Showing papers on "Petroleum reservoir published in 1976"

Relative Permeability Studies of Gas-Water Flow Following Solvent Injection in Carbonate Rocks

Abstract: Flow studies were conducted of 19 preserved cores from four oil-wet carbonate reservoirs to provide data for evaluating the water-rich, gas-injection improved recovery process. Results indicate that these cores were water repellent following displacement of oil by a solvent similar to the reservoir solvent. Restored-state tests of some of the same cores following cleaning by a polar solvent yielded water-wet flow behavior. These results indicate that tests of preserved cores are required if water-gas flow data applicable to oil-wet reservoirs are to be obtained. Water-gas relative permeability data also were obtained from preserved cores following both complete and incomplete displacement of oil by solvent. The presence of a small ''bypassed'' oil saturation significantly increased the trapped gas saturation and reduced water permeability at flood-out. Use of these data in a mathematical model of the reservoir process gave reduced water injectivities (compared with those attained during water preinjection) similar to those experienced in the field.

Altamont-Bluebell--A Major, Naturally Fractured Stratigraphic Trap, Uinta Basin, Utah

Abstract: The Altamont-Bluebell trend is composed of a highly overpressured series of oil accumulations in naturally fractured, low-porosity, Tertiary lacustrine sandstones. It now covers more than 350 sq mi (907 km2) located across the deeper part of the Uinta basin of northeastern Utah. Postdepositional shift of the structural axis of the basin in late Tertiary time produced a regional updip pinchout of northerly derived sandstones into a lacustrine "oil-shale" sequence. Facies shifts during the deposition of more than 15,000 ft (4,570 m) of lacustrine sediments have resulted in a changing pattern of reservoir distribution and hydrocarbon charge at various stratigraphic levels. About 8,000 ft (2,440 m) of stratigraphic section is oil bearing, and up to 2,500 ft (760 m) of section contains overpressured producing zones in the fairway wells. Reservoir performance is significantly enhanced by vertical fractures and initial fluid-pressure gradients, some of which exceed 0.8 psi/ft. The crude has a high paraffin content resulting in pour points above 100°F (37.78°C), gravities of 30-50° API, and an average GOR of 1,000 cu ft/bbl. This unique combination of geologic and hydrocarbon conditions makes it difficult to evaluate the ultimate recovery of the field, which could be more than 250 million bbl.

Fire control system for spray booth

Abstract: A system is provided for extinguishing accidental fires in paint spray booths of the type wherein oil is used as the medium for eliminating extraneous paint mist and overspray, said system providing control over both the oil and the medium used for extinguishing the fire In such a spray booth, oil from a self-contained reservoir located at the bottom of the booth is circulated over a plurality of baffles within the booth Paint mist is drawn by flow of air into contact with the oil covered baffles, and the paint solids are thereby entrained in the oil and collected in the oil reservoir An appropriate fire extinguishing system for such spray booth comprises a plurality of water fog nozzles within the booth that are activated in response to a fire, and which therefore discharge water into the reservoir Pursuant to the invention, means are provided to control and preserve the oil which is displaced by water accumulating in the oil reservoir, to maximize fire-fighting efficiency, and to discharge excess water from the booth while safely retaining the oil

Method of maintaining the permeability of hydrocarbon reservoir rock

Abstract: In the disclosed method, an aqueous solution of alkaline earth metal hydroxides and a salt of an alkaline earth metal is injected down a well bore and into a hydrocarbon reservoir in volume quantities sufficient to fill the pore spaces of said reservoir to some distance from the well bore. The concentration of the alkaline earth metal cations is greater than 10,000 ppm and the pH of the aqueous solution is greater than 10. The solution is forced under pressure out into the subterranean reservoir for a time period which is insufficient to consolidate sand but which is sufficient to permanently alter the properties of indigenous, intergranular clay sized particles and thereby achieve desirable permeability effects in certain fluid sensitive reservoirs. After a sufficient time period has elapsed, the well head pressure is released thereby allowing the solution to flow back into the well bore. Hydrocarbon productivity from water sensitive and low-permeable ("tight") reservoirs is improved by this method of permanently altering intergranular clays to prevent permeability reductions caused by clay migration or clay expansion.

