Showing papers on "Petroleum reservoir published in 1981"

A reservoir analysis of the Denver earthquakes: A case of induced seismicity

Abstract: Injection of fluid wastes into the fractured Precambrian crystalline bedrock beneath the Rocky Mountain Arsenal near Denver triggered earthquakes in the 1960's. An analysis, based on the assumption that fluid flow in the fractured reservoir can be approximated by flow in a porous medium, is presented. The configuration and hydrologic properties of the reservoir are determined from two lines of evidence: (1) locations of earthquake hypocenters determined by seismic arrays installed at the Arsenal and (2) observed long-term decline in fluid levels in the injection well. Together these two sets of data indicate that a long, narrow reservoir, aligned in the direction N 60/sup 0/W, exists. The reservoir is 3.35 km in width, extends 30.5 km to the northwest and infinitely to the southeast, and spans a depth interval from 3.7 to 7.0 km below land surface. It has a transmissivity of 1.08 x 10/sup -5/ m/sup 2//s and a storage coefficient of 1.0 x 10/sup -5/. Computed pressure buildup along the length of the reservoir is compared with the spatial distribution of earthquake epicenters. The comparison shows that earthquakes are confined to that part of the reservoir where the pressure buildup exceeds 32 bars. This critical value is interpretedmore » as the pressure buildup above which earthquakes occur. The migration of earthquake epicenters away from the injection well, a phenomenon noted by previous investigators, can be accounted for by the outward propagation of the critical pressure buildup. The analysis is extended to examining the effects of rapid flow in fractures opened by high injection pressure. The results show that the effect is confined to a small region within 1 km of the injection well. The existence of a critical pressure buildup above which earthquakes occur is completely consistent with the theory on the role of fluid pressure in fault movement as presented by Hubbert and Rubey.« less

Stress Fields, A Key to Oil Migration

Abstract: A coherent oil-migration model based on geomechanical considerations includes both the high-molecular kerogen structure and the capillary properties of source rocks. Oil is squeezed from kerogen by compaction following oil generation. This squeezing effect should be created by the differential stress (maximum compressive stress minus least compressive stress) acting on the kerogen which has been chemically broken up by oil formation. In sedimentary bodies whose water is at hydrostatic pressure, the migration of oil seems to involve two processes: (1) lateral transfer, by channeling into the more coarsely microporous layers of the source rocks, from the oil generation site toward the geologic structure or lower pressured zone; and (2) vertical transfer from source rock to eservoir by the opening or reopening of vertical fractures in the few areas, such as structural tops, where the least compressive stress is slightly greater than or equal to the pore pressure, and where the capillary pressure increment (2^ggr/R) of oil in the microporosity exceeds the tensile strength of the rock. In sedimentary bodies whose water is overpressured, the pore pressure should be governed by the least compressive stress and thus migration should begin by oil transfers in a system of small open fractures, and eventually in larger fractures. The theory demonstrates the impossibility of oil being transferred to the reservoir under true tensile conditions (negative effective compressive stress) and thus explains the large asphaltic veins of southeastern Turkey and the well-known bitumen veins of the Uinta basin.

Ekofisk : First of the Giant Oil Fields in Western Europe

Abstract: Discovery of the giant Ekofisk field in block 2/4 in the Norwegian part of the North Sea in 1969 was a major turning point in the exploration for petroleum in Western Europe. Since that time, the North-Sea has proven to be one of the best areas for exploration anywhere in the world. Current production is 1.5 million barrels of oil per day, and North Sea proven reserves total 18 billion barrels, with estimates of ultimate reserves as high as 40 billion barrels. Ekofisk is located in the Central Graben in the southern part of the Norwegian sector of the North Sea. Although several periods of tectonism have affected this area, it has remained an intercratonic basin since Devonian time. The main elements of the tectonic fabric were established during the Caledonian and Hercynian orogenies and later remained as controlling features for facies and sediment distribution. A stratigraphic history reveals petrography of the main chalk group, environment of deposition, and diagenetic history of the area. A section outlines the preservation of porosity which has allowed the Ekofisk and Tor Formations to retain an average porosity of 30 to 40 percent which would not have been possible under normal circumstances. It is appropriate to state that the anomalously high porosity in Ekofisk field is probably due to a combination of: (1) overpressuring of the reservoir, (2) magnesium rich pore fluids, and (3) early introduction of hydrocarbons. The six Greater Ekofisk fields now being developed were all located during the 1960s by reconnaissance seismic work. The history of the geophysical exploration is outlined and a study has been made on source rock analysis and geopressures. Also outlined is the three-phase, Greater Ekofisk development program.

