Showing papers on "Petroleum reservoir published in 1975"

Capillary Pressures in Stratigraphic Traps

Abstract: Capillary pressures between oil and water in rock pores are responsible for trapping oil, and the height of oil column, zo, in a reservoir may be calculated from the Hobson equation modified as follows: [EQUATION] where ^ggr is the interfacial tension between oil and water, rt is the radius of pore throats in the barrier rock, rp is the radius of pores in the reservoir rock, g is acceleration of gravity, and ^rgrw and ^rgro are the densities of water and oil, respectively, under subsurface conditions. To apply the equation, pore sizes must be estimated from mean effective grain sizes of the reservoir and barrier rocks. Effective grain size, De, in centimeters can be approximated from core analysis data by means of an empirical permeability equation from which [EQUATION] where n is porosity in percent and k is permeability in milli-darcys. Then pore and throat sizes may be estimated as functions of mean effective grain size as based on theoretical packings of grains. The oil-column equation assumes hydrostatic conditions, and additional column, ^Dgrzo, may be trapped if hydrodynamic flow occurs down the dip from barrier to reservoir facies, or [EQUATION] where dh/dx is the potentiometric gradient and xo is the width of the oil accumulation. Calculations of oil columns in stratigraphic fields show that the equations give values which are in fair to good agreement with observed oil columns; that porous and permeable, very fine-grained sandstones and siltstones are commonly effective barriers to oil migration; and that the recognition of such barriers can be important in exploration for stratigraphic traps.

Trapped gas saturations in carbonate formations

Abstract: Trapped gas saturations existing after gas displacement by wetting phase imbibition are presented for selected carbonate reservoirs Formations representing various rock types were investigated, and samples covering the porosity and permeability range within each field were tested Cores from Smackover reservoirs located within 4 states were included to examine differences in trapped gas which might occur within a carbonate deposited over a large geographical area The trapped gas varied with initial gas in place and with rock type With gas in place of 80% of pore space, trapped gas values ranged from a low of 23% of pore space in Type II chalk to a maximum of 69% in the Type I limestone evaluated Correlation of trapped gas saturation values was attempted using several approaches, but none was entirely satisfactory No relationship with permeability was found within most reservoirs, or between different reservoirs Within a given field, trapped gas at a common initial gas saturation typically increased as porosity decreased

Flat spot exploration

Abstract: The hydrocarbon-brine contact produces a flat reflection, unconformable with the lithologic reflections from the trap boundaries, and over a limited area bounded by structural contours. When it can be reliably detected and mapped, the flat spot can provide (i) a reasonably unambiguous indication and areal extent of a reservoir and (ii) an estimate of reservoir thickness. The gas-brine contact in thick reservoirs in offshore elastic sections is the easiest target. An example of gas mapping is presented in the paper. Other reservoirs represent a continuum of increasingly elusive targets. Increasing the range of applicability of flat spot exploration will require (i) increases in signal/noise and multiple ratio, increases in the three dimensional depth point density (or grid density), increased resolution and static and dynamic correction accuracy, and (ii) processing and interpretation aimed directly at flat spot mapping. Low relief structural and stratigraphic traps should provide the most attractive targets. The approach should be at least theoretically feasible, though not necessarily cost effective, for most major reservoirs with a well-behaved hydrocarbon brine contact.

Numerical Simulation of Oil Production With Simultaneous Ground Subsidence

Abstract: A 2-phase, 2-dimensional black oil simulator was developed for simulating reservoir production behavior with simultaneously occurring reservoir formation compaction and ground subsidence at the surface. The simulator was designed in particular for application to the Bolivar Coast fields of W. Venezuela, where extensive ground subsidence has been in evidence for many years. The flow equations were solved by both ADIP and SIP (Strongly Implicit Procedures). Reservoir compaction was described on the basis of the experimental data reported to date. The magnitude of areal subsidence at the surface was calculated using reservoir compaction, utilizing the recently developed theory of poro-elasticity. The model was employed for generating the reservoir formation profiles, as well as the ground subsidence bowls for a variety of conditions. It was found that the subsidence behavior strongly depends on the depth of burial. For example, with an increase in the depth, the reservoir bottom surface may actually uplift, while the top surface subsides. (21 refs.)

