Showing papers on "Petroleum reservoir published in 1980"

Oil Recovery by Gravity Drainage

Abstract: Recent observations have indicated surprisingly high oil recoveries for gravity drainage. This has prompted the reexamination of gravity drainage as an oil recovery process. It is shown that oil relative permeability is a key factor. To measure this oil relative permeability accurately, a new method based on centrifugal gas-oil displacement in small cores is described. Several oil relative permeabilities for various rock types are presented. These relative permeabilities confirm that gravity drainage in water-wet connate-water-bearing reservoirs can be a very effective oil recovery process.

Method for enhanced oil recovery by geopressured waterflood

Abstract: The recovery of petroleum produced from an oil reservoir is enhanced by injecting water such as from a geopressured aquifer having a natural gas content at or near saturation at a temperature above 300° F. into the oil reservoir at a flow rate sufficient to develop a back-pressure in the oil reservoir equal to between about 80% of its fracture pressure and a pressure below its fracture pressure and producing oil from the oil reservoir when the injection of water necessary to maintain the back-pressure below the oil reservoir fracture pressure drops below a predetermined level. The recovery of petroleum also is enhanced by using sand screening means to complete a portion of the well bore penetrating into the oil reservoir and a straddle packer assembly means which can be raised and lowered relative to the screening means.

History Matching in Two-Phase Petroleum Reservoirs

Abstract: An automatic history-matching algorithm based on an optimal control approach has been formulated to estimate jointly spatially varying permeability and porosity and coefficients of relative permeability functions in 2-phase reservoirs. The algorithm utilizes pressure and production rate data simultaneously. The performance of the algorithm for the waterflooding of one- and two-dimensional hypothetical reservoirs is examined, and properties associated with the parameter estimation problems are discussed.

Petroleum Generation and Migration in Denver Basin

Abstract: Crude oils and shale from the northern Denver basin were analyzed using organic geochemical techniques to determine oil-source-bed relations. Geochemical analyses show that, in general, Cretaceous oils are compositionally similar throughout the basin and are dissimilar to oil produced from the Permian Lyons Sandstone. Shales were evaluated for source-rock potential based on quantity of contained organic matter, thermal maturity, and geochemical correlation with crude oils. These analyses showed that most of the Cretaceous oils have been derived from the Carlile Shale, Greenhorn Limestone, Graneros Shale, and Mowry Shale interval. These units have a maximum collective thickness of about 500 ft (152 m) and can be grouped together on the basis of similar geochemistry. The source bed for the Lyons oil has not been identified. Regional geochemical study of the Carlile-Greenhorn-Graneros-Mowry interval shows that effective source beds are limited to the basin-axis area. Although shale samples from eastern Colorado and southwestern Nebraska are rich in organic matter, they are generally thermally immature. The presence of petroleum on the east flank of the basin and the limited geographic distribution of effective source beds indicate that extensive (perhaps 100 mi or 160 km) lateral migration has occurred. Cretaceous oils in reservoirs in the Terry and Hygiene Sandstone Members of the Pierre Shale have probably undergone extensive vertical migration (about 2,500 ft or 762 m in the central Front Range area).

Transient Flow In Naturally Fractured Reservoirs And Its Application To Devonian Gas Shales

Abstract: Devonian shale gas reservoirs typically are characterized by a low storage, high flow-capacity natural fracture system fed by a high storage, low flow-capacity rock matrix. In this study analytical solutions are developed to analyze the basic fractured reservoir parameters that control well productivity. These parameters include fractured system porosity and permeability, matrix porosity and permeability, and matrix size. It is shown that the conventional well test method does not usually work for fractured Devonian shale gas reservoirs. For most cases, the semi-log plot of the drawdown then buildup data does not show 2 parallel straight lines with a vertical separation. Numerical solutions also are used to include the Klinkenberg effect and desorption in the shale matrix. 18 references.

Regional facies and geochemical evaluation of the southern denison trough, queensland

Abstract: Results of geochemical investigations by the Bureau of Mineral Resources (BMR) and the Commonwealth Scientific and Industrial Research Organisation (CSIRO) indicate significant potential for hydrocarbon source throughout the Permian sequence with the Cattle Creek Formation (shallow shelf mudstone and shale facies, and prodelta mudstone facies) and the Reids Dome Beds (fluvial flood basin facies) constituting the most favourable source rock facies. The source rock facies comprise dominantly humic organic matter indicating that the Permian source is mainly gas-prone. The existing mature organic zone within the trough encompasses much of the Cattle Creek Formation and a section of the Reids Dome Beds; this suggests that present-day hydrocarbon generation may be taking place within these source rocks. A complementary regional facies analysis by the Geological Survey of Queensland (GSQ) demonstrated a relationship between hydrocarbon-bearing reservoirs and facies types. Clearly distributary channel, tidal, beach and barrier bar facies constitute the most favourable reservoir facies. Within the interval covered by the Cattle Creek Formation and Aldebaran Sandstone, juxtaposition of source and reservoir facies has been recognised and could present favourable stratigraphic traps. Three zones are recognised:an area extending from Rolleston to Westgrove;within the Kildare area; andan area extending from GSQ Taroom 10 to AAO Kia Ora 1. These zones deserve further consideration. Results of this integrated investigation lends optimism to further exploration.