Some Mass Balance and Geological Constraints on Migration Mechanisms

Abstract: Oil and gas are not at rest in the sedimentary mantle of the earth. They are not in equilibrium, whether they are finely dispersed in a potential source rock or whether they are concentrated in a trap in a reservoir rock. A wide variety of possible escape mechanisms exists; these include diffusion, continuous single phase flow, solution of oil in gas or gas in oil, and solution in water derived from compaction, clay diagenesis, or meteoric sources. The problem is to quantify the possible mechanisms and to rank their relative importance under a given set of physical, chemical, and geologic conditions. The quantitative importance of the various proposed mechanisms can vary by orders of magnitude, depending on the physical, chemical, and geologic conditions. During the past decade, oil-to-source correlations have become reliable and the timing of peak generation and concomitant migration has been sufficiently quantified to allow the geologist/geochemist to make estimates of when and how much petroleum moved from one location to another. Combined with a knowledge of the physical, chemical, and geologic conditions at the time of migration, such quantitative descriptions of subsurface petroleum transfer permit an empirical test of the applicability of the various proposed migration mechanisms. The application of this technique to selected areas suggests that most of the major commercial oil accumulations of the world left their source rock in a continuous oil phase. When bitumen concentrations in the rock are too low for continuous phase flo to exist, other migration mechanisms, which always are operative, will increase in both absolute and relative intensity. Solution of oil in gas may become significant in thick Tertiary delta systems, and meteoric water may be a surprising asset in some very specific geologic settings. However, it is unlikely that solution of oil in water derived from compaction or from dehydration of clay has much to do with the origin of many of the major oil accumulations of the world.

Geochemical Correlation of Windalia Oil and Extracts of Winning Group (Cretaceous) Potential Source Rocks, Barrow Subbasin, Western Australia

Abstract: Windalia oil is a commercial accumulation in a Cretaceous reservoir at Barrow Island, Western Australia. A chemical correlation study has been made between this oil and hydrocarbons extracted from 37 Cretaceous sedimentary rock samples from different stratigraphic levels in seven wells on and around Barrow Island. Seven established correlation parameters and one new parameter have been applied to establish oil:source rock relations. The new parameter is the ratio of pristane + heptadecane to phytane + octadecane. The influence of maturation on several correlation parameters has been investigated by pyrolyzing source rocks at 300°C for varying times. The changes observed in these experiments have been used to infer the effects which maturation processes have on the co relation parameters. To assess the overall degree of correlation between source rock extracts and oil, each method has been assigned a weighting which reflects its power as a correlation technique. An overall correlation score was obtained for each potential source rock by totaling the contributions from the eight individual methods. It appears likely that the Windalia oil had its source within the Winning Group of sedimentary rocks, the most probable source formations being the Middle shale of the Windalia sandstone member, the Muderong Shale, and the Windalia Radiolarite. Several mechanisms of formation of Windalia oil from these source beds are possible.

Near-Surface Evidence of Migration of Natural Gas from Deep Reservoirs and Source Rocks

Abstract: Gaseous hydrocarbons migrate to the surface in small quantities from deep source rocks and natural gas or crude oil accumulations. This process leads to anomalous concentrations of hydrocarbons in near-surface sediments. The hydrocarbon anomalies (amount and composition) are useful in exploration, because they may point to oil and gas reservoirs. The origin of hydrocarbon anomalies in shallow sediments is not a simple one. Methane in near-surface sediments may be caused by a combination of bacterial production of methane, leakage from reservoirs, and leakage of methane from thermal maturation of organic matter in source rocks. Organic geochemistry, especially carbon isotope techniques, have been used to recognize secondary fractionation processes caused by degassing or bacterial oxidation. Examples of geochemical surveys in onshore and offshore areas indicate secondary fractionations so small that gases from near-surface sediments and from reservoirs can be correlated by the geochemical data. The application of stable carbon isotopes is a significant step toward improving geochemical hydrocarbon surface exploration methods.

Two Oil Types on North Slope of Alaska--Implications for Exploration

Abstract: Forty oil samples from across the North Slope of Alaska have been analyzed by the U.S. Bureau of Mines and the U.S. Geological Survey. Results of these analyses suggest two separate genetic oil types. The first, the Simpson-Umiat oil type, occurs in reservoir rocks of Cretaceous and Quaternary age and includes oil from seeps in the Skull Cliff, Cape Simpson, Manning Point, and Ungoon Point areas, and oils from Wolf Creek test 3, and the Cape Simpson and Umiat oil fields. These are higher gravity, low-sulfur oils with no, or slight, odd-numbered n-alkane predominance and pristane to phytane ratios greater than 1.5. Also, these oils have ^dgr13C values ranging from -29.1 to -27.8 parts per thousand (ppt) and ^dgr34S values from -10.3 to -4.9 ppt. The s cond type, the Barrow-Prudhoe oil type, occurs in reservoir rocks of Carboniferous to Cretaceous age and includes oils from South Barrow gas field, Prudhoe Bay oil field, and the Fish Creek test well 1. Physical properties of Barrow-Prudhoe oils are variable, but in general the oils are medium-gravity, high-sulfur oils with slight even-numbered n-alkane predominance and pristane to phytane ratios less than 1.5. Also these oils have ^dgr13C values of -30.3 to -29.8 ppt and ^dgr34S values from -30.0 to +2.1 ppt. The two types are believed to originate from different source rocks; the Barrow-Prudhoe type may have originated from a carbonate or other iron-deficient source rock, and the Simpson-Umiat type from a siliciclastic source rock. Occurrences of the two oil types when outlined on a map, indicate at least two areas for additional exploration: for the Barrow-Prudhoe type, in stratigraphic traps along and adjacent to the Barrow arch, and for the Simpson-Umiat type, in Cretaceous rocks along the trend between the Simpson and Umiat oil fields and in Cretaceous and Tertiary rocks from Prudhoe Bay field to the William O. Douglas Arctic Wildlife Range.