Geologic Factors Controlling Crude Oil Composition in Australia and Papua, New Guinea

Abstract: A geochemical survey of both commercial and noncommercial crude oils in Australia has shown them to be predominantly paraffinic or paraffinic-naphthenic in composition. High wax contents are common. A close stratigraphic control on crude oil type operates in the Perth and Carnarvon basins of Western Australia. The chemical character of Australian oils can be related to their sedimentary environments, which range from lacustrine to nearshore marine. Spores, pollen, and cuticles derived from land plants have been a major source for the hydrocarbons. Apart from changing the relative proportions of the different boiling fractions, maturation has had little effect on the basic composition of the oils. Alteration of crude oil by water washing and microbial activity in the reservoir is rare but, in several oil accumulations, light fractions are thought to have been mobilized by gas invasion of the oil reservoir. Other differences in crude oil composition can be attributed to variations in microbial activity during early diagenesis of the organic source material.

The Role of Geology in Reservoir Simulation Studies

Abstract: Reservoir simulation models are becoming more and more sophisticated as a result of improved technology and in response to the need to reduce costs and improve hydrocarbon recovery. The improved technology has resulted in part from the development of capabilities for more precise reservoir description, including both the geological and engineering aspects of description. Increased precision in the geological contribution results from (1) improved knowledge of the geologic controls on reservoir rock properties, (2) better methods for synthesizing and quantifying geologic data, and (3) the experience gained from joint engineering-geologic projects. (11 refs.)

Altamont-Bluebell: A Major Fractured and Overpressured Stratigraphic Trap, Uinta Basin, Utah

Abstract: 1 ABSTRACT Altamont-Bluebell trend is composed of a highly overpressured series of oil accumulations occurring in naturally fractured, low-porosity, Tertiary lacustrine sandstones. Post-depositional shift of the structural axis of the basin in late Tertiary time produced a regional updip pinchout of northerly Jerived sandstones into a lacustrine "oil-shale" sequence, Facies shifts during the deposition of over 15,000 feet of lacustrine sediments result in a changing pattern of reservoir distribution and hydrocarbon charge at various stratigraphic levels. Approximately 8,000 feet of stratigraphic section is oil-bearing, and up to 2,500 feet of section contains overpressured producing zones in the fairway wells. Reservoir performance is significantly enhanced by vertical fractures and initial fluid pressure gradients which sometimes exceed 0.8 psi per foot. The crude has a high parafin content, resulting in pour-points over 100" F, .gravities of 30" to 50" API, and an average GOR of 1,000 cubic feet per barrel. This unique combination of geological and hydrocarbon conditions makes it difficult to estimate ultimate recovery, which could be in excess of 250 million barrels.

The Successful Use Of The Borehole Gravity Meter In Northern Michigan

Abstract: Borehole gravity surveys have been used in Northern Michigan to make producers out of otherwise dry holes. Wells which are drilled in thick, tight, salt-plugged reefs may have encountered a very restricted, tight facies. The borehole gravity survey can be used to detect nearby porosity. Such porosity zones can be entry beds to the main reservoir. The basis for qualitative interpretation is to determine the sidewall lithology and then evaluate which rock parameters could vary laterally to change bulk density. Porosity changes produce distinct low density deflections on gravity log plots. The bases for quantitative evaluations are the results of computer models or of simple cylindrical models. The maximum distance to a porous zone can be calculated using a cylindrical or ring-shaped model.