Eastern Green River Basin: A Developing Giant Gas Supply from Deep, Overpressured Upper Cretaceous Sandstones

Abstract: During the past 4 years, a previously unexplored 3,000-sq mi (7,800 sq km) overpressured area in the eastern Green River basin has developed into a major gas province which should ultimately produce more than 20 Tcf. Production is from lenticular sandstones in the Upper Cretaceous Lewis Shale and Mesaverde Group. Abnormally high pressure gradients of 0.5 to 0.86 psi/ft are caused by the generation of natural gas from coals and carbonaceous shales in the Mesaverde Group and perhaps from other source rocks such as the marine Lewis and Cody Shales. Because cumulative gas generation from coals increases approximately exponentially with increases in temperature and depth, the largest volumes of gas and the highest pressures should have been generated in the deepest parts of th basin. The deepest rocks (15,000 to 20,000 ft; 4,600 to 6,100 m) are sparsely explored but may prove to be the most productive parts of the overpressured area for the following reasons. (1) Higher pressures result in more gas in the available pore space. (2) Sufficient gas should have been generated at these depths to fill all available pore space in Mesaverde and Lewis sandstones, and to reduce water saturation to an immobile minimum. More total pay should thus be expected than in shallower areas where water production is a common problem. (3) Higher pore-fluid pressures increase the ease with which natural fracturing of rock units can occur and more fracturing should enhance reservoir performance. (4) Younger sandstones in the Upper Cretaceous Lance and Paleocene Fort Union Formations are also overpressured in the deepest basin areas because of gas generation from associated coals and carbonaceous shales. These formations should contain significant gas accumulations.

Geology and Petroleum Fields in Proterozoic and Lower Cambrian Strata, Lena-Tunguska Petroleum Province, Eastern Siberia, USSR

Abstract: A minimum of nine commercial and 13 non-commercial discoveries has been made since 1962 in the Lena-Tunguska petroleum province of Eastern Siberia. However, the petroleum potential of this province has scarcely been tapped because the prospective area is greater than 1,737,000 sq km. Discovered reserves are in Proterozoic marine terrigenous clastic reservoirs and Early Cambrian fractured carbonates interbedded with evaporites. The Cambrian reserves are small and are associated with salt swells and salt pillows, whereas the Proterozoic discoveries are large and are in both stratigraphic and structural traps. Most of the Proterozoic accumulations were found as a result of drilling through overlying Lower Cambrian structural traps. Generally, the discovered hydrocarbons are as and gas condensate, although some oil has been found. The original discovery field for the basin, Markovo field found in 1962, has proved and probable reserves of 622 Bcf of gas, 16 million bbl of condensate, and 10 million bbl of oil. The second largest field to date is the giant Sredne-Botuobin gas-condensate field, found in 1970. Sredne-Botuobin is a structural trap in both Proterozoic and Lower Cambrian strata. Proved plus probable reserves are 5.95 Tcf of gas and 149 million bbl of condensate. In both fields, the major reserves are in the Proterozoic. The largest field, Verkhnevilyuy, was found in 1975, and has 10.5 Tcf of proved plus probable reserves of gas and about 260 million bbl of condensate. The Yaraktin oil field was discovered during 1971 in Proterozoic strata. Proved, probable, and potential reserves are about 210 million bbl. The field is a very large stratigraphic trap. The reserve estimate is subject to upward and/or downward revision as stepout and infill wells are drilled. The potential of the area is very great. Several hundred, perhaps several thousand, oil and gas fields remain to be found. The province appears to be gas prone, but the discovery of the Yaraktin oil field indicates that some areas will have oil production. In terms of ultimate recovery, this region has the potential for producing 100 billion bbl of oil and 200 Tcf of gas, together with condensate. The existence of major to giant fields in Proterozoic strata--containing hydrocarbsons known from paleontological and geological data to have originated in Proterozoic beds--emphasizes the fact that nowhere should the Precambrian be regarded as economic basement. End_Page 225------------------------

Jurassic Cotton Valley and Smackover Reservoir Trends, East Texas, North Louisiana, and South Arkansas