Middle Ground Shoal Oil Field, Alaska

Abstract: Middle Ground Shoal oil field, in upper Cook Inlet, Alaska, is located beneath water with an average depth of 100 ft (30 m). The Shell MGS State No. 1, drilled in 1963, was the first offshore oil completion in Alaska. The field produces oil from a gross interval of about 2,800 ft (850 m) in the Tertiary lower Tyonek Formation. The productive interval has been separated into seven pools; the A pool is produced separately, but production from the B, C, and D and the E, F, and G pools, respectively, is commingled. Three production platforms are in use, and the field contains 31 producing wells, 23 injection wells, 1 shut-in gas well, and 8 abandoned or suspended wells. As of January 1, 1974, the field had produced 78,662,670 bbl of oil, 37,270,730 Mcf of gas, and 9,162,874 b l of water. Because of declining reservoir pressures, pressure maintenance by water injection was started in 1969. The structure at Middle Ground Shoal is a narrow anticlinal feature which strikes N10°E. Little or no paleostructural growth is thought to have occurred during deposition of the oil-bearing sandstone sequence. Channel fills and braided-stream deposits provide the reservoirs. The main productive interval in the field is the G pool, which is in the Hemlock Sandstone Member of the Tyonek.

The Walker Creek Field: A Smackover Diagenetic Trap

Abstract: The Walker Creek field, located in Lafayette and Columbia Counties, Arkansas, is the largest stratigraphic trap yet discovered in the Smackover State Line Trend. The porosity at Walker Creek is developed in an Upper Smackover oolite sequence thought to represent a regressive, high-energy shoreline deposit modified by contemporaneous structural movements associated with salt swells. The southern Persian Gulf shelf is seen as its Holocene analogue. The upper Smackover oolite reservoir is a continuous sequence of very well sorted lime grainstones containing no interstitial, low-energy lime muds. Porosity occlusion and ultimate trap formation is the result of early cementation associated with meteoric water table conditions developed during periodic exposure of the Smackover during its depositional history. The porosity-occluding early carbonate cements formed in the meteoric phreatic zone, immediately beneath the water tables, while primary porosity was being preserved in the overlying meteoric vadose zones. This primary porosity has been preferentially preserved over the active structures because vadose conditions persisted across these topographic highs for longer periods of time. Porosity distribution within the Smackover at Walker Creek, thus, is not controlled by original depositional processes--such as the pinchout of a porous sand into a lagoonal clay--but is the direct result of the early cementation history of a carbonate sand sequence that exhibited little variation in original porosity. The demonstration that Walker Creek is a "diagenetic trap" rather than a true stratigraphic trap gives the explorationist and production engineer in the Arkansas-Louisiana Smackover trend a valid alternative model to conceptualize potential reservoir characteristics.

Modeling of Noncontinuous Fort Union and Mesaverde Sandstone Reservoirs, Piceance Basin, Northwestern Colorado

Abstract: A recent FPC study indicated up to 600 trillion ft of natural gas in place in the Rocky Mt. in low permeability Cretaceous and Tertiary, nonmarine sandstones. This type of reservoir rock has been studied in the surface and subsurface in the Piceance Basin area of NW. Colorado. The sandstone geometry and orientation are characterized. A random intersection technique is developed that utilizes the geological information to generate a spectrum of reservoir models that may be used to simulate the performance of hydraulically and nuclearly fractured wells. An example reservoir model for a nuclear fractured well is compared with a reservoir model for a nonfractured well. In general, the point-bar sandstones can be simulated by radial models and the channel sandstones by linear models. (23 refs.)

