Secondary Recovery Projects Research Articles

Successful Sand Control Design for High Rate Oil and Water Wells

Successful sand control in high rate oil and water wells can be achieved by following this procedure: define the sand, design the gravel, control the placement, and stabilize the pack once it is in place. Introduction A key factor affecting the profitability of waterflooding heavy-oil, unconsolidated-sand reservoirs is the ability to achieve effective sand control completions in response and injection wells. Effective sand control reduces liner failures, simplifies individual well operating problems, and protects expensive pumping equipment required for high producing rates. A survey of the literature and current completion practices indicates that the gravel flow packed liner practices indicates that the gravel flow packed liner completion is the best method currently available for controlling sand in unconsolidated sand reservoirs subjected to high rate waterflooding. However, to be effective over the life of a typical waterflood (10 years or more), the gravel flow packed completion must be carefully designed and properly installed. Presented here is a method for designing a gravel flow packed liner completion, based on the following considerations:formation analysis,gravel-to-sand ratio,formation sand uniformity, andvelocity through slots. The technique is developed from the technology and experience of the water-well and petroleum industries, noting that continual improvement in well completions is necessary to achieve or maintain profitable secondary recovery projects. Literature Survey For over 30 years a number of investigators looked for a way to control sand. Laboratory experiments with sand, bridging over rectangular perforations, brought about the designed slotted liner. But even with reasonable empirical formulas and factors of safety, only a measure of control was possible in unconsolidated sand reservoirs. The problem increased when secondary recovery operations made possible the production of relatively large volumes possible the production of relatively large volumes of fluid. How was it, then, that water wells could produce thousands of barrels of sand-free fluid through small intervals? The water-well industry had been using the gravel flow pack completion method with such success that, in many areas, the technique was a standard completion practice as early as 1916. The oil industry rapidly began to research the gravel flow pack. By the mid-forties there were enough field data pack. By the mid-forties there were enough field data to confirm the investigators' theoretical conclusions. Once the basic design requirements were established, completion techniques were improved so that today practically every aspect of a well designed flow pack is practically every aspect of a well designed flow pack is defined in the literature. Basic Design Considerations The function of the gravel flow pack is to act as a filter, allowing natural fluid movement but preventing formation sand grains and other solids from entering the wellbore. Bridging of the formation against the gravel pack is the key to the control of sand movement. When effective bridging is achieved, sand and other solid particles carried by the formation fluids are deposited at the pack's periphery, allowing clean fluids to be produced. JPT P. 1193

Performance of the Skewed Four-Spot Injection Pattern

Abstract Secondary recovery projects often are not started in oil reservoirs until dictated by rising GOR's or declining oil production. Such circumstances require a well dispersed production. Such circumstances require a well dispersed injection pattern to prevent the oil bank from bypassing the production wells. Many times this purpose is served by using the five-spot or line-drive patterns, in which half of the wells are made injection wells. A regular injection pattern is proposed that is based on the same well spacing pattern is proposed that is based on the same well spacing as the five-spot but in which only a third of the wells need be converted to injection wells. Fluid flow model studies on this proposed pattern show that production histories will be as good as those for a five-spot pattern at mobility ratios of three and above. The model data are presented in a form that may be used to predict recoveries from both homogeneous and stratified formations. Introduction The injection of fluid into a petroleum reservoir usually and pumped by an actual, or predicted, loss in the productivity of the reservoir. Often, an oil reservoir is productivity of the reservoir. Often, an oil reservoir is produced by pressure depletion until high GOR's dictate a produced by pressure depletion until high GOR's dictate a change in policy. Fluid injection also causes increased ultimate recovery, but this usually is of less importance to the operator than is the maintenance of the production rate. It is a fact that the ultimate recovery in any particular fluid injection project is relatively independent of the number and spacing of the injection wells as long as the reservoir voidage through the production wells is balanced by the total injection rate. However, the response of a production well is directly affected by the distance it lies from production well is directly affected by the distance it lies from an injection well. In places where the well productivities are declining, the injection wells should be spaced as evenly as possible among the producing wells ("dispersed" injection pattern). More particularly, if the production response depends upon the formation (and subsequent production) of an oil bank, each production well should be surrounded by injection wells. Otherwise, the oil productivity will increase very little as the oil bank moves productivity will increase very little as the oil bank moves past the well. An evenly spaced injection pattern has the past the well. An evenly spaced injection pattern has the best chance of generating an oil kick in the production wells. If reservoir voidage and injection rates are to be equal, the ratio of injection wells to production wells must be equal to the ratio of the average injectivity to the average productivity (in reservoir volumes). This ratio is productivity (in reservoir volumes). This ratio is instrumental in choosing the injection pattern. Table 1 shows the production well to injection well ratio for the dispersed injection patterns that have been described in the literature. All of these patterns will have comparable recoveries and response times (for the same basic distance between wells). The choice of pattern therefore depends upon the relative injectivity and productivity of the wells and upon the type of drilling pattern employed. Another important factor may be the ability of the proposed production wells to make up the lost productivity proposed production wells to make up the lost productivity from those wells converted to injectors. These factors become more pronounced at the higher oil viscosities (low gravity oils). All other things being equal, the probable ratio of single well injectivity to single well productivity will be equal to the water-oil mobility ratio of the proposed flood. Thus, high mobility ratios (due to low gravity proposed flood. Thus, high mobility ratios (due to low gravity oil) should call for fewer injection wells - as long as these injection wells are "dispersed" to obtain more even production response for the remaining wells. Secondary production response for the remaining wells. Secondary recovery projects in oil reservoirs seldom, if ever, will have mobility ratios requiring more injection wells than production wells. Thus, only the last five of the patterns listed production wells. Thus, only the last five of the patterns listed in Table 1 will be of significant interest in oil recovery. TABLE 1-CHARACTERISTICS OFDISPERSED INJECTION PATTERNS No. of Production Drilling PatternPattern No. of Injection Required Nine-spot 1/3 Square Seven-spot 1/2 Equilateral triangle Straight line drive 1 Square Staggered line drive 1 Offset lines of wells Five-spot 1 Square Four-spot (inverted 2 Equilateral triangleseven-spot Inverted nine-spot 3 Square JPT P. 1315

