Showing papers on "Petroleum reservoir published in 1977"

Chalk Diagenesis and Its Relation to Petroleum Exploration: Oil from Chalks, a Modern Miracle?

Abstract: Chalks consist largely of stable low-magnesium calcite. Thus, they undergo diagenetic alteration different from that of more widely studied aragonite and high-magnesium calcite-bearing, shallow-marine carbonate deposits. Examination of outcrop and subsurface samples of chalks from the North Sea, onshore Europe, the Scotian Shelf, Gulf Coast, and the U.S. Western Interior indicates that chalks undergo significant diagenetic changes during their postdepositional history. Scanning-electron microscopy, light microscopy, oxygen-isotopic analysis, and trace-element analysis outline the major factors that control the patterns of chalk alteration. The major mechanism of chalk cementation is pressure solution and local reprecipitation. Although small variations in initial grain size, faunal composition, or clay content can lead to significant bed-to-bed variations in cementation, overall patterns of chalk diagenesis appear to be related to two main factors: (1) maximum depth of burial, and (2) pore-water chemistry. With a few notable exceptions, the porosity (and permeability) of chalks decreases as a direct function of burial depth. The exceptions include cases where: (1) oil entered the rock, reducing or terminating carbonate reactions; (2) chalks are overpressured and therefore are not subject to the normal grain-to-grain stresses expected at those depths; and (3) tectonic stresses increase solution and cementation. In areas here fresh water entered the pores before major burial, chalks show a much steeper gradient of porosity loss versus burial depth as compared with regions where marine pore fluids were retained. Under normal circumstances, a typical nannofossil chalk ooze will have 70% porosity at the sediment-water interface. At a depth of 1 km, porosity will be reduced to about 35%; at 2 km, to about 15%; and at 3 km, to essentially 0. Thus, one observes progressive lithification of chalks (and their isotopic alteration) as one moves downhole or toward areas of greater burial. Petrophysical and isotopic studies can predict maximum depths of burial, paleogeothermal gradients, and proximity to zones of deformation. In areas such as the Ekofisk field in the North Sea, however, major quantities of oil are produced from chalks having as much as 40% porosity (largely primary) at depths greater than 3 km. This appears to be related largely to the widespread overpressuring of the Central graben in that area. Other such areas of anomalous porosity in thick chalk sections should be detectable by seismic methods. Significant hydrocarbon production from chalks can occur in three major settings: (1) overpressured or oil-saturated zones where these phenomena were initiated early in the subsidence history (e.g., the North Sea); (2) areas where chalks never have been buried deeply (e.g., the Scotian Shelf); and (3) cemented and fractured chalks in several possible settings (e.g., the Gulf Coast).

Oil and gas in reservoirs with subnormal pressures

Abstract: Oil and gas are common in stratigraphic traps in structural basins, both deep down near the bottom, and also along the flanks. In many of these traps initial reservoir pressures were subnormal, indicating a lack of permeable connection to the outcrop. Some maps drawn on the potentiometric (piezometric) surface using pressure data from drill-stem tests show clearly the location of the stratigraphic barriers which have trapped the oil; these maps should be used in prospecting. Many giant gas fields with abnormally low initial reservoir pressures are low on the flanks of structural basins. The geologic factors favoring this type of accumulation are not understood. The cause of the low pressures may be related to removal of overburden, which has resulted in a dilation of the pore volume in the rocks, and a decrease in reservoir temperature.

Distribution of Hydrocarbons Between Oils and Associated Fine-Grained Sedimentary Rocks--Physical Chemistry Applied to Petroleum Geochemistry, II