Abstract: The stratigraphic and structural framework of the Jurassic Cotton Valley and Smackover in the Ark-La-Tex area can be divided into distinct producing trends, each having predictable characteristics and geographic limits. The main Cotton Valley producing trends are: (1) a semicircular belt of lower Cotton Valley limestone along the west flank of the Sabine uplift in east Texas; (2) a north-trending belt of lower Cotton Valley limestone on the west flank of the East Texas basin; (3) an arcuate belt of "blanket" sandstones centering in Lincoln Parish, north Louisiana; and (4) a broad circular area of massive fine-grained sandstones covering the general area of the Sabine uplift. Minor Cotton Valley sandstone production is developing on the west flank of the East Texas basin from low-permeability Bossier sandstones. The Smackover producing areas are: (1) updip fault traps along the Mexia-Talco fault system; (2) salt anticlines along the flank of the salt basins; (3) basement structures updip from the salt anticlines and fault system; (4) stratigraphic traps near the Arkansas-Louisiana state line downdip from the salt anticlines; (5) complex graben-fault traps associated with more intense salt features deeper within the basin; and (6) a speculative new trend updip of the Mexia-Talco fault system combining small fault traps and regional updip porosity pinchouts recently discovered by McFarlane Oil in western Henderson County, Texas, in a well with oil flows of over 1,000 bbl per day.

Coastal and Deltaic Sedimentation of Upper Cretaceous Eagle Sandstone: Relation to Shallow Gas Accumulations, North-Central Montana

Abstract: Depositional environments of the Upper Cretaceous Eagle Sandstone were studied at outcrops along the Missouri River and its southern tributaries from the town of Virgelle southeastward to the mouth of the Judith River in north-central Montana. In this area, the Eagle is divided into three members--the Virgelle Sandstone Member, 80 to 130 ft (24 to 40 m) thick, and the middle and upper members, which together are as much as 220 ft (67 m) thick. The Eagle Sandstone is underlain by the Telegraph Creek Formation and overlain by the Claggett Shale, both of Late Cretaceous age. The Telegraph Creek accumulated in an offshore-shoreface transition environment and grades upward into the shoreface and foreshore sandstones of the Virgelle Sandstone Member. The basal Virgelle was depo ited along an eastwardly prograding coastal-interdeltaic mainland shoreline. The middle member of the Eagle represents coastal-plain deposition. In the eastern part of the area, the upper part of this member comprises a sheetlike, delta-front sandstone capped by a thin coastal-plain unit. The delta-front sandstone was deposited along a wave-dominated shoreline that prograded over a coastal plain following an overall marine transgression. The upper member lies disconformably on the middle member and is represented by rock types which were deposited in two distinct depositional settings. Interbedded sandstone, siltstone, and shale that exhibit variable bedding types in the northern outcrops probably accumulated in a tidal-flat environment. Progradational cycles of shoreface sandstones are haracteristic of the upper member in the southern outcrop. Chert gravel in the upper member and in the basal part of the Claggett Shale forms a persistent time interval in the northern Rockies and probably represents a lag deposit laid down by the transgressing sea. Natural gas from shallow accumulations in the Eagle Sandstone of the Bearpaw Mountains area is of biogenic origin and was probably generated in the surrounding shales during Late Cretaceous time. Although gravity-induced faults formed after the gas generation provide the final trapping mechanism, the initial control for entrapment was stratigraphic. Most of the early generated gas has remigrated into separate, discrete structural traps where porous reservoirs are developed; some of the gas may have been selectively sealed in original stratigraphic traps. The outcropping depositional units, in particular the reservoir sandstones, can be traced into the subsurface and identified in nearby wells. Thus, an understanding of depositional environments is an important exploration tool for sha low gas accumulations.

Petroleum geology of northern central america

Abstract: Major reserves of oil exist in the Reforma area of Tabasco and Chiapas states and the Campeche Shelf of SE Mexico in high-energy, bank-edge, reef-derived or reef-associated carbonate rocks, ranging in age from Late Jurassic to earliest Late Cretaceous. It is the conclusion of this study that the Reforma reservoir facies does not extend into W Guatemala. However, there the potential for major reserves in bank and lagoonal carbonates of similar age is considered excellent. A variety of structures, mostly resulting from salt tectonics, is present. Known reservoir rocks include fractured carbonates with secondary porosity resulting from solution and dolomitization, and limestones with primary intergranular porosity.An indigenous source is likely for the large quantities of oil which have been tested at Rubelsanto. Seals, in the form of thick intervals of Cretaceous anhydrite and, in places, of Tertiary fine-grained clastics, are abundant.