Exploration for Oil Accumulations in Entrada Sandstone, San Juan Basin, New Mexico

Abstract: Recent exploration activity in the San Juan basin of northwestern New Mexico has resulted in the discovery of new oil fields in the Entrada Sandstone of Jurassic age. The major trapping element is provided by topographic relief in excess of 100 ft (30 m) on top of the Entrada. Preliminary analyses indicate that the topographic relief was created by preserved eolian sand dunes which were formed in a topographic basin which then became the sight of a large lake in which limestones and anhydrites of the Todilto Formation were deposited over the Entrada sands. The organic-rich limestones of the Todilto provide the most likely source for the oil found in the underlying Entrada. Analysis of stratigraphy, oil shows, source-rock potential, and porosity distribution led to the selection of an initial exploration area located along the southeastern flank of the San Juan basin. Seismic model studies, confirmed by an experimental seismic program, indicated that the topographic relief on top of the Entrada could be mapped seismically. An extensive seismic and drilling program has resulted in the discovery of six new oil pools. In addition to the topographic relief on top of the Entrada, other factors which control the oil accumulations include local structural conditions, hydrodynamics, source-rock and oil-migration history, and porosity-permeability relations in the Entrada. The knowledge gained from this exploration program should aid in future exploration for Entrada oil fields in the San Juan basin, and encourage exploration for similar stratigraphic traps in other basins.

Simulation Model for Petroleum Exploration

Abstract: A computerized simulation model was constructed to synthesize the processes of petroleum generation, migration, and accumulation under relatively simple conditions. The model successfully simulated accumulation in an existing anticlinal gas field, and was used to estimate the possibility of fault and stratigraphic entrapment nearby. The geologic cross section of the area is divided into a series of vertical columns, which are sectioned into rectangular cells representing successive intervals of time and the strata deposited therein. Four geologic processes are sequentially performed on each cell or on each pair of adjacent cells: (1) deposition, (2) compaction, (3) petroleum generation, and (4) petroleum migration. First, sediment is deposited in the cell, with its original thickness restored by removing the effects of compaction. Then for each time-stratigraphic unit, the system calculates the amount of compaction caused by increasing time and depth of burial, and also the amount of petroleum generated, which is assumed to be a function of temperature. Primary migration is assumed when the petroleum saturation o the shale source beds exceeds the residual amount normally in thermally mature shale. Secondary migration is assumed to result from buoyancy alone; any petroleum which exceeds the hydrostatic trapping capacity of the shale seal migrates into a cell located along some upward path or escapes to the surface. The model was applied to the anticlinal East Niigata field, Japan, using carefully selected input parameters. Results made it possible to estimate the migration paths and the timing of entrapment in each producing zone under the assumed conditions. The model may also be applied to exploration problems. It was used to estimate the possibility of petroleum entrapment in homoclinal strata near the East Niigata field under several assumed geologic situations. Results of this experiment show that the simulation method is potentially very useful for estimating the possibility and places of entrapment, especially for stratigraphic traps.

Facies and Burial Diagenesis of a Carbonate Reservoir: Chapman Deep (Atoka) Field, Delaware Basin, Texas

Abstract: Hydrocarbon production at Chapman Deep Atoka field is from a complex microfacies mosaic of shallow-water bank limestones deposited along the northern hingeline of the Delaware basin. Reservoir localization is essentially stratigraphic in terms of depositional and diagenetic facies, although regional draping and a system of vertical fractures are significant structural aspects of the field. The bank facies consist of cyclic alternations of Donezella (algal) bioherms, oolite-biograinstone shoals, and low-energy interbank deposits. Laterally equivalent slope and basinal facies include spiculitic and crinoidal argillaceous limestones and shales, with interbedded lenses of fine-grained carbonate and siliciclastic turbidites. Early diagenetic effects include incipient marine ce entation and the formation of secondary porosity, most of which was occluded by calcite cements, internal sediments, and dolomitization. In contrast, reservoir evolution is principally related to diagenesis in the deep subsurface (mesogenetic) environment. Bulk-volume reduction by chemical and physical compaction was counterbalanced by porosity rejuvenation through the selective dissolution of allochems, cements, and stylolite surfaces, and the formation of open-gash fractures and adjoining stylolites. Although this limited pore system is of inherently low permeability, effective communication within and between individual reservoir lenses was enhanced by later fracturing. Although potential reservoir facies can be mapped regionally and burial diagenetic effects can be recognized petrogr phically, exploration for similar reservoirs in the Delaware basin is hindered by our limited knowledge of mesodiagenesis.