Petroleum Geology of East-Central Utah and Suggested Approaches to Exploration

Abstract: The Paradox fold and fault belt dominates the central part of east-central Utah. The Uncompahgre Uplift borders the area on the northeast, the San Rafael Swell on the northwest, the Henry Mountains basin on the west, and the Monument Upwarp is on the south edge. During Cambrian, Devonian, and Mississippian time the area was a shallow shelf marginal to the Cordilleran geosyncline to the west. The Cambrian and Devonian rocks are predominantly sandstone, shale, and carbonate, whereas the Mississippian strata are chiefly dolomite and limestone. Paleotectonism had an influence on both Devonian and Mississippian stratigraphy and petroleum entrapment. During Pennsylvanian time the ancestral Uncompahgre Uplift shed coarse arkosic clastics to the southwest into the northwest-trending Paradox Basin. Saline rocks were deposited in this trough in response to eustatic changes of sea level coupled with an arid climate. Subsequent salt flowage resulted in the formation of numerous northwest-trending salt anticlines. Pennsylvanian algal, bioclastic, and oolitic carbonate reservoirs were deposited along the shelf margins of this basin. Marine carbonates and sandstones of Permian age intertongue with continental red beds to the east. Triassic and Jurassic strata are dominantly continental red beds with a few eastward-terminating marine tongues. A thin sequence of Lower Cretaceous continental clastics was deposited, followed by a thick sequence of Upper Cretaceous marginal-marine sandstone and open-marine shale. Potential hydrocarbon source beds are present in east-central Utah in Paleozoic and Mesozoic marine deposits. Mississippian and Permian organic-rich shales are present west of the study area and may have supplied petroleum to Mississippian and Permian reservoirs in the area by long-range migration. Only 2.2 percent of the area has been explored by drilling to the Mississippian and Devonian. Most of the production from the six oil and gas fields in the area is from Mississippian carbonate reservoirs located on paleostructure beneath a disconformable cover of Pennsylvanian saline deposits. The area is an underachiever in terms of the abundance of oil shows in relation to the petroleum reserves discovered. This abundance of shows is related to regional paleotectonic tilt that varied both in degree and direction throughout geologic time. Generated oil moved back and forth in reservoirs leaving residual shows. The suggested exploration approach is the careful mapping of paleomigration paths after typing oils to source beds and determining the time of hydrocarbon generation. The most easily defined prospects are those where isolated reservoir porosity and permeability are developed in proximity to source beds. The Pennsylvanian provides the best potential for this type of prospect. East-central Utah has potential for major reserves of petroleum and is only sparsely explored. Stratigraphic traps have the greatest potential.

Analysis of internal steam drive in geothermal reservoirs

Abstract: Petroleum reservoir analysis methods are applied to simple closed geothermal reservoirs that produce by internal steam drive. Relations are presented for the reservoir temperature, pressure, and fluid saturations, with the assumption that the fluids are produced according to their respective relative permeabilities. Calculated performances are given for various types of reservoirs. Results indicate that hot-water reservoirs can have complicated behaviors, including changing from production of hot water to dry steam.

Monitoring acoustic emission from propagating fractures in petroleum reservoir rocks

Abstract: The results presented here are from a continuing petroleum reservoir stimulation research program at the Morgantown Energy Research Center (MERC) of the U.S. Government Energy Research and Development Administration (ERDA). The research pertains to hydraulic fracturing of oil and gas reservoir rocks with specific emphasis placed upon the acoustic mapping of induced fracture orientations, lengths and rates of propagation, and the mechanisms governing fracture propagation in oil and gas reservoirs. Information presented here is based upon a field experiment for acoustically mapping hydraulic fractures, and laboratory studies on acoustic emission from fracture initiation and growth in reservoir rocks. The field experiment was conducted in a petroleum reservoir in Bradford, Pa. Twelve hydrophone type sensors were placed at the oil bearing rock elevation of 2,030 feet from the surface in adjacent wells surrounding the fractured well. Complete directional acoustic velocity distribution and acoustic background noise levels were evaluated. The resulting measurements made during the hydraulic fracture mapping experiment, data analysis techniques and problems are discussed. Instrumentation developed and used in the data reduction and analysis is described. Laboratory hydraulic fracture stimulation experiments conducted in reservoir rocks are discussed with a description of techniques, instrumentation, and data analysis included.

Low-cost but accurate radioactive logging for determining gas saturation in a reservoir

Abstract: A method is disclosed for determining gas saturation in a petroleum reservoir using logging signals indirectly related to the abundances of oxygen and carbon nuclei in the reservoir rock The first step of the invention is to record first and second logs sensitive to the abundance of oxygen and carbon nuclei, respectively, after the region surrounding the well bore is caused to have fluid saturations representative of the bulk of the reservoir A purposeful change is then made in the fluid saturations in the region surrounding the well bore by injecting a liquid capable of displacing substantially all of the original fluids The logs are recorded a second time The displacing fluid is then itself displaced by brine, and a third suite of logs is recorded The total fluid and oil saturations are then determined from the differences between respective corresponding logs and from known fractional volume oxygen and carbon contents of the reservoir brine and oil and the first injected liquid Gas saturation is then calculated from differences between total fluid and oil saturation values It is not necessary that the log responses be independent of the material in the borehole, the casing, the casing cement, or the reservoir rock It is only necessary that changes in formation fluids content cause proportional changes in log responses