A Process for Primary Migration of Petroleum

Abstract: Experimental data support a model migration process in which carbon dioxide and hydrocarbon gases are produced in source rocks and are dissolved in pore water concurrently with oil generation. The dissolved gases mobilize the liquid hydrocarbons so that they can leave the source rock with any water expelled during compaction. In noncompacting situations the liquid hydrocarbons can diffuse over reasonable distances from their source rocks into adjacent permeable beds. They later phase-separate by removal of carbon dioxide from the water in or near a reservoir or en route to a reservoir. Removal of carbon dioxide is accomplished by reaction with "carbon dioxide-starved" or unconditioned sedimentary rocks as the oil-bearing water moves up faults and permeable strata, or by e solution due to low pressure at shallow depths.

Organic Composition of Some Upper Cretaceous Shale, Powder River Basin, Wyoming

Abstract: The lower Upper Cretaceous strata in northeastern Wyoming, which have yielded major quantities of oil and gas, were sampled at boreholes in Converse, Johnson, and Weston Counties. Cores of noncalcareous shale of largely nearshore-marine origin were obtained from the Frontier Formation and the overlying Cody Shale at depths of 3,780.6 to 3,879.9 m in Converse County, near the axis of the Powder River basin, and at depths of less than 320 m in Johnson County, on the western flank of the basin. Cores of calcareous and noncalcareous shale representing offshore-marine and nearshore-marine environments were acquired from the Belle Fourche Shale, Greenhorn Formation, and Carlile Shale at depths of less than 270 m in Weston County, on the eastern flank of the Powder River basin. Analyses of the shale for organic carbon content, total pyrolytic hydrocarbon yield, volatile hydrocarbon content, temperature of maximum pyrolytic yield, and vitrinite reflectance indicate that the amount and character of the organic matter in the sampled rocks is related to the content of calcium carbonate, the depositional environment, and the burial depth of the strata. On the east flank of the Powder River basin, calcareous shale of offshore-marine origin contains abundant hydrogen-rich organic matter derived mainly from aquatic plants. Noncalcareous shale of largely nearshore-marine origin, on the west flank of the basin, locally contains significant hydrogen-poor organic matter derived mostly from land plants. The noncalcareous, nearshore-marine shale in the middle of the basin probably contained similar amounts of hydrogen-deficient organic matter prior to deep burial and thermal alteration. The calcareous shale in Weston County is a potentially rich source of oil and gas, but it is thermally immature and is in a very early stage of the hydrocarbon-generation process. The noncalcareous shale in Johnson County is a potential source rock for gas, but also is in an early stage of thermal alteration. In Converse County, the sampled beds are thermally mature and have generated hydrocarbons. The extent of this contribution of hydrocarbons to the commercial petroleum occurrences of the area can be inferred from the composition of the original organic matter in the beds. Furthermore, the degree of thermal alteration of the organic matter at these localities indicates that the depth of the sampled strata was never as great on the flanks of the Powder River basin as in the basin ce ter.

Limestone and dolomite reservoirs

Abstract: Limestones and dolomites form important reservoirs for oil and gas, but a realization of the future significance of these strata for hydrocarbon production in the noncommunist world is not known. Carbonates currently produce 38% of the oil and gas from the world's giant fields, a fair measure of overall world production, because 240 giant fields contain nearly three-quarters of the world's proven reserves. Carbonates often produce in selected large fields with approximately 60% of the world's giant fields in this type of reservoir. Dolomite and limestone also are prominent host rocks for lead and zinc sulfides in all parts of the world, a fact resulting from carbonate chemical instability and susceptibility to replacement. This work attempts a review of all aspects of the origin, facies, patterns, stratigraphy, diagenesis, and petroleum reservoir development of carbonate sediments. 113 references.

Depositional Environment and Hydrocarbon Prospects, Tanjung Formation, Barito Basin, Kalimantan

Abstract: The Tanjung Formation, which is the oldest Tertiary sedimentary section in the Barito basin, has been producing oil since the early 1960's. Geologic history of the basin can be divided into 3 sedimentation cycles, i.e.: a. Eocene-Oligocene cycle (Tab-Tcd) b. Oligocene-Miocene cycle (Tcd-Tf) c. Miocene-Pliocene cycle (Tgh) Each cycle is distinctly separated by tectonic activities. During the Eocene-Oligocene cycle the Tanjung Formation was deposited over almost the whole basinal area and overlies the Pre-Tertiary basement unconformably. The lower member consists of terrestrial and paralic clastics and red beds and the middle member of marine and deltaic shales, sandstones and coals. The upper member consists of neritic shales and silty shales, with a series of thin limestone beds and paralic clastics at the top. There is thinning and pinching out to the west and south onto the north ward tilted basement surface. A Plio-Pleistocene orogeny caused a westward movement of the Meratus block, which folded and thrust the basin's rocks into a series of north-northeast to south-southwest trending, tight anticlines that probably are controlled by basement features. Because of their transgressive and deltaic nature and due to the tectonic history of the basin, the Tanjung Formation clastics form highly potential reservoirs for structural and stratigraphic traps. A structural trap was proven by the discovery of the Tanjung oil Field, which had a cumulative production of 14,836,835 cubic meters by December, 1979, from both pre-Tertiary and Lower and Middle Tanjung reservoirs. A primary stratigraphic (lens) trap is supposed to occur in the Kambitin structure, while secondary (unconformity) traps still remain to be discovered. So far, in the subsurface this formation is only recognized from well log data, except in the Tanjung Raya area where it is also seismically identifiable. Integrated exploration efforts, using modern exploration concepts and tools, should undoubtedly be able to identify the formation in the subsurface in other areas and locate more structural and stratigraphic traps.