Point-Bar Origin of Fall River Sandstone Reservoirs, Northeastern Wyoming

Proved oil reserves of more than 40 million bbl have been found in the Lower Cretaceous Fall River Sandstone on the northeast flank of the Powder River basin. Most of the oil is in stratigraphic traps on gentle regional dip of about 2° SW. Fall River reservoir sandstone formerly was believed to have been deposited as barrier bars with the updip permeability barriers provided by lagoonal shale. A new interpretation of West Moorcroft field (Mettler, 1966) suggested an origin as point-bar sand deposited in a meandering stream channel with the updip permeability barrier provided by a clay-filled, abandoned channel. This interpretation is applicable to other Fall River oil fields, as shown by distribution of sandstone at Coyote Creek and Miller Creek fields. On the basis f thickness of permeable sandstone, a pattern is present which is remarkably similar to that of point-bar, swale, and channel deposits of recent stream-meander belts. Recognition of these distinct facies will aid in exploration for new fields, in development drilling within fields, and in planning for secondary recovery projects.

Developments in West Texas and Southeastern New Mexico in 1966

The Permian basin continues to be one of the most active areas of petroleum and gas exploration and development in the United States; 778 exploratory wells and 2,997 development wells have been drilled. This is a reduction of 114 exploratory wells compared to 1965. Exploratory well success was 26.4%, and development well success was 86%. Gas exploration continued to increase, with important gas reserves being found in the Delaware basin. Crude production increased 7.7% in 1966 compared to 1965. This increase was the result of completion of 2,516 oil wells during 1966, successful implementation of secondary-recovery projects, and the higher Texas proration factor in 1966 than in 1965. The most active and successful exploratory areas were the Central Basin platform and the Delaware basin. The most active development trends were the Cato-Chaveroo trend in Chaves and Roosevelt Counties, New Mexico, and the Spraberry trend of West Texas. Seismic exploration decreased only 1% compared to 1965, which may indicate the end of the downward trend. Leasing continued at a high level of activity. Large cash bonus prices were paid for good acreage. Key acreage in the Delaware basin sub-province brought the highest prices in the area, whereas $1.00 per acre or less was paid in the nonproductive frontier.

West Burkburnett Waterflood-A Successful Shallow Project In North Texas

Abstract The West Burkburnett field is located about two miles west of burkburnett in Wichita County, Tex. Waterflooding of the field began nearly 22 years ago. The project has been so successful that expansion has ultimately covered the entire reservoir, although initial plans were to flood only about half of the area. Recoveries are given showing that 50.5 per cent of the original stock tank oil in place will ultimately be recovered and that secondary recovery of 35.3 per cent of the original stock tank oil in place will be 2.3 times greater than total primary. Mobil Oil Corp. is the major operator in the field and has gained much valuable experience in waterflooding through operation of the project. Pertinent data concerning the development, operation, characteristics and success of the project are given, and general conclusions are drawn concerning certain engineering techniques used in waterflood operations. Introduction Waterflooding has long been recognized as an important method of increasing oil recovery from shallow reservoirs in North Texas, The West Burkburnett project, a water injection operation in the 1,750-ft Gunsight sand, was one of the first major secondary recovery projects to be developed in the area. Information gained in the operation of the project has been profitably applied in the project itself and in other reservoirs. In most shallow Cisco Sand waterfloods in North Texas, secondary oil recovery has been less than primary oil recovery except where primary recovery was less than 15 per cent of the original stock tank oil in place. Primary recovery from the West Burkburnett project was 15.2 per cent. Secondary ultimate will be more than twice the total primary. The J. G. Goins lease, which served as a pilot for the project, had a primary recovery of 24.3 per cent, Secondary ultimate recovery for the pilot area was about 1.6 times the total primary. This project has been far more successful than the average North Texas project. Ultimate total recovery from Mobil leases, which comprise about 85 per cent of the field. will be more than 20 million bbl. The West Burkburnett field is situated between the old Burkburnett Townsite and Clara fields, about two miles west of Burkburnett, Wichita County, Tex. Geology and Reservoir Properties The Gunsight sand of the Cisco series and Pennsylvanian age is found in the West Burkburnett field from a depth of 1,550 ft at the south edge of the field to 1,850 ft at the north edge. Sand thickness averaged 10.6 ft for the primary area and 11.6 ft for the secondary area. The structure is monoclinal, dipping about 120 ft/mile from south to north. The reservoir is formed as the sand grades into shale on all sides. Shale is also interspersed in the sand body throughout the reservoir, but is not found in any continuous beds. The sand is also associated with a limestone which lies immediately above it and is almost always known to be present. Thin lime streaks are also commonly present, but are not believed to be continuous. The sand is fairly uniform in porosity and permeability distribution, and in sand thickness. The primary recovery mechanism was solution gas expansion. Primary productive limits on Mobil leases contained more than 3,100 acres, about 2,600 of which have been included in the waterflood project. Approximately 700 core samples were taken from new development wells on Mobil leases. Analyses of these core samples and supplemental data from electrical logs were considered in determining reservoir properties. Comparison of properties from individual leases showed that the sand was of such uniformity that, after the initial development, averages were compiled for the total reservoir (Table 1). History of Development The field was discovered in June, 1912, when Corsicana Petroleum Co., a predecessor of Mobil, completed its Chris Schmoker No. 1 for 85 BOPD. Corsicana owned several other leases in the field amounting to about 85 per cent of the primary productive area. Development of the field continued between 1912 and 1926, and virtually all the locations were drilled on regular 10-acre spacing. Several inside locations on Mobil's leases were not drilled. Initial potentials varied between 5 and 125 BOPD (pumping) with the average being approximately 30 BOPD and no water. A vacuum of 18 in. of mercury was pulled on the casing-tubing annulus of most wells early in their lives. Gas was transported to the Burkburnett gasoline plant, which was constructed in 1918. JPT P. 919ˆ