El Agreb--El Gassi Oil Fields, Central Algerian Sahara: GEOLOGIC NOTES

Abstract: About 50 mi south-southwest of the Hassi Messaoud field, a group of three fields, El Agreb, El Agreb Northeast, and El Gassi, is located in separate structural highs on the faulted El Agreb--El Gassi anticline which is on the same major pre-Hercynian anticlinorium as is Hassi Messaoud. The El Agreb--El Gassi structure is a northeast-southwest-trending anticline divided into separate blocks by northwest-southeast-trending faults. It is on the western side of the major ancient Hassi Messaoud anticlinorium which separates the Algerian Sahara into western and eastern basins. The high was formed at the end of the Paleozoic, during the Hercynian orogeny. The Gotlandian (Silurian), the Ordovician, and the upper part of the Cambrian are eroded over the crest of the high in this area and in Hassi Messaoud. Later local movements, attributed to the Austrian orogeny, have affected the southern part of the El Agreb field, the southernmost field of the group, and have uplifted the area northeast of the northernmost El Gassi field. The Cambrian quartzitic sandstone, Hassi Messaoud Sandstone, is the reservoir rock of El Agreb--El Gassi fields. The thickness of the reservoir varies, but averages 400 m.

Some fundamental problems of formation evaluation in the North Sea

Abstract: In all but a very few causes, it is possible to recognize prospective hydrocarbon-bearing intervals from a modern logging program. In many North Sea reservoirs, however, it is necessary to pursue an extensive program of coring and wireline or other production testing in order to arrive at acceptable estimates of petrophysical quantities for reserves and field development calculations. Some fundamental log interpretation problems are explained; and where possible, methods and procedures are suggested which may lead to their solution. These problems include: (1) resistivity measurement in sea water muds opposite low resistivity sands; (2) hydrocarbon saturation determination in clastics containing conductive solids and relatively fresh formation water. A method of applying the Waxman-Smits equation is suggested. The very low apparent oil saturations in productive Jurassic conglomeratic facies are also discussed; (3) distinction of gas from oil by logging methods, where radioactive minerals in the sands preclude use of the gamma ray log to correct for shaliness; and (4) chalky limestone evaluation, especially the need for a logging method of deriving permeability in relatively high porosity, indeterminate productivity reservoirs.

Review of the palaeozoic stratigraphy and petroleum potential of northern south australia

Abstract: The Amadeus, Warburton, Officer, Adavale, Arckaringa, Pedirka, Cooper and Great Artesian Basins form a complex system of overlapping basins in central Australia. Cambrian rocks are widespread in the Amadeus, Warburton and possibly the Officer Basins and are marked by the major role of carbonate deposition. Gas and oil shows are known from the Amadeus and Warburton Basins. In South Australia their reservoir potential lies in shoreline clean-up of generally dirty marine sandstones and porosity-permeability associated with archaeocyathid bioherms or dolomitization of limestones. The Ordovician rocks follow the widespread distribution of the Cambrian rocks and are distinctive for thick quartzites and graptolitic shales. In South Australia, the Warburton and Officer Basins may have facies developed which are similar to the Pacoota and Stairway Sandstones, the reservoir rocks for the Amadeus Basin gas and oil fields. Large anticlinal structures have recently been suggested by S.A. Mines Department geophysical work in the Officer Basin which enhances the potential. Red beds are distinctive in the Devonian System. Deposition apparently spilt into the peri-Musgrave Block area and the Adavale Basin to Innamincka area. A thickness of over 3 000 metres of Devonian rocks was drilled in the Officer Basin which contained some reservoir rock lithology. The petroleum potential in South Australia is relatively unattractive. Some 3.4 trillion cu ft of deliverable gas reserves have been established already in the Permian sediments of the Cooper Basin which are up to 900 m thick. The Early Permian sediments of the Pedirka Basin which may be at least 500 m thick may hold similar petroleum potential.