Petroleum Geology of Kodiak Shelf, Alaska

Abstract: Organic geochemical data show that Cenozoic rocks on Kodiak Island, in Albatross basin, and under the continental slope generally contain less than 0.5 wt. % organic carbon. Moreover, kerogen from all rocks analyzed is predominantly (60 to 100%) herbaceous; woody and coaly kerogens are present in secondary (20 to 40%) amounts. Most strata in shelf basins are thermally immature; however, Eocene and Oligocene strata, which probably floor the shelf basins, are mature on the basis of comparison with coeval strata onshore. Eocene and Oligocene rocks have poor reservoir properties; the best reservoirs are probably in upper Miocene or Pliocene and younger rocks. Potential traps for hydrocarbons include Tugidak uplift, parts of Albatross Bank, structures in the central-shelf upli t, and Portlock anticline. Overall, unless hydrocarbon source rock properties improve offshore, gas and gas condensate are the most likely hydrocarbons to have been generated.

Hydraulic oil reservoir vent

Abstract: A hydraulic oil reservoir for a mobile vehicle having the oil container of the reservoir formed in a beam of a horizontally disposed frame of the mobile vehicle. A vent assembly for the oil reservoir is comprised of a porous plug vent interconnected through a pair of hoses to two spaced openings in the top wall of the oil container. The interconnection of the two openings in the top wall of the reservoir enables the reservoir to be vented adequately while reducing the likelihood of oil expulsion through the vent when the vehicle is operated on a hillside terrain.

A Review of Carbonate Reservoirs

Abstract: Porosity and permeability in carbonate strata result from interactions between certain favored types of original sediment and a variety of diagenetic processes. Alteration may be induced by several generations of hydrographic conditions controlled in turn by the total geologic history of the reservoir area. Reservoir development is therefore highly complex. Carbonate sediment is produced and deposited with high porosity. This is normally reduced from 50% to less than 10% during diagenesis but permeability may be increased by some processes. In an analysis of hydrocarbon reservoirs, the following combinations of sediment type, stratigraphic relations and favorable diagenetic overprint persistently recur in the geologic record: 1. Lime sand bars and sheets on shelves with histories of incomplete cementation (Chesteran, Oklahoma; Murban on Trucial Coast; Arab D, Saudi Arabia; Smackover of Louisiana). 2. Carbonate organic buildups whose original high porosity and permeability along margins of banks and platforms have not been completely occluded, or whose fabric has been dolomitized and fractured (Devonian buildups in Alberta and the Golden Lane atoll of eastern Mexico). 3. Downslope talus accumulation below major carbonate bank or platform margins (Poza Rica and Reforma pools of Mexico). 4. A stratigraphic trap formed by subtidal grainstone and intertidal dolomitized mudstone reservoir which change facies updip to a sabkha anhydrite seal (Permian San Andres of West Texas and the Mississippian strata of Williston Basin). 5. Leaching and dolomitization at regional unconformities, processes aided by an original grainy texture and/or fracturing (Natih and Fahud Cretaceous fields of Oman; Late Paleozoic phylloid algal limestone of southwestern U.S.A.; basin margin pinnacle reefs of Devonian Zama-Rainbow; and Silurian of Michigan basin). 6. Chalky textured pure carbonate muds which have not been “solution welded” by burial below 1 000 m and have been protected from Mg poor solutions (North Sea Danian; Austin Chalk).

Factors controlling porosity and permeability in geopressured Frio sandstone reservoirs, general crude oil/Department of Energy Pleasant Bayou test wells, Brazoria County, Texas

Abstract: Reservoir characteristics of Frio sandstones in the GCO/DOE Pleasant Bayou No. 1 and No. 2 wells are influenced by depositional environment, sandstone composition, and diagenetic history. The sandstones and shales were deposited in deltaic and continental slope environments. Fluvial channel and distributary-mouth bar sandstones are most favorable for development and preservation of the porosity needed for a geothermal reservoir. Sandstones in the geopressured zone are lithic arkoses and feldspathic litharenites. Depositional matric (detrital material less than 20 micrometers in size) occluded most or all of the potential primary porosity between grains in many of the fine-grained sandstones at the time of deposition. Even if cements are present, dissolution of grains and development of secondary porosity do take place. Permeable geopressured sandstone reservoirs are characterized by porosity that is dominantly secondary. 12 references.