Exploration Developments in Colorado-Nebraska, 1965-1966: ABSTRACT

During the past 12 months, total exploration and development drilling in the Denver basin maintained the relatively low but consistent plateau established during the previous year. Approximately 80-90% of the tests were drilled by independent operators. Major oil companies have been active in development drilling, secondary-recovery projects, and exploration in pre-Cretaceous formations, particularly the Permian and Pennsylvanian. Significant discoveries in the Cretaceous D and J sandstone bodies were found in the older so-called fairway part of the basin. Here both subsurface control and land are available. In the available-land category are Logan and Morgan Counties, Colorado, and Cheyenne County, Nebraska. Seismic activity took place only in the following areas: Weld County, east of Black Hollow field, the extreme southern part of the basin in Crowley and Pueblo Counties, and in the evaluation of D and J sandstone prospects. The Colorado and Nebraska legislatures passed involuntary unitization laws. This, together with improved secondary-recovery methods, should increase ultimate recovery and profit on a per-well basis. Largely because of the increased number of tests and information available, a few companies are using computers in their exploration programs. The exploration pattern established during the past few years should continue. End_of_Article - Last_Page 2029------------

Exploration and Development, Montana and Dakotas, 1965-1966: ABSTRACT

Total exploratory drilling in the three-state area has increased from the preceding year. This is primarily the result of successful operations in the Sweetgrass arch area of Montana. This paper relates exploration developments in the three-state area. Examples are given of exploratory drilling that utilized some of the concepts presented in papers given at previous annual meetings of the Rocky Mountain Section. Areas of greatest drilling activity are outlined and discussed. Secondary recovery projects approved by appropriate state agencies are listed and discussed. End_of_Article - Last_Page 2029------------

A Two-Spot Combustion Recovery Project

Abstract Recovery of 400-cp oil from a 4,500-ft deep reservoir by forward combustion was successfully demonstrated. Of the 226,000 bbl produced during the project, at least 132,000 bbl represent additional recovery over primary. Vertical conformance was estimated at 75 per cent. Sixty percent of the oil was produced after completion of air injection. Reservoir and performance data are given. Introduction This in situ combustion pilot test was undertaken to investigate the possibility of recovering heavy (9 to 12 deg. API) oil from deep (4,500 ft) reservoirs. Mene Grande Oil Co. holds or operates concessions in Eastern Venezuela with considerable reserves of these heavy crudes. Primary recovery from these very flat reservoirs is generally low (2 to 7 per cent), and viscosities range upward from 400 cp. Conventional water and gas injection have in most cases been economically impractical. Only combustion holds hope of sweeping a sufficient fraction of these reservoirs to make secondary recovery projects feasible. As a modest initial venture, but to yield maximum information in the shortest possible time. an isolated two-spot pattern with 100-meter spacing was selected. Test Site Description The sand selected for this project is highly unconsolidated, with a porosity of 35 per cent and permeabilities ranging from 2 to 5 darcies. Initial oil saturation was estimated to be 94 per cent, with connate water occupying the remaining 6 per cent. The initial reservoir pressure was 1,600 psi, but had dropped to about 1,360 psi by the time air injection commenced. Although many wells had penetrated this sand, virtually all are completed in other reservoirs. However, one existing well was found which could serve as an injectors Some 23 ft of net oil sand was present in two tenses, an upper of 10 ft and a lower of 13 ft. Although a 2-ft shale section separated the lenses, the entire interval was perforated. Prior to inception of the air-injection project, the injection well had produced 89,000 bbl of 9.5 deg. API crude. Its initial rate was 225 BOPD, and a decline- curve analysis yields an estimated cumulative recovery of 183,000 bbl of oil. Following selection of the location and spacing for the proposed two-spot, a second well was drilled 100 m northeast of the injector. It encountered only a disappointing 10-ft sand. considered inadequate for a good producing well. Another well was then drilled 100 m to the southwest. A single 15-ft sand was found, and the well was cased and completed. An isopach map of the sand had previously been prepared from logs of all wells penetrating the section. Spacing is 600-m hexagonal. Most nearby wells are completed in other sands. In view of the rapid changes in thickness found over 100-m distances, this map was rendered meaningless. Thus the effective size of the reservoir could be obtained only from a material balance. An effective volume of 3.56 million bbl of oil in place was computed. The producing mechanism was pure fluid expansion. Equipment and Completions The producing well was equipped with 9 5/8-in. casing, gravel packed, and completed with a 5 1/2 -in. OD slotted liner (see Fig. 2). Two parallel tubing strings were run-a 3 1/2-in. OD production string with a pump holddown nipple, and a 2 7/8-in. OD observation string which swaged to 2 3/8-in. OD to enter the liner. This latter string was plugged on bottom, and a thermocouple line was run inside of it. Three thermocouple junctions were spaced at 5-ft intervals oppositive the perforations. JPT P. 994ˆ