Upper Smackover Reservoirs, Walker Creek Field Area, Lafayette and Columbia Counties, Arkansas

Abstract: This study has made possible the zonation of two major upper Smackover reservoirs productive at Walker Creek field, Lafayette and Columbia Counties, Arkansas, and a reconstruction of the depositional environments that were present contemporaneously throughout this area. Petrographic examination of etched core plugs, petrographic-microscope studies of thin sections, core descriptions, and consultation with authors of published papers permitted a grouping of upper Smackover carbonate rocks into facies more or less environmentally controlled and similar to those already established in the literature. Minor changes in petrographic groupings were necessitated by the additional data and the numerous core descriptions incorporated in this paper; otherwise, the facies groupings of W. F. Bishop generally have been followed. Distribution of nonskeletal particles in the sea which existed during deposition of the upper Smackover in this area resembled in many aspects that at the present northeastern tip of Yucatan. The presence of discrete sandstone bodies and their carbonate equivalents permitted lithologic markers to be correlated throughout this area of predominantly carbonate deposition, resulting in a unique interpretation of depositional environments. Major zonations of oolite bars have been confirmed by pressure data, and dense dark limestones useful as a diagnostic facies appear to have environmental significance. Certain diagnostic phenomena disclosed in thin-section analysis indicate possible eolianite lithification in the vadose or phreatic zone. The Walker Creek field produces from a structurally controlled stratigraphic trap containing nearly 100 million bbl of oil in place plus 100 Bcf of recoverable gas.

In-Situ Determination of Residual Gas Saturation by Injection and Production of Brine

Abstract: A new in-situ procedure has been developed for measuring the residual gas saturation in watered-out zones of gas reservoirs. Gas-free formation brine is injected into a well penetrating the water-invaded zone to dissolve the residual gas from a region around the wellbore. The brine is then produced from the well. The volume of brine containing no dissolved gas is then determined by sampling the brine and analyzing for gas content. The original residual gas saturation can be calculated from these data. The procedure has been confirmed by computer simulation and by laboratory tests on a long glass-bead pack. Two full-scale field tests have also been conducted; the interpretation of one of these tests is discussed in detail.

Hilight muddy field - lower cretaceous transgressive deposits in the powder river basin, wyoming

Abstract: Thin sandstones of the Lower Cretaceous Muddy Formation at an average depth of 9,400 ft produce oil from a stratigraphic trap at Hilight field, Campbell County, Wyoming. The Muddy section is generally of low permeability, but the best reservoirs have effective porosity of 16.7% and average permeability of 115 md. The reservoir is expected to yield an ultimate recovery of more than 80 million bbl of oil. Sedimentary structures and petrographic analyses show that Muddy sandstones were deposited in beach, lagoonal, and fluvial environments. Porous sandstones average less than 10 ft and rarely attain 20 ft in thickness. Lower Muddy sandstones are fluvial. These fluvial sandstones are associated with shales and siltstones that are highly carbonaceous and were deposited in poorly drained marshes. Upper Muddy sandstones are mostly beach or lagoonal in origin. (11 refs.)

Jay Field, Florida--A Jurassic Stratigraphic Trap

Abstract: The first Jurassic oil discovery in Florida was made in June 1970, in Santa Rosa County near Jay, 35 mi (56.3 km) north of Pensacola. Current estimates indicate recoverable reserves in the Smackover Formation of 346 million STB of oil and 350 Bcf of gas. The accumulation occurs on the south plunge of a large subsurface anticline, and the updip trap is formed by a facies change from porous dolomite to dense micritic limestone. The Smackover consists of a lower transgressive interval of laminated algal-mat and mud-flat deposits and an upper regressive section of hard-pellet grainstones. Early dolomitization and freshwater leaching have provided a complex, extensive, high-quality reservoir. Irregular distribution of facies presents difficult problems in development drilling, unitization, and pressure-maintenance programs. Hydrogen sulfide content of the hydrocarbons requires expensive processing facilities and well investment. A typical completed well costs $650,000, and an additional $200,000 is required for flow-line and inlet separation facilities. Add to this $550,000 for plant facilities to sweeten the oil for market, and each well investment approaches $1,400,000. Daily production from Jay field is 93,500 bbl from 89 wells. The rapid development of this field resulted from a drilling program coordinated with modular plant design.