Porosity Evolution of Upper Miocene Reefs, Almeria Province, Southern Spain

Abstract: Sea cliffs 40 km east of Almeria, southeastern Spain, expose upper Miocene reefs and patch reefs of the Plomo formation. These reefs are formed of scleractinian corals, calcareous algae, and mollusks. The reef cores are as much as 65 m thick and several hundred meters wide. Fore-reef talus beds extend 1,300 m across and are 40 m thick. The reefs and reef breccias are composed of calcitic dolomite. They lie on volcanic rocks that have a K-Ar date of 11.5 m.y. and in turn are overlain by the upper Miocene Vicar Formation. In the reef cores and fore-reef breccia beds, porosity is both primary and postdepositional. Primary porosity is of three types: (a) boring clam holes in the scleractinian coral heads, cemented reef rocks, and breccias; (b) intraparticle porosity within the corals, Halimeda plates, and vermetid worm tubes; and (c) interparticle porosity between bioclastic fragments and in the reef breccia. Postdepositional moldic porosity was formed by the solution of aragonitic material such as molluscan and coral fragments. The Plomo reef carbonate rocks have high porosity and permeability, and retain a great amount of depositional porosity. Pores range in size from a few micrometers to 30 cm. The extensive intercrystalline porosity and high permeability resulted from dolomitization of micritic matrix. Dolomite rhombs are between 10 and 30 µ across. More moldic porosity was formed by the dissolution of the calcite bioclasts. Some porosity reduction has occurred by incomplete and partial sparry calcite infilling of interparticular, moldic, and intercrystalline voids. The high porosity and permeability of these reefs make them important targets for petroleum exploration in the western Mediterranean off southern Spain. In these offshore areas in the subsurface the volcanic ridge and the Plomo reef complex are locally onlapped or overlapped by 350 m or more of Miocene(?) and Pliocene fine-grained sedimentary rocks. The possibility exists that the buried Plomo reef deposits may form traps for oil and gas in the offshore areas southwest of the type locality. Stratigraphic traps also may occur where the Neogene sequence above the Plomo reef complex onlaps the volcanic ridge.

Mineralogy and diagenesis of low-permeability sandstones of late cretaceous age, piceance creek basin, northwestern colorado

Abstract: This report presents preliminary results of a mineralogic and diagenetic study of some low-permeability sandstones from measured surface sections and cores obtained from drill holes in the Piceance Creek Basin of northwestern Colorado. These sandstones are in the nonmarine upper part of the Mesaverde Formation (or group) of Late Cretaceous age and are separated from overlying lower Tertiary rocks by a major regional unconformity. Attention is focused on the sandstone units of the Ohio Creek Member, which directly underlies the unconformity; however, comparisons between the mineralogy of the Ohio Creek strata and that of the underlying sandstone units are made whenever possible. The Ohio Creek is a member of the Hunter Canyon Formation (Mesaverde Group) in the southwestern part of the basin, and the Mesaverde Formation in the southern and central parts of the basin. The detrital mineralogy is fairly constant throughout all of these nonmarine Cretaceous sandstone units; however, in the southeastern part of the basin, there is an increase in percentage of feldspar, quartzite, and igeneous rock fragments in sandstones of the Ohio Creek Member directly underlying the unconformity. In the southwestern part of the basin, sandstones of the Ohio Creek Member are very weathered and are almostmore » entirely comprised of quartz, chert, and kaolinite. A complex diagenetic history, partly related to the overlying unconformity, appears to be responsible for transforming these sandstones into potential gas reservoirs. The general diagenetic sequence for the entire Upper Cretaceous interval studied is interpreted to be (early to late): early, calcite cement, chlorite, quartz overgrowths, calcite cement, secondary porosity, analcime (surface only), kaolinite and illite, and late carbonate cements.« less

Evidences of Primary Oil Migration

Abstract: Primary hydrocarbon migration, which is defined as movement of hydrocarbons from nonreservoir to reservoir rocks, is believed to be one of the principal mechanisms in the formation of significant petroleum accumulations. Unlike the other important factors involved in petroleum accumulations, such as reservoir, trap, seal, and source rock, which are rock or a form of rock, primary migration is an action most of which occurred in the geologic past. Therefore, it is relatively difficult to prove. On the basis of the relative concentrations and types of organic matters in shales and reservoirs (sandstones and limestones), and of the availability of water that would have facilitated hydrocarbon migration, primary migration is a necessity in forming significant petroleum accumulations. Statistical and indirect evidence of primary migration is based on the 7,241 sandstone reservoirs in the United States, and geochemical evidence is based on source-rock analyses of shales from different parts of the world. The principal direction of primary migration can be either vertical or horizontal.