Production Logging-The Key to Optimum Well Performance

Abstract Included in the family of production logging devices are two types of flowmeters (a continuous and a packer type), high-resolution thermometers, gradiomanometers, production fluid samplers, densimeters, water cut meters, and through-tubing calipers. The instruments enable recording of: profiles of flow rate; fluid characteristics that enable determination of the fluid composition; hole sizes; and temperatures. In addition, casing collars are recorded for depth control. Fluid samples, suitable for PVT studies, can be obtained at any depth in the fluid column. Interpretations of these data, especially when used in conjunction with through-tubing gamma ray-neutron and cement bond logs, define most production problems. In new completions, production logging services are used both to ensure optimum ultimate recovery and to explain production problems brought to light by surface performance. In older wells, the logs aid in planning remedial work for declining producers. Monitoring of secondary recovery projects is another important application of production logging services. Introduction Experience indicates that surface fluid measurements are not adequate to describe the efficiency of the down-hole production system. In many wells that appeared to be producing properly, down-hole malfunctions were found that, if uncorrected, would appreciably reduce ultimate recovery. In some instances the malfunctions, if allowed to persist, would even preclude effective application of secondary recovery techniques. Because the operation of the down-hole system has a great effect on ultimate recovery, a more diagnostic means of measurement is required. Production logging tools are designed to operate downhole under dynamic producing conditions. Thus, this family of tools provides the information necessary to evaluate the performance of the well-completion scheme. Included in the family are instruments that locate fluid entry (or injection), measure flow rates, and enable determination of fluid composition from each zone of fluid entry. The tools are built to operate through 2-in. tubing, and to perform properly at pressures up to 10,000 psi and temperatures up to 300F. Pressure control equipment allows safe entry into producing wells with surface pressures as high as 6,000 psi. and into injection wells with pressures up to 7,200 psi. Production Logging Measurements Great progress in production logging has been made recently in the development of tools to work under dynamic conditions. Combinations of these tools (a flow rate meter, fluid identification devices, and some form of depth control) provide answers to the question, "How much of what fluid is coming from where?" Flow rate measurement is not new to the industry. However, downhole determination of fluid composition has always been a problem. The new devices enable identification of the various fluids flowing, and permit computation of the fraction of total flow that each represents. With the constituent fluids thus identified, down-hole flow rate measurements are much more meaningful. The problem of fluid identification is complicated by the variety of possible mixtures of oil, gas and water. and by the effects of fluid velocities on these mixtures. Both the fluid mixture and velocity must be considered in selecting appropriate logging devices. The first consideration must be measurement of parameters that vary sufficiently for reasonable resolution between the constituent fluids of a multi-phase flow. For example, the greatest benefits of a device that measures fluid densities are realized when defining gas entry into liquids. For oil-water mixtures the specific gravities are more nearly the same and resolution is difficult. JPT P. 137ˆ

Developments in Pennsylvania, 1964

Exploration in Pennsylvania during 1964 resulted in the discovery of 2 new fields, 1 new pool, and 3 deeper pools. Production from these discoveries is from deep (Middle Devonian or older) gas-producing formations. Deep development drilling reached an all, time high in Erie and Crawford Counties, where 91 wells were drilled during the year. Development drilling in the shallow fields was concentrated in the Warren-Youngsville and Pleasantville-Tionesta oil areas, and in the Armstrong, Indiana, and Jefferson County gas areas. There were 938 new wells drilled and 27 wells deepened during 1964. This is an increase of 34 per cent over the 700 drilled in 1963. Of the 938 new wells, 911 were in proved fields, and 27 were exploratory tests. Of the 911 proved field wells, 619 were drilled exclusive of underground gas storage and secondary recovery projects, 278 wells in secondary recovery projects, 13 wells in gas storage, and 1 well for waste disposal. Of the 619 development wells excluding secondary recovery projects, 274 were gas wells, 242 oil wells, and 103 dry holes. The total footage drilled during the year was 2,199,863 ft. Exploratory tests totaled 27, drilling a total of 174,906 ft. of hole. Of the 27 exploratory tests, 6 were successful, and 21 were dry, giving a success ratio of 1 in 4.5. Oil pipeline runs totaled 5,113,000 bbls. of crude oil which is more than the 1963 production of 5,014,000 bbls. Proved oil reserves as of December 31, 1964, were estimated at 86,720,000 bbls. Gas produced totaled 85,322,000 Mcf, compared with 92,340,000 Mcf in 1963. Gas reserves were estimated at 1,243,575,000 Mcf at the end of the year. The total reservoir capacity for the storage of natural gas in Pennsylvania is 521,514,000 Mcf. Seismic crews logged 101 weeks during the year. This is an increase of about 11 per cent over the seismic activity in 1963. No gravity work was done but geological field parties were active.