Petroleum Geology of Cook Inlet Basin -- An Exploration Model

Abstract: Oil exploration commenced onshore adjacent to lower Cook Inlet on the Iniskin Peninsula in 1900, shifted with considerable success to upper Cook Inlet from 1957 through 1965, then returned to lower Cook Inlet in 1977 with the COST well and Federal OCS sale. Lower Cook Inlet COST No. 1 well, drilled to a total depth of 3,775.6 m, penetrated basinwide unconformities at the tops of Upper Cretaceous, Lower Cretaceous, and Upper Jurassic strata at 797.1, 1,540.8, and 2,112.3 m, respectively. Sandstone of potential reservoir quality is present in the Cretaceous and lower Tertiary rocks. All siltstones and shales analyzed are low (0 to 0.5 wt. %) in oil-prone organic matter, and only coals are high in humic organic matter. At total depth, vitrinite readings reached a maximum ave age reflectance of 0.65. Several indications of hydrocarbons were present. Oil analyses suggest that oils from the major fields of the Cook Inlet region, most of which produce from the Tertiary Hemlock Conglomerate, have a common source. More detailed work on stable carbon isotope ratios and the distribution of gasoline-range and heavy (C12+) hydrocarbons confirms this genetic relation among the major fields. In addition, oils from Jurassic rocks under the Iniskin Peninsula and from the Hemlock Conglomerate at the southwestern tip of the Kenai lowland are members of the same or a very similar oil family. The Middle Jurassic strata of the Iniskin Peninsula are moderately rich in organic carbon (0.5 to 1.5 wt. %) and yield shows of oil and of gas in wells and in surface seeps. Extractable hydrocarbons from this strata are similar in chemi al and isotopic composition to the Cook Inlet oils. Organic matter in Cretaceous and Tertiary rocks is thermally immature in all wells analyzed. Oil reservoirs in the major producing fields are of Tertiary age and unconformably overlie Jurassic rocks; the pre-Tertiary unconformity may be significant in exploration for new oil reserves. The unconformable relation between reservoir rocks and likely Middle Jurassic source rocks also implies a delay in the generation and expulsion of oil from Jurassic until late Tertiary when localized basin subsidence and thick sedimentary fill brought older, deeper rocks to the temperature required for petroleum generation. Reservoir porosities, crude oil properties, the type of oil field traps, and the tectonic framework of the oil fields on the west flank of the basin provide evidence used to reconstruct an oil migration route. The route is inferred to commence deep in the truncated Middle Jur ssic rocks and pass through the porous West Foreland Formation in the McArthur River field area to a stratigraphic trap in the Oligocene Hemlock Conglomerate and the Oligocene part of the Tyonek Formation at the end of Miocene time. Pliocene deformation shut off this route and created localized structural traps, into which the oil moved by secondary migration to form the Middle Ground Shoal, McArthur River, and Trading Bay oil fields. Oil generation continued into the Pliocene, but this higher API gravity oil migrated along a different route to the Granite Point field.

Factors controlling reservoir quality in tertiary sandstones and their significance to geopressured geothermal production

Abstract: Variable intensity of diagenesis is the factor primarily responsible for contrasting regional reservoir quality of Tertiary sandstones from the upper and lower Texas coast. Detailed comparison of Frio sandstone from the Chocolate Bayou/Danbury Dome area, Brazoria County, and Vicksburg sandstones from the McAllen Ranch Field area, Hidalgo County, reveals that extent of diagenetic modification is most strongly influenced by (1) detrital mineralogy and (2) regional geothermal gradients. The regional reservoir quality of Frio sandstones from Brazoria County is far better than that characterizing Vicksburg sandstones from Hidalgo County, especially at depths suitable for geopressured geothermal energy production. However, in predicting reservoir quality on a site-specific basis, locally variable factors such as relative proportions for porosity types, pore geometry as related to permeability, and local depositional environment must also be considered. Even in an area of regionally favorable reservoir quality, such local factors can significantly affect reservoir quality and, hence, the geothermal production potential of a specific sandstone unit.

Method of monitoring the spacial production of hydrocarbons from a petroleum reservoir

Abstract: In the injection of fluids into subsurface geological formations, such as for the purpose of recovering a mineral in that formation, it is important that the flow progress of that fluid is known at all points in the subsurface. This information is provided by injecting a selected fluid into the formation. This fluid may be a gas, or a liquid, or a mixture of gas and liquid. When this fluid is in the subsurface formation there will be a mixture of gas and liquid in selected proportion in the formation. This mixture in a geologic formation overlain by a shale, for example, will have a much higher reflection coefficient. A source of seismic waves is operated at the surface, and the received reflections are compared between spaced positions on the surface.