Method of producing hydrocarbons from an unconsolidated formation

Abstract: This specification discloses a method of producing hydrocarbons from an unconsolidated hydrocarbon-bearing formation that is penetrated by a well that has an irregular wall adjacent the formation. Granular particles that are water-wet are injected down the well to fill the irregularities in the wall and a packer that has lateral passageways therethrough is set against the well wall. Pressure is applied via the packer to the formation in an amount no greater than the overburden pressure on the formation and hydrocarbons are produced from the formation via the lateral passageways of the packer into the well.

Radioactive logging for determining oil saturation in a reservoir

Abstract: A method is disclosed for determining oil saturation in a petroleum reservoir using logging signals indirectly related to the abundance of carbon nuclei in the reservoir rock. The first step of the invention is to record a log sensitive to the abundance of carbon nuclei after the region surrounding the well bore is caused to have oil saturations representative of the bulk of the reservoir. A purposeful change is then made in the fuel saturations in the region surrounding the well bore by injecting a liquid capable of displacing substantially all of the original fluids. The log is recorded a second time. The displacing fluid is then itself displaced by brine, and a third log is recorded. Oil saturation is then determined from differences between the logs and from known fractional volume carbon contents of the reservoir oil and the first injected liquid. It is not necessary that the log responses be independent of the material in the bore hole, the casing, the casing cement, or the reservoir rock. It is only necessary that changes in oil content cause proportional changes in log response.

Stratigraphic section of part of the Green River Formation and underlying units exposed in Tommys Draw, western Piceance Creek Basin, Colorado

Abstract: Lithologic descriptions are given for the uppermost Mesaverde Formation, the Ohio Creek, and Wasatch Formations, and most of the Green River Formation exposed along left, middle, and right forks of Tommys Draw, Rio Blanco County, Colorado.

Effect of gas pressure maintenance on the recovery of the Iranian fractured limestone reservoirs

Abstract: The nature of Iranian fractured reservoirs and the mechanisms of oil recovery are briefly described. The variation of interfacial tension with pressure and its effect on capillary pressure are discussed in some detail. Because gravity drainage is the main mechanism of oil recovery from the limestone blocks in these reservoirs, the final oil recovery from the blocks in the reservoirs is badly hampered as reservoir pressure drops. Therefore, by increasing the reservoir pressure to its original pressure, extra recovery from the same blocks can be recovered due to the above process as well as swelling of oil. This excess oil recovery in some cases may be as high as 100% of oil recovery by natural depletion. The composition of gas to be injected also is important in the above process, since it affects the gas-oil interfacial tensions. However, this has to be studied in the laboratory for each reservoir. The concept of capillary pressure reductions by reducing interfacial tension due to the increase of pressure also is applicable to sandstone reservoirs where gravity drainage significantly contributes to the oil recovery.

Pressure Responses From Induced Hydraulic Fractures in Adjacent Wells Within a Petroleum Reservoir: An Experiment

Abstract: Pressure responses from induced hydraulic fractures in five adjacent oil wells were monitored by 40 wells within the petroleum reservoir in northern Pennsylvania. The multisensor array of pressure transducers were arranged in 4 x 4 five-spot patterns and located a considerable distance away from the stimulated wells. Dynamic pressure behavior from four hydraulic fracturing treatments was observed in three of the wells, a step-function pressure change was monitored in another well during and following fracture extension, and pressure buildup was recorded in the fifth well during a four-staged waterfrac stimulation. Data were analyzed by sequential two and three dimensional contour plots as a means of estimating induced fracture length and orientation. Several interpretations of observed variations in reservoir pressure during stimulation treatments are offered. Concepts advanced as plausible interpretations include (1) pressure wave transmissibility through independent fracture systems connecting the lamellar strata, and (2) pressure buildup perpendicular to the fracture trend as a result of block movement acting in a piston-like manner. 7 fig.

Catagenesis of dissipated organic substance in argillaceous strata with poor traps

Abstract: The main phase of oil formation, that is, the moment when potential source rocks become actual generators of oil, is retarded and spatially restricted in pelitic rocks such as the Maykop series in the West Kuban' downwarp, where reservoir horizons are scarce or missing. Nonetheless the test case discussed and documented suggests that the main phase of oil formation need not be confined to a particular depth or absolute time-span with regard to its development and/or termination.