Sunoco-Felda Field, Hendry and Collier Counties, Florida

Abstract: Sunoco-Felda field is located on the South Florida shelf, on the northeastern flank of the South Florida embayment. Production is principally from a stratigraphically trapped oil accumulation in a reefoidal, algal-plate, gastro-pod-bearing limestone mound in the Sunniland Limestone of Early Cretaceous age. The discovery well was drilled in July 1964 by Sun Oil Company on the basis of a combination of regional subsurface geology and geophysical work. The oil reservoir is about 11,475 ft (3,500 m) below the surface and is characterized by excellent vuggy porosity ranging upward to 28 percent; maximum permeability reaches 665 md. The field has a 34-ft (10 m) oil column and encompasses a surface area of approximately 4,500 acres (18 km2). In-place oil reserves are stimated to be 44 million bbl. The South Florida shelf area is sparsely drilled and offers great potential for the discovery of additional fields the size of Sunoco-Felda field. The subtle expression of this type of low-relief feature in the subsurface requires the complete coordination and application of sophisticated geological and geophysical techniques in order to provide a successful and economically attractive exploration program.

Trapping Mechanisms for Oil in Lower Cretaceous Muddy Sandstone at Recluse Field, Wyoming

Abstract: Muddy sandstones form lenticular reservoirs that contain water at both the up-dip and down-dip margins. As in many other stratigraphic traps, oil is produced in the central part of the reservoir where permeability is higher, whereas only water occurs at the margins where permeability is reduced. Consequently, wells that produced oil at the rate of 1800 bbls per day were offset by tests that recovered water at the rate of 1800 bbls per day from the same sandstone and at the same elevation. The principal Muddy reservoirs are of two types. One is a narrow, sinuous, fluvial sandstone body of limited extent. The other is a fine-grained sandstone that was deposited close to the shoreline during a marine transgression, and this sandstone forms wider, ovate bodies parallel to strike. In the latter section, grain size and quartz content decrease upward while clay matrix and bioturbation increase upward. Similar changes occur laterally so that permeability is reduced from an average 400 md to 17 md or less at the margins of the field. Lateral changes within the reservoir are confirmed by interpretation of logs and cores, and by analysis of shut-in pressures from drill-stem tests. The distribution of oil and water within the reservoir can be accounted for by capillary-pressure and potentio-metric gradients. The observed oil column is somewhat greater than 130 ft. Calculations show that about 20 ft. was trapped by capillary-pressure changes where permeability is reduced, and 110 ft was trapped by down-dip hydrodynamic flow. These calculations explain the recovery of water adjacent to oil production and suggest that fluid pressure relationships should not be neglected in either exploration for or development of stratigraphic traps.

Multiple phase behavior in porous media during CO/sub 2/ or rich gas flooding

Abstract: Mixing of oil with high ethane content hydrocarbon gases or CO/sub 2/ can produce multiple liquid phases and an asphaltic precipitate in low temperature reservoirs. The residual saturation that occurs in a reservoir displacement is not greatly significant from a recovery standpoint, but may produce 3-phase relative permeability effects which reduce injectivity and, thus, oil recovery rate during alternate gas-water injection.

Flow Heterogeneity in Reservoir Rocks

Abstract: A study by Chevron Oil Field Research Co. shows that microscopic flow heterogeneity values are essential for interpreting laboratory displacement data and properly evaluating field displacement projects. Chevron discusses microscopic flow heterogeneity in reservoir rocks: a measuring method, results of some measurements, and several applications to reservoir engineering problems. Heterogeneity is expressed in terms of both breakthrough recovery and the Dykstra-Parsons permeability variation. Microscopic flow heterogeneity in a reservoir rock is related to pore size, pore shape, and location of the different pore sizes that determine flow paths of various permeabilities. This flow heterogeneity affects secondary recovery displacement efficiency, residual oil and water saturations, and capillary pressure measurements.