Geochemistry of Oil from Santa Cruz Basin, Bolivia: Case Study of Migration-Fractionation

Abstract: Geochemical studies provide important data relevant to the origin of the oils in the Santa Cruz basin, Bolivia. Production from this basin occurs from rocks of Devonian, Carboniferous, Cretaceous, and Tertiary ages. The productive structures are usually undisturbed by major faulting. The Devonian sediments are composed of sandstones and dark marine shales. The post-Devonian rocks are generally oxidized and probably nonmarine. The Tertiary and Cretaceous reservoirs usually contain the highest API° gravity oils. Comparison of geochemical data (N5-N10 molecular weight range) shows that the oils are very similar; however, systematic compositional trends occur as a function of API° gravity. These trends are interpreted from gross structural group data. Isoparaffins and cycloparaffins increase in relative abundance, while normal paraffins and aromatics decrease with increasing API° gravity. A model is proposed that rationalizes these compositional trends by a mechanism of "accommodation" in water. The model requires enrichment of hydrocarbons of intermediate solubility, partial exclusion of hydrocarbons of low solubility, and retention in solution of the more soluble hydrocarbons. Processes such as thermal fractionation and biodegradation fail to account satisfacto ily for the observed compositional trends. The compositional interrelationships of the oils coupled with the geologic framework suggest that these oils have a common source, most probably the Devonian. Differences between the oils are attributed to fractionation occurring during migration. Exploration risk for areas such as the Santa Cruz basin can be substantially reduced by use of the knowledge derived from petroleum geochemistry.

Migration of Hydrocarbons and Secondary Porosity in Sandstones

Abstract: A unified hypothesis concerning generation and migration of hydrocarbons and development of secondary porosity in sandstones is presented. Carbonic acid is considered to be the primary reagent responsible for dissolution in the development of secondary porosity in sandstones. The degree to which reservoir quality is enhanced by development of secondary porosity may be proportional to the amount of hyrocarbons generated as well as to the amount of unstable constituents during diagenesis. In some cases, formation of secondary porosity may be responsible not only for development of reservoir but also for a significant element of entrapment by the partial but areally and stratigraphically selective dissolution of sandstone in the migration path of hydrocarbons. (JMT)

Effects of porosity type, pore geometry, and diagenetic history on tertiary recovery of petroleum from carbonate reservoirs. Final report

Abstract: The objective of this study is to determine the mechanisms controlling porosity in Red River formation (Upper Ordovician) carbonate reservoirs, and to determine what types of pore systems result from a given set of depositional and diagenetic conditions. The Red River Formation of Montana is a major oil-producing reservoir in the area and Cabin Creek Field is a good candidate to undergo tertiary recovery in the future. The first sections of this paper discuss the stratigraphy, distribution of lithofacies, depositional environments, and diagenesis of the study area.The section on distribution of porosity discusses the various types of porosity present, their origin, how they are distributed throughout the upper Red River reservoirs, and how they relate to depositional environment. Size and shape of pores and pore throats are discussed in the sections on pore geometry, first in terms of statistical measures from capillary-pressure curves, then by interpretation of scanning-electron micrographs of resin-pore casts. The last two sections discuss petrophysical relationships, diagenetic controls on the development and geometry of pore systems, and the role of pore geometry in the determination of carbonate reservoir characteristics.

Structural Evolution of Harmaliyah Oil Field, Eastern Saudi Arabia

Abstract: The history of structural growth of the Harmaliyah oil field in eastern Saudi Arabia was studied by means of a series of paleostructural maps to determine if early entrapment of hydrocarbons played an important role in preserving the high porosity of the Kimmeridgian (Upper Jurassic) Arab D reservoir. The Arab D has been affected by shallow or preburial diagenesis--a common feature in Arabian Upper Jurassic calcarenitic reservoirs. Closure forming the structural trap in the Arab D at Harmaliyah oil field developed principally during the late Turonian (Late Cretaceous). During Kimmeridgian (Late Jurassic)-early Turonian (Late Cretaceous) time, shallow or preburial diagenesis of the calcarenitic Arab D reservoir rocks seems to have played a major part in preservation of por sity before the porosity was filled with hydrocarbons.

Seismic Models of Sandstone Stratigraphic Traps in Rocky Mountain Basins

Abstract: Stratigraphic-trap classifications used in this investigation, follow Rittenhouse (1972). These subtle stratigraphic traps are representative of the type of trap that exploration geologists and geophysicists commonly pursue in the Rocky Mountain basins. If known specific stratigraphic-trap fields can be detected and identified with surface reflection seismic data, then these data may possibly serve as guides to explore for analogous but undiscovered fields. Our approach to documenting the seismic response of the known stratigraphic traps involves three specific steps: (1) simulate the seismic response of a selected stratigraphic-trap field with digital seismic modeling, (2) run vertical seismic profile (VSP) experiments in available wells and dry holes to measure the in situ acoustic properties of both the reservoir and the trap facies, and (3) gather surface seismic data across the field, near available VSP control, to corroborate the model and VSP studies. Each successive stage of the investigation contributes more documentation of the waveform character or seismic signature accompanying the field. The objective of this publication is to present the results of seismic model studies of 15 known stratigraphic traps that were obtained during the first part of the three-fold investigation. The modeled fields have sandstone reservoirs representative of depositional settings, diagenetic histories, and burial depths. Vertical seismic profile and surface seismic experiments will follow where the model studies indicate convincing seismic anomalies. For one of the models, the Red Bird field in the Powder River basin of Wyoming, an entire seismic-stratigraphic investigation is already (Balch et al, 1981).