Regional Geology and Hydrocarbon Occurrences Off the East Coast of Canada

Abstract: Petroleum exploration has been carried out in four major Mesozoic-Cenozoic tectonic provinces off the east coast of Canada. Numerous structural and stratigraphic traps occur in the Scotian Basin continental margin clastic and carbonate wedge, which overlies a thick, mobile evaporite sequence. Maximum thickness of sedimentary rocks exceeds 11 km. The subsurface of the Grand Banks is characterized by a series of fault-bounded sub-basins with most of the trap types related to salt and basement tectonics. Sedimentary thicknesses are generally less than 7 km. The East Newfoundland Basin contains a clastic wedge superimposed on fault-bounded sub-basins with a total sedimentary thickness exceeding 12 km. Similarly, on the Labrador Shelf the thick Cretaceous-Tertiary clastic wedge covers faulted basement structures, with basal beds draped over these features. The hydrocarbon occurrences on the Scotian Shelf are predominantly gas, with some condensate and oil. Generally poor source rocks have been encountered, due partly to a preponderance of terrestrial-type organic matter and partly to thermal immaturity. There is an indication of good marine Jurassic source rocks at greater depths, which enhances the oil potential for deeper, undrilled prospects. Three good gas shows have been encountered on the Labrador Shelf. The coincidental improvement in source rocks, reservoir and seal makes the hydrocarbon potential of this area more attractive.

Recovery of oil from an oil reservoir by miscible displacement

Abstract: Oil from an oil reservoir and subsequently from several oil reservoirs is recovered by injecting, in a first stage, a displacement agent in a gaseous state into the oil reservoir. Afterwards, in a second stage, there is withdrawn 90% of the displacement agent from the oil reservoir together with water through the wells. In a third stage there is injected into a second oil reservoir this withdrawn displacement agent, after water separation and drying and compression of the agent. As in the aforementioned stages 1-3 there is withdrawn from the second oil reservoir 90% from the displacement agent left in this oil reservoir which may be injected into the third oil reservoir, etc. The entire (overall) amount of the displacement agent used is half of the amount used according to previously known processes. At the end one recovers the used displacement agent. Initially one may even use a mixture of displacement agent with impurities that are purged by the injection process itself in the first oil reservoir.

System for heating the service cabin of a motor vehicle

Abstract: An arrangement for heating the service cabin of a motor vehicle having a work implement thereon for use such as in agriculture or earth moving includes an oil distribution system having a hydraulic pump for feeding the oil from an oil reservoir associated with the vehicle and through oil conduits back to the reservoir. The oil is heated during operation of a hydraulic apparatus provided for operating the work implement which is coupled into the oil conduit for heating the service cabin area. An operating element in the form of a throttle is coupled in parallel into the oil conduits, and a return conduit leads from the throttle to the oil reservoir via the heat exchanger. A selectively operated valve in the conduits is provided for valving the oil from the reservoir to the hydraulic apparatus or to the operating element for selectively heating the oil fed through the heat exchanger. RELATED APPLICATIONS This application relates to U.S. Ser. No. 123,169, filed Feb. 20, 1980 and to U.S. Ser. No. 165,083 filed 7/1/80, both commonly owned herewith.