Permian and Lower Triassic Reservoir Rocks of Central Utah

Abstract: Permian and Lower Triassic reservoir rocks throughout central Utah consist of beach and shallow water sandstones and shallow marine carbonates. These reservoirs are the Permian Cedar Mesa Sandstone, Toroweap Formation, White Rim Sandstone, Kaibab Formation, and the Lower Triassic Sinbad-Timpoweap carbonate member of the Moenkopi Formation. Depositional patterns of these stratigraphic units are controlled by the relative positions of the Oquirrh and Bird Spring basins and the Emery uplift which separates the 2. Hydrocarbon shows are found in all of the reservoirs, but generally increase in abundance upward in the stratigraphic sequence and the upper 2, the Kaibab and Sinbad, both produce commercial oil.

Recent Developments in Sunniland Exploration of South Florida

Abstract: The Sunniland Formation is a wedge of carbonates and anhydrites of Late Trinity, Early Cretaceous age. To date, it is the only productive formation in South Florida. The first test that penetrated the Sunniland Formation (1943) became the discovery well for Sunniland Field. Wildcat activity during the next 20 years averaged three wells per year and resulted in only one non-commercial discovery. In 1964, after the discovery of the Sunoco-Felda field, wildcat activity tripled averaging nine tests per year. Six additional discoversies occured between 1966 and 1975. Daily production climbed from 1,300 barrels of oil per day to the present 13,000 barrels of oil per day. Cumulative production through 1964 was 8,000,000 barrels of oil, and by the end of the 1975 totaled 42,000,000 barrels of oil. The main reservoirs are found in the upper part of the Sunniland Formation (average depth 11,500) in porous and permeable skeletal-pelletal carbonates. These shelf carbonates were deposited in beach and shoal-type environments along a northwest-southeast trending band. Updip from this favorable trend, the carbonates become micritic-skeletal with resulting low permeabilities. An anhydrite facies is present downdip. Regional dip is a gentle 1/2° and known structures are low relief. Hydrocarbon accumulations are both structurally and stratigraphically controlled with structure being the most important factor. The increase in exploration during the past 11 years in South Florida can be attributed to several factors. Additional well control has provided necessary data for a better understanding of stratigraphy. This new information has also permitted a realistic understanding of the Sunniland Formation's potential as a hydrocarbon reservoir. Initial production of 300-500 barrels of oil per day is typical. Production history indicates that many wells will ultimately produce in excess of 1,000,000 barrels of oil.

Analysis of Pressure Transient Data in Naturally Fractured Reservoirs With Spherical Flow

Abstract: Methods for analysis of pressure transient performance in homogeneous reservoirs with spherical flow have been presented by others in the past. This work extends the art to the case of naturally fractured reservoirs with uniform fracture distribution. A reservoir model similar to the double-porosity system described by Warren and Root is employed. The fundamental differential equation and the solution of the equation by the application of the Laplace Transformation serves as the theoretical foundation. A method is then presented for estimation of an average spherical permeability and static reservoir pressure. Also the procedure for estimation of total fluid capacitance (phi/sub 2/C/sub 2/ + phi/sub 1/C/sub 1/) and the fraction of which being contributed by the fracture network (..omega..) is discussed.