The Dual Solvent Slug Technique for Improving the Injectivity of Waterfloods

Abstract In recent years, secondary recovery of oil by water flooding has becomeincreasingly popular in Western Canada. In most cases, water injection wellsare completed by converting wells that were formerly used for oil production;common practice is to place these wells on injection after some form oftreatment to remove wax and other deposits from the well bore. It has been known for some time that the presence of residual oil impedesthe flow of water, and this is particularly significant in the area immediately surrounding the well bore. It has also been demonstrated in the past that theuse of a miscible displacing fluid leaves lower residual oil saturations thatdoes the use of an immiscible displacing medium such as water. There have been several methods proposed to achieve a reduction in residual oil saturation around water injection wells. These have mainly dealt with the use of surfactants or the injection of low-viscosity hydrocarbon solvents. Recently, several articles have appeared in the literature concerning increased recovery of crude oil from formations through the use of large solvent slugs that are mutually miscible with oil and Water. These articles, based on laboratory studies on a variety of solvents, indicate that this method of recovery is technically feasible but does not appear to be economical. This paper covers an adaptation of the miscible solvent slug technique to increasing injectivity of conventional waterfloods by a reduction of the residual oil saturation around the well bore. Reduction is accomplished by injecting an oil-soluble solvent slug followed by a mutually miscible water-soluble solvent slug. Two alternate types of treatment are discussed, one for newly converted injection wells and the other for wells that have been performing poorly on water injection. The theory behind these treatments is discussed as well as actual case histories of successful field trials on several Alberta wells. Introduction Several articles have been written recently on the subject of secondary recovery by waterflooding in Western Canada. It has been stated that known recoverable oil reserves will increase by approximately 50 per cent when all secondary recovery projects now in operation or planned are completed.

Developments in Pennsylvania, 1963

Exploration in Pennsylvania during 1963 resulted in the discovery of 3 new gas fields, 1 new gas pool, and 4 successful deeper pools. Several old gas pools and fields were extended by development drilling. Development drilling saw its biggest year in the Youngsville-Sugar Grove oil field of Warren County where 132 oil wells were drilled during the year. The daily production from this field reached a high of 1,700 b/d of crude oil. The greatest density of drilling for deep production was in northwestern Pennsylvania in Crawford and Erie Counties where operators continued development of the Medina (Lower Silurian) gas pools. The 8 discoveries are: the Artemas field, Bedford County; Mays pool, Clarion County; Sabula pool, Clearfield County; Fike field, Fayette County; Crichton and Hadden pools, Indiana County; Mt. Zion field, Somerset County; and the Sloan pool, Westmoreland County. There were 700 new wells drilled and 26 wells deepened during 1963. Of the 700 new wells, 672 were in proven fields, and 28 were exploratory tests (all deep wells). Of the 672 proven fields wells, 461 were drilled outside of underground gas storage and secondary-recovery projects, 205 wells in secondary-recovery projects, and 6 wells in gas storage. Of the 461 development wells outside secondary-recovery projects, 202 were gas wells, 198 oil wells, and 61 dry holes. The total footage drilled during the year was 1,727,051 ft. Exploratory tests totaled 28, drilling a total of 166,388 ft. of hole. Of the 28 exploratory tests, 8 were successful, and 20 were dry, giving a success ratio of 1 in 3.5. Oil pipeline runs totaled 5,014,000 bbls. of crude oil which is less than the total production of 5,238,000 bbls. for 1962. Proved oil reserves as of December 31, 1963, were estimated at 91,734,000 bbls. Gas produced totaled 92,340,000 Mcf as compared with 87,308,000 Mcf in 1962. Gas reserves were estimated at 1,214,498,000 Mcf at the end of the year. The total reservoir capacity for the storage of natural gas in Pennsylvania is 512,100,000 Mcf. Seismic crews logged 91 weeks during the year. This is an increase of about 10% over the seismic activity in 1962. No gravity work was done but geological field parties were very active.

Developments in Illinois in 1963

A total of 1,878 new tests for oil and gas was drilled in Illinois in 1963, 39 wells more than were reported in 1962. Of the 447 wildcat wells drilled, 6.5% were successful. Eleven new oil pools, 23 extensions to pools, and 21 new pays in pools were discovered during the year. Mississippian rocks accounted for most of the 55 discoveries with a total of 40. Silurian strata accounted for 6, Devonian for 5, and Pennsylvanian and Ordovician each accounted for 2. Production for 1963 was estimated at 74,861,000 bbls. of oil. An estimated 64%, or about 47.9 million bbls., is oil produced from secondary recovery projects. The amount of exploratory drilling in Illinois in 1964 is expected to approximate closely that of 1963. The search for new pools will be greatest along the margins and shelf areas of the Illinois basin, and there probably will be exploration of the deeper pay possibilities in the deep part of the basin.

