field have mutually benefited from their early recognition of the need for unitization and pressure maintenance and from the forthright manner in which these were accomplished. The tangible benefits accruing to the participants in the Unit are: (1) income from gasoline plant products, (2) reduced lifting and operating costs from those of competitive operation, (3) maintenance of high levels of current income by mitigation of the inevitable decline in production rates inherent to natural depletion, (4) an increase in ultimate recovery of about 40 per cent over natural depletion operations. This paper should properly be considered a progress report; however, the performance of the field after five years of pressure maintenance clearly indicates that the ultimate success of the project is assured. LOCATION AND GEOLOGY The Brookhaven field is located in south-central Mississippi, about six miles from the town of Brookhaven. Production at Brookhaven

Jan 1, 1955