Lithology, reservoir properties, and burial history of portion of Gammon Shale (Cretaceous), southwestern North Dakota

Abstract: In the northern Great Plains, large quantities of biogenic methane are contained at shallow depths in Cretaceous marine mudstones. The Gammon Shale and equivalents of the Milk River Formation in Canada, which comprise most sediments deposited offshore during the Eagle-Telegraph Creek regression, are typical of such gas-bearing rocks. At Little Missouri field, southwestern North Dakota, Gammon reservoirs consist of discontinuous lenses and laminae of siltstone, less than 10 mm thick, enclosed by silty clay shale. Large amounts of allogenic clay, including highly expansible mixed-layer illite-smectite cause great water sensitivity and high measured and calculated water-saturation values. Reconstructed burial depths, clay mineralogy, and organic matter maturation studies show that the Gammon has not undergone thermal conditions sufficient for oil or thermal gas generation. Scarce authigenic minerals such as pyrite, siderite, and calcite probably formed as a result of bacterial metabolism early in the burial history. The scarcity of authigenic silicates suggests that diagenesis has been inhibited during much of the burial history by the presence of free methane. Shale layers are practically impermeable whereas siltstone microlenses are porous (30 to 40%) and have permeabilities on the order of 3 to 30 md. Reservoir continuity between siltstone layers is poor and, overall, reservoir permeability is probably less than 0.4 md. Connecting passageways between siltstone lenses are 0.1 µm or less in diameter. Organic matter in the low-permeability reservoirs served as the source of biogenic methane, and capillary forces acted as the trapping mechanism for gas accumulation. At Little Missouri field, reservoirs and non-reservoirs cannot be distinguished on the basis of lithology, and much of the Gammon interval is potentially economic. Future research should be directed toward determining the physical basis of log response in the low-permeability reservoirs and toward the development or application of water-free recovery technology.

Neutron well logging

Abstract: This invention relates to an improved method for determining the oil saturation of subsurface earth formations in the vicinity of a well borehole. High energy neutrons irradiate the subsurface earth formations and gamma rays caused by inelastic scatter with the subsurface earth formation constituent materials are measured. For a chosen borehole depth, gamma ray logs are taken in different situations: first, with the formation fluid water and oil mixture in an undisturbed state; second, after flushing the formation with alcohol to displace the formation water and oil mixture; and, finally, after flushing the alcohol from the formation with water to obtain a measurement with no oil in the formation. The gamma ray measurements obtained are then used to determine the oil saturation without requiring knowledge of the porosity of the earth formation, borehole conditions or formation type. When the original oil content of the formation is at a naturally flushed, or residual, oil saturation, the present invention may be used to determine the residual oil saturation.

Meren field - the geology and reservoir characteristics of a Nigerian offshore field

Abstract: The Meren Field is located in the offshore waters of Nigeria. The field contains 1.3 billion barrels of original oil in place and may be classed as a major oil accumulation. The more landward lying fault-blocks within the field contain an increasing greater preponderance of oil reserves to gas reserves. This study has indicated the possibility of using a combination of well log interpretation with laboratory analyses of sidewall cores to aid in the determination of the areal variation of porosity and permeability within a particular reservoir. 7 refs.

Stratigraphic, Sedimentologic, and Diagenetic Framework for Jurassic Cotton Valley Terryville Massive Sandstone Complex, Northern Louisiana: ABSTRACT

Abstract: With deregulation and the subsequent rise in gas prices and development of modern evaluation and completion techniques, the "tight gas sands" of the Cotton Valley Terryville massive sandstone complex have become an intriguing play. This study establishes a generalized stratigraphic framework which allows regional correlation of individual productive horizons in the Terryville from east Texas to east Louisiana. It also proposes a sedimentologic sequence for deposition and a diagenetic sequence for reservoir rock modification. The Terryville is an extensive complex of marine-dominated, massively bedded, predominantly fine-grained, quartz sandstones. It lies stratigraphically between the underlying Bossier Shale and the overlying Knowles Limestone and downdip from the time-equivalent Hico Shale and Schuler Formation. A series of four prograding marine-dominated, coalescing, deltaic complexes are proposed as the depositional systems for placing the Terryville sands on the stable Jurassic shelf. In this model, fluctuating sea levels and longshore drift spread the sands over a 40- to 50-mile-wide belt. Burial diagenesis modified the porosity and, in the southeastern portion of the area, created overpressuring in the Terryville sandstones. Subsequent structural movement in certain areas created large fractured reservoirs. Production from the tight gas sands is controlled by distinctive sedimentary and diagenetic effects which divide the area into two subareas: the normally pressured and the overpressured Terryville. Utilization of these concepts should result in a higher degree of success in economically developing the tight gas sands of the Cotton Valley Terryville.