Reservoir Variations At Upper Valley Field Garfield County, Utah

Abstract: The Upper Valley field, Garfield County, Utah, is the only significant production found to date in the Kaiparowits Basin of S.-central Utah. Cumulative production to Jan. 9176 is 14.9 million bbl of oil from 4 distinct zones within the Triassic Timpoweap and Permian Kaibab formations. All of the reservoirs are carbonates which have been dolomitized to varying degrees and were deposited in environments ranging from supratidal to shallow marine. Significant facies variations and diagenetic alterations are present in all 4 reservoir zones and have affected distribution of porosity, permeability, and fracturing. Production has been offset along the western flank and down the southern plunge of the Upper Valley anticline by a hydrodynamic drive that appears to have created a curvilinear oil-water contact due to variation in the densities of the crude within the field. The accumulation has been further complicated by an apparent lack of hydrocarbon charge along certain portions of the structure in the main pay zone.

Geotechnical studies of geothermal reservoirs

Abstract: It is proposed to delineate the important factors in the geothermal environment that will affect drilling. The geologic environment of the particular areas of interest are described, including rock types, geologic structure, and other important parameters that help describe the reservoir and overlying cap rock. The geologic environment and reservoir characteristics of several geothermal areas were studied, and drill bits were obtained from most of the areas. The geothermal areas studied are: (1) Geysers, California, (2) Imperial Valley, California, (3) Roosevelt Hot Springs, Utah, (4) Bacca Ranch, Valle Grande, New Mexico, (5) Jemez Caldera, New Mexico, (6) Raft River, Idaho, and (7) Marysville, Montona. (MHR)

Recent Knowledge of Hydrocarbon Potentials in Sedimentary Basins of Indonesia: Hydrocarbons

Abstract: Although the search for hydrocarbons in Indonesia was initiated about 8 decades ago, exploration work is still at a high level. Recent studies have resulted in a new understanding of the Tertiary sedimentary basins, and knowledge concerning offshore sedimentary basins has been updated significantly. More important, however, is the current knowledge of the mechanisms of basin formation which seems to enhance the validity and applicability of the new global tectonics to the geology of Indonesia. Recent exploration surveys and subsequent drilling have shown that the southern part of the Sunda Shelf consists of many sedimentary basins and intervening uplifts. Major faults are common throughout the area and clearly control the distribution and shapes of the basins. Block faulting apparently broke up the periphery of the Sunda Shelf at the beginning of Tertiary time. The chief crude oil production in western Indonesia is from the regressive and deeper transgressive sandstone series of Oligocene-Miocene age, except in East Kalimantan, where producing zones range from Eocene to Pliocene. Prospective areas have changed considerably since oil and gas in economic amount have been proved from an interbedded limestone formation of Tertiary age. Additional reserves are anticipated in stratigraphic traps. Oil and gas discoveries within deltaic sandstones, notably in East Kalimantan, have upgraded significantly the onshore and offshore potentials of the area. Carbonate rocks are becoming a prime objective in the search for oil, especially in the East Java-Madura basinal area. Although eastern Indonesia was chiefly the site of late Paleozoic and Mesozoic sedimentation, oil has been proved only within the strata of Tertiary age, notably in the Salawati basin. Of particular importance was the recognition of the tremendous potential that reefs, particularly Tertiary reefs, possess as hydrocarbon reservoirs. A similar basin and environmental model is anticipated for the Bintuni basin. Recent scientific cruises have indicated the presence of several potential basinal areas between the Sunda and Sahul Shelves. The sedimentary basins in Indonesia can be classified as arc-front, foreland, and deltaic basins.

Oil fields of the greater Pittsburgh region

Abstract: Westmoreland County is the only county that has not had considerable crude oil production from the 92 oil reservoirs in the 6-county area of the Greater Pittsburgh Region. All 6 counties have produced large volumes of gas. This report deals only with the oil reservoirs. The McDonald field and Washington-Taylorstown field have secondary recovery gas drive projects in operation. Both projects have been very successful. This study shows that there are still too many unknowns with respect to the reservoirs for accurate determination of the secondary reserves of crude oil. Therefore, the proven reserves to the year 2000 were estimated by extrapolating the production decline curve for each county. Additional gas drive projects and successful water flooding would increase the proven reserves in the area dramatically. Preliminary studies indicate that oil saturations in these reservoirs are higher than those in the reservoirs of the Middle District of Pennsylvania consisting of Clarion, Forest, and Venango counties. (38 refs.)