Abstract: Amounts and ratios of hydrocarbons in nonreservoir rocks (potential source rocks) can be compared with associated oils if, in relatively old and stable geologic situations, the hydrocarbons reach or closely approach a distribution equilibrium between source rock and reservoir. A distribution-equilibrium equation makes possible the calculation of the composition of a hypothetical oil expected from the composition of the hydrocarbons in the nonreservoir rock and from the different tendencies of the hydrocarbons to be absorbed tendencies have been measured and the hypothetical oil compositions calculated and compared with those of the real oils. The hypothetical and actual oil compositions agree very well in some relatively old and deep sedimentary deposits in which the source rocks and associated oils probably are related genetically. On the other hand, there is relatively poor agreement in some relatively young and shallow deposits, but the agreement appears to improve with increasing depth and age. One explanation for this is that the hydrocarbons in the relatively young and shallow oils may not be related genetically to associated young and shallow source rocks, but came from older and deeper ones. Alternatively the hydrocarbons in the young and shallow reservoirs and in the associated source rocks, in fact may be related genetically, but do not appear to be in distribution equilibrium because primary migration is still o curring. These findings imply that certain petroleum components, particularly the saturated hydrocarbons, are generated and migrate over relatively long periods of time. The results also may imply that the generation of petroleum components in fine-grained sedimentary rocks causes primary migration. Perhaps it is unreasonable to assume that perfect equilibrium may be reached between source rock and reservoir, but this is the presupposition made when looking for close similarities in compositions of oils and rock extracts in order to correlate oils with source rocks.

Experimental Study of Fracture Permeability in Porous Rock

Abstract: Fluid flow through fractured porous subsurface reservoirs is an important but often unquantified property. The necessary quantification of this flow is achieved by both laboratory and field measurements. Laboratory experiments of the effect of temperature and confining pressure on permeability in Navajo Sandstone indicate that simulated fractures in porous rock (1) have a higher percentage rate of permeability decline with depth than whole rock, (2) experience a greater degree of permanent deformation with depth than whole rock, (3) are healed effectively when fracture permeabilty approaches that of the whole rock, and (4) experience a reduction in permeability dependent on the macroscopic ductility and previous maximum depth of burial of the host sandstone.

Lisburne Group (Mississippian and Pennsylvanian), Potential Major Hydrocarbon Objective of Arctic Slope, Alaska

Abstract: The Lisburne Group, a thick carbonate-rock unit of Mississippian and Pennsylvanian age, is one of the most widespread potential reservoir-rock units in northern Alaska. A comprehensive review of the Lisburne in the subsurface of the eastern Arctic Slope indicates attractive reservoir characteristics in a favorable source and migration setting where numerous trapping mechanisms appear to be available. Evaluation of this group as a potential exploration objective is particularly timely because of impending offshore sales in the Beaufort Sea and current exploration programs under way in the Prudhoe Bay area and the Naval Petroleum Reserve. Dolomite and sandstone have been identified as reservoir rocks. Oolitic grainstone is a common rock type, but observations indicate little reservoir potential owing to complete void filling by calcite cement. The most important reservoir rock as judged by thickness, areal extent, and predictability is microsucrosic (10 to 30µ) dolomite of intertidal to supratidal origin. It is present throughout the Lisburne and is most abundant near the middle of the sequence. Northward it decreases in thickness from 1,000 ft (300 m) to less than 100 ft (30 m). Porosity of the dolomite as determined in selected wells averages between 10 and 15% and attains a maximum of slightly more than 25%. Net thickness of reservoir rocks (i.e., rocks with greater than 5% porosity) ranges in these wells from 40 to 390 ft (40 to 120 m). Oil shows are common, and drill-stem tests have yielded as much as 1,600 bbl/day of oil and 22 MMcf/day of gas in the Lisburne pool of the Prudhoe Bay field and as much as 2,057 bbl/day of salt water outside the field area. The occurrence of dolomite over such a large area makes its presence in the offshore Beaufort Sea and adjacent Naval Petroleum Reserve 4 fairly certain. The presence of sandstone as thick as 140 ft (40 m) in the middle and upper part of the Lisburne in two coastal wells suggests that larger areas of sandstone may be found on the north in offshore areas. Shows of oil and gas and a saltwater flow of 1,470 bbl/day have been recorded from this sandstone facies. Shales of Permian and Cretaceous ages unconformably overlie the Lisburne, providing adequate sealing beds above potential reservoirs. Impermeable limestone (completely cemented grainstone) and thin beds of shale may serve as seals within the Lisburne, but the possibility of fractures in these units may negate their sealing capability. The most favorable source rock for Lisburne hydrocarbons appears to be Cretaceous shale that unconformably overlies the Lisburne east of Prudhoe Bay. This shale is reported to be a rich source rock and is the most likely source for the entire Prudhoe Bay field. A source within the Lisburne or within the underlying Kayak Shale is postulated for oil shows in the southernmost Lisburne wells. This postulated source may be in a more basinal facies of the Lisburne and may be similar to dark shale in the upper Lisburne in thrust slices to dark shale in the upper Lisburne in thrust slices in the Brooks Range. Coal in the underlying Endicott Group is a possible source for dry gas. At present, much of this coal probably is in a gas-generating regime downdip from the Prudhoe Bay field. Stratigraphic traps involving the Lisburne Group may have resulted from widespread Permian and Cretaceous unconformities. Structural traps related to normal faulting may be present along the trend of the Barrow arch, and faulted anticlines are numerous in the foothills of the Brooks Range. Combination traps are possible along the trend of the Barrow arch.