Lateral Trapping Mechanisms in Deep Basin Gas Trap, Western Canada: ABSTRACT

Abstract: The basic model for a Deep Basin gas trap is characterized by laterally extensive, low-porosity and low-permeability subsurface strata that contain gas downdip and water updip. No permeability barrier separates the two phases in the transition zone at the updip limit of the gas accumulation. Two other features of the model are significant: (1) the original gas and water phase pressures are about equal at the updip limit, and (2) there is no downdip gas/water contact. In many respects, the Deep Basin trap is just the reverse of a conventional gas over water-type trap. In the conventional trap, gas has migrated to the highest structural position in the reservoir owing to its buoyancy in the ambient formation water phase; there is a downdip gas/water contact where original pressures in both phases are nearly equal and no permeability barrier is necessary to separate the two phases. The physical principles controlling the Deep Basin water over gas trap are just as simple and straightforward as those long recognized for conventional traps. Because there is no downdip water phase or gas/water contact, the Deep Basin gas accumulation is not subjected to buoyancy forces as in the contentional trap. As long as pressures remain equal between both phases at the updip contact or transition zone, there will be no unbalanced forces present. As a result, the gas accumulation will remain in a state of static equilibrium. Similarly, in the conventional trap, equal pressures at the gas/water contact maintain the gas accumulation in a state of static equilibrium. Evidence for these basin principles of Deep Basin trapping of hydrocarbons result from the study of abundant, high quality reservoir data derived from an extensive, ongoing development drilling program pursued by Canadian Hunter in the Elmworth gas field of northwestern Alberta. End_of_Article - Last_Page 930------------

Hot dry rock geothermal potential of Roosevelt Hot Springs area: review of data and recommendations

Abstract: The Roosevelt Hot Springs area in west-central Utah possesses several features indicating potential for hot dry rock (HDR) geothermal development. The area is characterized by extensional tectonics and a high regional heat flow of greater than 105 mW/m/sup 2/. The presence of silicic volcanic rocks as young as 0.5 to 0.8 Myr and totaling 14 km/sup 3/ in volume indicates underlying magma reservoirs may be the heat source for the thermal anomaly. Several hot dry wells have been drilled on the periphery of the geothermal field. Information obtained on three of these deep wells shows that they have thermal gradients of 55 to 60/sup 0/C/km and bottom in impermeable Tertiary granitic and Precambrian gneissic units. The Tertiary granite is the preferred HDR reservoir rock because Precambrian gneissic rocks possess a well-developed banded foliation, making fracture control over the reservoir more difficult. Based on a fairly conservative estimate of 160 km/sup 2/ for the thermal anomaly present at Roosevelt Hot Springs, the area designated favorable for HDR geothermal exploration may be on the order of seven times or more than the hydrogeothermal area currently under development.

Site Characterization For Injection Of Compressed Air Into An Aquifer

Abstract: Compressed air energy storage (CAES) can level rates of electricity generation at central plants. Air compressed during low demand may be stored in deep water-bearing permeable rock formations (aquifers). During peak demand the compressed air is reheated and expanded through turbines. An aquifer reservoir uses a closed anticline with impervious caprock overlying a permeable sandstone or limestone. The confined reservoir volume accommodates sufficient compressed air for peak generation. The reservoir depth below its associated water table is selected to store air at the system's design pressure. Compromising geologic features such as faults are avoided. Rock properties needed to qualify a site include mechanical, physical (permeability, porosity) and mineralogical/geochemical characteristics of caprock and reservoir rock. Threshold pressure of the caprock must be sufficient to retain compressed air. A small structure near Pittsfield, Illinois, is being characterized for experimental scale field injection of compressed air at shallow depth. This test is designed to fulfill three objectives: (1) evaluate numerical modeling and laboratory conclusions about CAES behavior in aquifers; (2) demonstrate air injection, storage and recovery; and (3) evaluate and modify preliminary reservoir stability criteria. Characterizing methods include seismic exploration, confirmatory drilling, geophysical logging, caprock and reservoir rock testing, hydrology tests and watermore » analysis.« less