Application of radial simulation model

Abstract: A radial simulation model has been developed to study low-permeability reservoirs, particularly for gas storage. The radial simulation model gives understanding of the pressure distribution within the blocks or segments normally used for areal simulation. This paper describes the nature of the radial simulation model prepared and gives the results of two studies. The first study has to do with finding the pressure at a specific location within a tight storage reservoir where a well has been plugged with some uncertainty as to the quality of the well plugging operation. Taking data from operation of adjacent wells, a calculation is made to give some indication of the pressure rise that takes place during the injection cycle in this reservoir. The second study has to do with a storage field having a relatively poor reservoir in that it has low thickness and low permeability for some of the storage wells inside the field, and this formation is believed to occur at the edge of the field in some cases. The study here shows the effect of well spacing on the cushion gas starting with an original reservoir pressure and using a storage cycle with a delta pressure up to 1,200 psimore » as compared with a discovery pressure of 1,540 psia (0.33 psi/ft). The effect of annual cycle proposed for the storage reservoir on the increase in cushion gas that occurs for various well spacings show that a 700-ft, 40-acre spacing is needed for not leaving a large quantity of cushion gas in the reservoir. Studies on the effect of gas migration into the surrounding area indicate that 1.2 MMcf of gas may be migrating away from the storage reservoir each year on a 700-ft radius area at the edge of the field.« less

Influences of Diagenetic Environment on Porosity and Permeability of Holocene and Pleistocene Corals: GEOLOGIC NOTES

Abstract: Changes in effective porosity and permeability during diagenesis in Holocene and Pleistocene corals from the Bahamas and Florida Keys are influenced by environmental and, to some extent, by taxonomic variations. Submarine and vadose samples show a decrease in permeability during porosity reduction by cementation, whereas phreatic samples increase in permeability with decreasing porosity because of larger and better sorted pore apertures. As a result, reef rock built mainly of corals may be a better reservoir rock if it has undergone diagenesis in the phreatic zone rather than in the submarine or vadose environments.

Interpretation of Bottom-Hole Pressure Build-up Tests on Fractured Oil Reservoirs

Abstract: A procedure is developed to analyze pressure buildup curves where radial flow theory does not apply. In a vertically fractured system, which is present in most West Texas carbonate reservoirs, flow in the region nearest the fracture is essentially linear, whereas, further out in the formation, radial flow normally prevails. Historically, interwell flow capacity, fracture length, wellbore damage and static pressure have been determined using the late time slope from pressure log time curves. This solution is based on a radial flow model and, as a result, most of the computed reservoir parameters are in error. A set of guidelines are established to allow uniform interpretation of pressure buildup curves and to determine the best workover candidates for fractured oil reservoirs. Field examples representing four basic cases are also presented.

Aspects of numerical simulation of future performance of geopressured geothermal reservoirs

Abstract: Differential equations describing momentum and energy conservation in geopressured geothermal reservoirs are developed. Such reservoirs are known to be abundant in the Gulf Coast region of the United States. Effects considered in the development of these equations include heterogeneous and anisotropic porous media, water influx from adjacent compacting shales and clays, and reservoir rock compaction as a result of reservoir fluid withdrawal. The equations describe the behavior of the water and gas phases in the reservoir fluids and the behavior of the rock matrix. Constitutive equations describing the effects of pore pressure changes on reservoir parameters are also presented. The equations can serve as the basis for development of computer models of the geopressured geothermal reservoirs. One such model is described. This model simulates momentum conservation of the water phase in geopressured reservoirs. Finite difference techniques are used to solve this equation. Simulation studies of a hypothetical geopressured reservoir demonstrate the difficulties of determining reservoir parameters from short term single well tests. However, they do indicate that such reservoirs are capable of sustaining fluid production for a number of years at significant rates.