Estimation of two-phase petroleum reservoir properties

Abstract: The estimation of petroleum reservoir properties on the basis of production rate and pressure observations at the wells is an essential component in the prediction of reservoir behavior. The reservoir properties to be estimated appear as parameters in the partial differential equations describing the flow of fluids in the reservoir. The estimation of these properties is referred to variously as the inverse or identification problem or as history matching. In this dissertation, new results have been obtained pertaining to the estimation of petroleum reservoir properties. Most of the prior analysis of the reservoir parameter estimation problem has been confined to reservoirs containing a single fluid phase, e.g., oil. We consider here reservoirs that contain two fluid phases, e.g., oil and water. The parameters to be estimated in such a case are the porosity and permeability, which depend on spatial location, and the saturation-dependent relative permeabilities. In this work we treat two basic problems in reservoir parameter estimation: (1) establishing the ability to estimate the desired parameters (so-called identifiability), and (2) developing and testing a new algorithm, based on optimal control theory, to carry out the estimation. In regard to problem (1), we have extended the classic analytical (Buckley-Leverett) solution for incompressible flow to heterogeneous reservoirs. Analysis for an incompressible water flooding situation shows that the spatially varying properties at locations behind the saturation front have an effect on the pressure solution. The spatially varying properties can be uniquely determined based on data taken up to the time of water breakthrough. Only an integral value of the porosity can be determined from the water-oil ratio data alone; however, the spatially varying porosity may be determined when the initial saturation varies with location. The values of the relative permeabilities which are identifiable, and the information about the relative permeabilities obtained for other intervals of saturation, is established. Analytical expressions are derived for the sensitivity of the pressure and water-oil ratio observations to parameters appearing in functional forms of the relative permeabilities. When the relative permeabilities are represented as exponential functions, the coefficients and exponents can be uniquely determined. For problem (2), an algorithm is developed for the estimation of porosity, permeability and the relative permeabilities for two-phase, compressible reservoirs. This work represents the first study for which relative permeabilities have been estimated based on a model generally used to represent fluid flow in petroleum reservoirs. An objective function, composed of the weighted sum of squares of the deviations between the observed and calculated values of pressure and water-oil ratio, is minimized by a first-order gradient method based on optimal control theory. The algorithm is tested for one and two-dimensional hypothetical water floods. The algorithm performed well for problems in which the porosity, permeability and relative permeability exponents were simultaneously estimated. The increase from one to two spatial variables does not appear to change the properties of the estimation problem. Small observation errors are shown not to significantly affect the convergence of the estimates.

Effect of permeability on cooling of a magmatic intrusion in a geothermal reservoir

Abstract: Transient cooling of magmatic intrusion in a geothermal reservoir due to conduction and convection is studied. The effects of overlying cap rock and different horizontal and vertical permeability of the reservoir are considered. Results are compared to the data from Salton Sea Geothermal Field. It is also observed that multiple layers of convection cells exist when horizontal permeability is much larger than the vertical permeability. The sharp dropoff of surface heat flow observed at Salton Sea Geothermal Field is confirmed by numerical results. Based on these numerical results, it is possible to speculate that the age of the intrusive body is about 8000 to 12,000 years.

Hot dry rock geothermal site evaluation, Western Snake River Plain, Idaho

Abstract: Geologic, geophysical, hydrologic, and water chemistry studies have been performed to evaluate a hot dry rock geothermal prospect along the northern margin of the Western Snake River Plain, Idaho. The potential reservoir rock, Idaho Batholith granite, outcrops just north of the site, and is step faulted down to the south; it is more than 3 km deep in the southern part of the site. The central and northeastern parts appear to be the most promising for HDR development. Geophysical data suggest: (1) high permeability at depth in the NW corner, and (2) too great a depth to granite in the south. Thermal disturbances from ground water may affect heat flow reported from shallow measurements. Silica geothermometers indicate equilibrium temperature not significantly above the 60 to 80/sup 0/C measured in hot springs and wells. Future work, including a seismic reflection survey and an exploratory well, is planned to further define the thermal regime, the depth to granite, and its permeability.

Porosity of Reservoir Rocks

Abstract: Sedimentary rocks consist of grains of solid matter with varying shapes which are more or less cemented, and between which there are empty spaces (Fig. 11.1). It is these empty spaces which are able to contain fluids such as water or liquid or gaseous hydrocarbons and to allow them to circulate. In this case the rock is called porous and permeable.

The fortescue field - new oil in the gippsland basin

Abstract: The Fortescue-1 well drilled in the Gippsland Basin in June 1978 was a dry hole. However, results of detailed stratigraphic analysis together with seismic data provided sufficient information to predict the possible occurrence of a stratigraphic trap on the flank of the giant Halibut structure. Three months later the West Halibut-1 well encountered oil in the Latrobe Group 16 m below that depth carried as the original oil-water contact for the Halibut field. Following wireline testing in both the water and oil-bearing sandstone units, two separate pressure systems were recognised in the well. Three additional wells, Fortescue-2, 3 and 4, were drilled to define further the limits of the field, the complex stratigraphy and the hydrocarbon contacts. Integration of detailed well log correlations, stratigraphic interpretations and seismic data indicated that the Fortescue reservoirs were a discrete set of units stratigraphically younger and separated from those of Halibut and Cobia Fields. Analysis of pressures confirmed the presence of two separate pressure systems, proving none of the Fortescue reservoirs were being produced from the Halibut platform. Geochemical analysis of oils from both accumulations supported the above results, with indications that no mixing of oils had occurred. Because the Fortescue Field is interpreted as a hydrocarbon accumulation which is completely separated from both Halibut and Cobia Fields, and was not discovered prior to September 17, 1975, it qualified as "new oil" under the Federal Government's existing crude oil pricing policy. In late 1979, the Federal Government notified Esso/BHP that oil produced from the Fortescue Field would be classified as “new oil”.