Fluid-mineral equilibria in a hydrothermal system, Roosevelt Hot Springs, Utah

Abstract: The availability of fluids and drill cuttings from the active hydrothermal system at Roosevelt Hot Springs allows a quantitative comparison between the observed and predicted alteration mineralogy, calculated from fluid-mineral equilibria relationships. Comparison of all wells and springs in the thermal area indicates a common reservoir source, and geothermometer calculations predict its temperature to be higher (288°C ± 10°) than the maximum measured temperature of 268°C. The composition of the deep reservoir fluid was estimated from surface well samples, allowing for steam loss, gas release, mineral precipitation and ground-water mixing in the well bore. This deep fluid is sodium chloride in character, with approximately 9700 ppm dissolved solids, a pH of 6.0, and gas partial pressures of O2 ranging from 10−32 to 10−35 atm, CO2 of 11 atm, H2S of 0.020 atm and CH4 of 0.001 atm. Comparison of the alteration mineralogy from producing and nonproducing wells allowed delineation of an alteration pattern characteristic of the reservoir rock. Theoretical alteration mineral assemblages in equilibrium with the deep reservoir fluid, between 150° and 300°C, in the system Na2O-K2O-CaO-MgO-FeO-Fe2O3-Al2O3-H4SiO4-H2O-H2S-CO2-HCl, were calculated. Minerals theoretically in equilibrium with the calculated reservoir fluid at >240°C include sericite, K-feldspar, quartz, chalcedony, hematite, magnetite and pyrite. This assemblage corresponds with observed higher-temperature (>210°C) alteration assemblage in the deeper parts of the producing wells. The presence of montmorillonite and mixed-layer clays with the above assemblage observed at temperatures <210°C corresponds with minerals predicted to be in equilibrium with the fluid below 240°C. Alteration minerals present in the reservoir rock that do not exhibit equilibrium with respect to the reservoir fluid include epidote, anhydrite, calcite and chlorite. These may be products of an earlier hydrothermal event, or processes such as boiling and mixing, or a result of errors in the equilibrium calculations as a result of inadequate thermochemical data.

An assessment of the petroleum prospects for the galilee basin, queensland

Abstract: The Galilee Basin in central Queensland is an extensive intracratonic basin containing up to 2 800 m of Late Carboniferous to Middle Triassic strata deposited under predominantly fluviatile conditions in two depocentres, the Lovelle Depression and the Koburra Trough. The exploration criteria of petroleum geochemistry, reservoir rock quality, structural and trapping style have been assessed. The source potential is generally poor with the Aramac Coal Measures, basal Jericho Formation, and the underlying Devonian rating best for possible hydrocarbon generation. Organic maturation is generally not reached until the Late Carboniferous Jochus Formation. The predominant organic maceral type for the Late Carboniferous and the Permian is vitrinite, suggesting gas-prone source. The potential for reservoir rock is best developed in the Aramac Coal Measures and Colinlea Sandstone correlative units within a fluvial channel sandstone facies. Structural and stratigraphic traps formed in the Late Carboniferous and the Early Permian are thought to be most prospective. The presence of oil and gas in ENL Lake Galilee 1 does imply that hydrocarbons have been generated in the basin or possibly from the underlying Devonian. The application of oil/source rock correlation data suggests the basal Jericho Formation or the underlying Devonian as the oil source. The Aramac Coal Measures, with a combination of reservoir and source facies even though only marginally mature, are thought to offer the best play. Lack of success to date may well reflect deficiencies in one or more of the exploration criteria. However, examination of drilling locations suggests that many wells were poorly sited owing to the difficulty in seismic mapping below the Late Permian coal seams.

Tertiary Carbonate Reservoirs in Indonesia

Abstract: Hydrocarbon production from Tertiary carbonate reservoirs accounted for about 10% of daily Indonesian production at the beginning of 1978. Environmentally, the reservoirs appear as parts of reef complexes and high-energy carbonate deposits within basinal areas situated mainly in the back arc of the archipelago. Good porosities of the reservoirs are represented by vugular/moldic and intergranular porosity types. The reservoirs are capable of producing prolific amounts of hydrocarbons: production tests in Salawati-Irian Jaya reached maximum values of 32,000 b/d, and in Arun-North Sumatra tests recorded 200 MMcf gas/day. Significant hydrocarbon accumulations are related to good reservoir rocks in carbonates deposited as patch reefs, pinnacle reefs, and platform complexes.Exploration efforts expand continuously within carbonate formations which are extensive horizontally as well as vertically in the Tertiary stratigraphic column.

An oil migration and re-entrapment model for the mardin group reservoirs of southeast anatolia

Abstract: Oil migrates from a source into a reservoir rock and then, inside the reservoir rock, into a trap, and from the trap into a series of traps and reservoir rocks. The movement of oil is continuous and the interchange of oil between several reservoir rocks is totally independent of the source rock after a certain stage of migration. Each migration stage may cause quality changes in the properties of oil. A model is devised to account for oil migration and re-entrapment, and to explain the distribution of different quality oils in time and space. Variations in the API-gravity of oil, formation-water salinity, reservoir temperature and pressure, sulphur-content of oil, initial water content and recoverable oil reserves of oilfields can be important clues for the determination of migration directions and new prospects. These concepts were applied in a petroleum migration study of the Mardin Group (Aptian-Turonian) which is the most important reservoir rock of SE Anatolia.