The Behavior of Naturally Fractured Reservoirs

Abstract An idealized model has been developed for the purpose of studying the characteristic behavior of a permeable medium which contains regions which contribute significantly to the pore volume of the system hut contribute negligibly to the flow capacity; e.g., a naturally fractured or vugular reservoir. Unsteady-state flow in this model reservoir has been investigated analytically. The pressure build-up performance has been examined in some detail; and, a technique for analyzing the build-up data to evaluate the desired parameters has been suggested. The use of this approach in the interpretation of field data has been discussed. As a result of this study, the following general conclusions can be drawn:Two parameters are sufficient to characterize the deviation of the behavior of a medium with "double porosity" from that of a homogeneously porous medium.These parameters can be evaluated by the proper analysis of pressure build-up data obtained from adequately designed tests.Since the build-up curve associated with this type of porous system is similar to that obtained from a stratified reservoir, an unambiguous interpretation is not possible without additional information.Differencing methods which utilize pressure data from the final stages of a build-up test should be used with extreme caution. Introduction In order to plan a sound exploitation program or a successful secondary-recovery project, sufficient reliable information concerning the nature of the reservoir-fluid system must be available. Since it is evident that an adequate description of the reservoir rock is necessary if this condition is to be fulfilled, the present investigation was undertaken for the purpose of improving the fluid-flow characterization, based on normally available data, of a particular porous medium. DISCUSSION OF THE PROBLEM For many years it was widely assumed that, for the purpose of making engineering studies, two parameters were sufficient to describe the single-phase flow properties of a producing formation, i.e., the absolute permeability and the effective porosity. It later became evident that the concept of directional permeability was of more than academic interest; consequently, the degree of permeability anisotropy and the orientation of the principal axes of permeability were accepted as basic parameters governing reservoir performance. More recently, it was recognized that at least one additional parameter was required to depict the behavior of a porous system containing regions which contributed significantly to the pore volume but contributed negligibly to the flow capacity. Microscopically, these regions could be "dead-end" or "storage" pores or, macroscopically, they could be discrete volumes of low-permeability matrix rock combined with natural fissures in a reservoir. It is obvious that some provision for the inclusion of all the indicated parameters, as well as their spatial variations, must be made if a truly useful, conceptual model of a reservoir is to be developed. A dichotomy of the internal voids of reservoir rocks has been suggested. These two classes of porosity can be described as follows:Primary porosity is intergranular and controlled by deposition and lithification. It is highly interconnected and usually can be correlated with permeability since it is largely dependent on the geometry, size distribution and spatial distribution of the grains. The void systems of sands, sandstones and oolitic limestones are typical of this type.Secondary porosity is foramenular and is controlled by fracturing, jointing and/or solution in circulating water although it may be modified by infilling as a result of precipitation. It is not highly interconnected and usually cannot be correlated with permeability. Solution channels or vugular voids developed during weathering or burial in sedimentary basins are indigenous to carbonate rocks such as limestones or dolomites. Joints or fissures which occur in massive, extensive formations composed of shale, siltstone, schist, limestone or dolomite are generally vertical, and they are ascribed to tensional failure during mechanical deformation (the permeability associated with this type of void system is often anisotropic). SPEJ P. 245^

The Use of Air-Mist for Well Cleanout and Deepening

HOLDER JR., LOUIS E., TECHNICAL DRILLING SERVICE, INC. MIDLAND, TEX. Abstract A method of cleaning out and deepening using air-mist as the circulating fluid and with specially rigged portable rotary drilling tools has been found to be ideally suited for use in fields having low reservoir pressure. Three typical examples from the West Texas-New Mexico Permian Basin are cited. One is the Permian Sand fields of Ward and Winkler County, Texas, and Lea County, New Mexico. Another is the San Andres dolomite fields of Ector, Andrews, Hockley and Terry Countries, Texas, and the third is the Spraberry area trend of Midland, Upton and Reagan Countries, Texas. The Use of Air-Mist For Well Cleanout and Deepening As production rates begin to decline in fields which have been producing for a number of years, engineers and management begin searching for ways to restore the productive capacity, either through workover operations or by means of pressure maintenance or secondary recovery projects. Several factors should be considered in deciding the best method to be employed in work-over and/or reconditioning operations.First, an operation which should give the desired result must be selected, with care being exercised to assure no damage to the reservoir could result from the method to be used.Second, the cost of this operation, considering not only the initial outlay, but also loss of revenue during the workover period and the resulting payout, must justify authorizing the work.The use of air-mist as a circulating medium for cleanout and deepening operations has been found to be most satisfactory, having a number of advantages over the conventional reverse circulation, or cable tools for this type work. Equipment and Processes Used The equipment for air-mist clean-out and deepening is specialized. To reduce the moving costs to a minimum, a trailer mounted rig is used. For deeper work a conventional rotary table is required; however, for shallow cleanout and deepening, a Guiberson rotating head permits the use of a working platform. This further reduces the moving time and cost by eliminating the need for a substructure. These two types of rigs are shown in Figs. 1 through 4. A rotating blowout preventer in addition to a conventional double gate type is required for air-mist circulation as shown in Fig. 5, and a discharge or "blooie" line, preferably of at least 7 in. diameter, fitted with quick break type connections is used to handle the return samples and spent air. If the cleanout or deepening operation is being performed in an area where surface damage would result from an unrestricted blowing of the returned fluid and air, a mist arrester can be attached to the end of the "blooie" line to kill any spray before discharging the returns into a pit. This mist arrester is shown in Fig. 6.Air compressor equipment capable of delivering from 1.5 to 2.5 MMcf/D at pressures ranging from 1,200 to 1,500 psi are required. JPT P. 833^

Early Results Show Wide Range of Recoveries in Two Texas Panhandle Water Floods

Abstract Favorable performance results from each of two pilot water floods conducted in different areas of the Brown Dolomite reservoir in the Texas Panhandle field prompted initiation of full-scale waterflood projects. Although both of the full-scale floods are being conducted in supposedly similar areas of the Brown Dolomite reservoir, flood responses and oil recoveries of the two have been entirely different to date. Kewanee Oil Co.'s Morse water flood located in eastern Gray County, Tex., is an economically successful venture, as evidenced by the fact that two adjacent flood areas have been developed since its completion in 1959, and another one now is under way. On the other hand, flood responses and oil recoveries in Kewanee's Stansberry Brown Dolomite water flood have been discouraging to date, primarily due to premature water breakthrough. Certain reservoir characteristics may exist in the field (such as inherent formation fractures, thin highly permeable sections in some areas and high connate-water saturations) to account for the poor performance, but this has not yet been validated. This paper briefly describes the discovery and over-all development of the Texas Panhandle field, and outlines the development histories of both the Morse and Stansberry Brown Dolomite waterflood areas. Reservoir data, water sources and injection systems, optimum well spacings and injection patterns, operational problems and performance data for the two waterflood areas are compared. Introduction and History of Development The Texas Panhandle field, discovered in 1918, produces from Permian dolomites and the "Granite Wash" of Pennsylvanian age. The development of the more prolific Granite Wash and the better dolomite zones occurred during the 1920's and the early 1930's. The advent of the acidizing technique in the late 1930's led to the development of the "tighter" dolomite areas. Subsequent development was minor until 1952 when hydraulic fracturing caused extensive development of areas previously considered submarginal. The field covers over 200,000 productive acres containing 12,500 active wells with a cumulative production of 1 billion bbl of oil. The principal producing mechanism has been solution-gas drive. The original reservoir pressure was 440 psi with an estimated solution GOR of 210 cu ft/bbl. The limited amount of available energy in the reservoir has been supplemented by several gas-injection cooperatives formed in the 1940's. Approximately one-fourth of the field has been subjected to gas injection, with the result that an estimated 50 million bbl of additional oil have been recovered. The Morse waterflood area of eastern Gray County, Tex., was developed originally between 1928 and 1937. Results of a gas-injection project initiated in 1946 were only partially successful. In 1955 water flooding appeared to offer the most economical possibility of increasing the "Brown Dolomite" reservoir's ultimate recovery. Prior to this time, three pilot water floods had been attempted in other areas of the Panhandle field but all were abandoned as unsuccessful. The Morse Brown Dolomite pilot flood in Gray County and another Brown Dolomite pilot flood in Hutchinson County, Tex., were the first two successful pilot floods in the Panhandle field. The regional locations of secondary recovery projects in the Panhandle field are shown on Fig. 1. Morse Water FloodThe Morse Brown Dolomite pilot flood was started in July, 1955 (in the cross-hatched area shown on Fig. 2). Injection Well No. 10 was drilled in a five-spot location for input service, and Well No. 7 was an old oil well which has been utilized as a "gas-injection" well before being converted to water-input duty. Actual performance of the pilot area in the early stages was a text-book example of calculated performance. Two gas-injection wells were converted to water-input duty in May, 1957, to back up the pilot and further evaluate the practice of converting old wells to water-input service. Expansion in 1958 was limited to the addition of 10 injection wells due to lack of cooperation by offset operators. JPT P. 1323^

Successful Pilot Predicts Bright Future for Loco Hills Water Flood, New Mexico

Abstract The Grayburg-San Andres reservoirs of the Artesia- Vacuum trend, Eddy County, N. M., have produced more than 2 million bbl of primary oil. The rock characteristics and production performance of these reservoirs indicate that many of them should yield substantial volumes of secondary oil. This paper describes the performance of one of the most successful waterflood pilot operations in the Artesia-Vacuum trend. The Newmont Oil Co. pilot in the Loco Hills field consisted of six injection wells in a modified five-spot pattern. Existing producing wells were converted to injection and a local water supply was used until response justified construction of a 26-mile pipeline to deliver sufficient water volumes for full development. Production rates in individual pilot wells increased from 400 to more than 18,000 bbl/month by June, 1960. Injectivity profiles indicate that this field must be flooded at high injection rates and pressures to effectively sweep all of the productive sand and that the reservoir appears to be quite sensitive to variations in injection rates. Additional development of Newmont leases surrounding the pilot area has continued, and the project had 15 injection wells and 47 producing wells on Feb. 1, 1962. These properties, which were producing 444 B/D in Aug., 1958, averaged 2,618 B/D in Jan., 1962. Unit volume recoveries in the pilot flood indicate that the Loco Hills field should be one of the more important secondary recovery projects in New Mexico. Introduction The Loco Hills field is located in the southwestern part of the Artesia-Vacuum trend of Eddy County, N. M., in a minor syncline on the flank of the Grayburg-Jackson monocline. Location of the field is presented in Fig. 1. The reservoir is a stratigraphic trap limited on three sides by permeability pinch-outs and on the east by a static water table. The principle producing formation his Zone 4 of the Grayburg formation of Permian age, locally known as the Loco Hills sand. This zone occurs at an average depth of 2,750 ft. It has good continuity throughout the area examined and, from the data at hand, appears to have uniform characteristics from well to well. The "typical" Loco Hills section consists of 10 to 30 ft of tight gray sand or sandy gray lime, underlain by 20 to 50 ft of soft brown sugar sand. Only the brown sand has a native permeability high enough to permit natural flow. History of Development The discovery well in the Loco Hills field Yates, et al, Federal No. 1 is located in the NW/4 of SW/4 Section 6, T-17-S, R-30-E. This well was completed in Jan., 1939, for a potential of 506 BOPD after being shot with 140 qt of nitroglycerine. Development on random spacing followed rapidly until the field ultimately contained 264 wells over a surface area of approximately 8,500 acres. JPT P. 1223^

Developments in Illinois in 1961

In Illinois 1,832 wells were reported drilled for oil and gas in 1961, a decrease of 4.7% from the 1,922 total reported in 1960. These figures are exclusive of water- or gas-input wells, salt-water disposal wells, old wells worked over, and an undetermined number of oil wells drilled in secondary recovery projects. Exploratory drilling decreased 21.9% from 661 wells (FOOTNOTE 3) in 1960 to 516 in 1961. Fifteen new pools, 45 extensions, and 25 new pays in pools were discovered in 1961. Total oil production decreased from 77,341,000 bbls. in 1960 to 77,117,000 bbls. in 1961. Of the 15 new pools discovered in 1961, 9 oil and 3 gas pools produced from Mississippian sandstones and limestones, 1 oil pool from limestone of Devonian age, and 2 from carbonate of Silurian age.

Review of California Waterflooding Operations

Abstract This paper presents a statistical review of California waterflooding operations. Water flooding was first started in California in 1944; and, as of June 1, 1960, there were 55 active secondary recovery water-injection projects. In addition, there are 14 projects in which pressure is being maintained by water injection and 18 waste-water-disposal projects. The number of floods has increased markedly since 1951 when the crude-oil demand began exceeding the supply. However, for varying reasons, 24 water-injection programs have been discontinued. The majority of floods were started following careful preliminary engineering analyses. No serious difficulties appear to have been encountered as a result of either the relatively high oil viscosity or the rather large average zonal thickness. No data are available to evaluate increased oil recoveries which may result from the water injection, but response has been described as "good" in 20 of the 55 secondary water floods. Scope of Investigation The present investigation is concerned primarily with secondary recovery operations, or those water-injection projects which were instigated at a time when reservoir pressures had declined to values substantially less than the original. Other water-injection projects, those undertaken with the intent of maintaining reservoir pressure relatively near to the original or those primarily instigated for the purpose of waste-water disposal, have not been considered in detail. Projects in these latter classifications are listed in Tables 1 and 2. Current California Secondary Recovery Projects As of June 1, 1960, there were 55 active secondary recovery projects in California. At that time, the secondary recovery projects encompassed a total of 322 injection wells, into which water currently is being injected at a rate of 497,895 B/D. Fig. 1 shows the number of active secondary recovery projects in the state by years since the inception of flooding in 1944. This same graph also shows California's total annual crude-oil production and the annual refinery utilization of crude oil. It is interesting to note the accelerated rate at which new projects were started after the crude-oil demand began to exceed the supply. Tables 4a and 4b summarize all available data pertaining to current, active, secondary recovery projects in California.

Developments in Pennsylvania in 1960

During 1960, exploration in Pennsylvania resulted in the discovery of 1 new gas field, 8 new gas pools, and 1 deeper pool. It also extended several gas-producing areas, and established a new producing depth record in the state. After drilling a dry hole to the Gatesburg formation (Upper Cambrian) in each of its 2 offshore blocks, the New York State Natural Gas Corporation surrendered its acreage. The new producing-depth record was established by the Robert I. Snyder well No. 1 in Somerset County when gas was found in the Oriskany at 8,574 ft. The well had an initial open-flow after fracturing of 1,572 MCF of gas at a rock pressure of 3,293 psi in 44 hrs. Deep exploration (Middle Devonian or older) found all of the new pools and the one new field. Of the unsuccessful wildcats, 12 were new-field wildcats and 6 were new-pool wildcats. Three deeper pool tests were unsuccessful as were 10 outposts. One new-field wildcat, 8 new-pool wildcats, 1 deeper-pool test, and 3 outposts were successful. There were 61 development gas wells completed and 21 dry holes. The greatest density of deep drilling occurred in Clearfield County. There were 126 deep wells completed in Pennsylvania in 1960 with a total footage of 851,347 ft. Of the 126 wells, 74 were gas wells and 52 were dry holes. Secondary-recovery projects in the Bradford field and the development drilling in the gas fields dominated the shallow-sand drilling activity during 1960. No new shallow-sand oil or gas discoveries were made. In all, 745 shallow-sand wells were completed. Of these, 175 were gas wells, 24 were oil wells, 47 were dry holes, 2 were drilled for underground gas storage, and 497 were drilled in connection with secondary-recovery operations. In addition to the 745 wells, 42 shallow-sand wells were deepened. The total footage of the new and deepened wells was 1,578,933 ft. Oil production increased from 5,760,000 bbls. in 1959 to 5,942,000 bbls. in 1960. Proved oil reserves were estimated at 108,028,000 bbls. on December 31, 1960. Gas production increased from 118,862,000 MCF in 1959 to 119,671,000 MCF in 1960. Gas reserves were estimated at 1,192,132,000 MCF at the end of the year. Distillate produced in 1960 amounted to 67,000 bbls. The total footage drilled, both shallow and deep, was 2,430,280 ft.