Distribution and Continuity of Carbonate Reservoirs

Abstract: Industry's production experience in Canada includes carbonates ranging in age from Ordovician to Triassic. They encompass the whole domain of carbonate reservoir types, from the small pinnacle reefs of Silurian and Middle Devonian age in Ontario and the Rainbow basin of northern Alberta, through the large Leduc and Slave Point reef complexes of central Alberta, to widespread shoals and carbonate banks of Devonian, Mississippian and Triassic age extending over much of the Western Canada basin. Carbonate reservoirs are characterized by extreme heterogeneity of porosity and permeability, often within a single pool. They range from massive, vuggy and fractured reservoir types in the organic-reef facies, to highly stratified, often vertically discontinuous reservoirs in the back-reef and shoal facies. Depletion plans for these pools, most of which are on enhanced recovery operation, require detailed, integrated geological-engineering studies. Initially, reservoir description, consisting of lithofacies, correlation cross-sections and fluid saturation studies, is used to develop reservoir engineering numerical models. Continued monitoring of operating performance is essential to ensure that the geological model is valid. Four representative pools will be reviewed to illustrate how the internal reservoir geometry has affected performance. In addition, the Judy Creek Beaverhill Lake ''A'' reservoir will be discussed to illustratemore » how detailed geological-engineering studies can change the operating practice within a pool. This field was changed from a peripheral flood to a pattern flood, resulting in substantial increase in expected oil recovery.« less

Frozen-in hydrocarbon accumulations or diagenetic traps; exploration targets

Abstract: Porosity and permeability of clastic and carbonate reservoir rocks are reduced progressively during burial by plugging of pores with secondary, pressure-dependent, diagenetically derived cements. The depth at which all effective porosity and permeability is lost in water-bearing reservoir rocks varies according to their mineral content. The presence of hydrocarbons in a reservoir inhibits the process of diagenetic plugging with the result that porosities and permeabilities differ greatly above and below an oil/water contact. This difference in diagenetic evolution within and outside the oil column indicates early emplacement of oil in a trap. Furthermore, diagenetic plugging inhibits the entry of any later generated oil and makes the lateral flushing of oil from a trap progressively more difficult with burial. When diagenetic plugging below a hydrocarbon paleotrap is complete, the accumulation is sealed in, and deeper burial with attendant pressure and temperature increases results in natural cracking of trapped oil to gas with phase-change expansion causing geopressuring of the depletion-type reservoir. When a diagenetically sealed trap later is tilted regionally or locally the accumulation will be held in place despite its unfavorable structural position. Such diachronous traps are designated ''diagenetic'' as opposed to ''structural'' or ''stratigraphic.'' Effective search for diagenetic traps requiresmore » careful paleostructural analyses coupled with documentation of diagenetic porosity-destruction sequences for each objective reservoir rock during burial. Because of the lack of present-day structural or primary stratigraphic closure and the unconventional nature of the trapping concept, there probably are many diagenetically trapped hydrocarbon accumulations yet to be discovered, particularly in deeper basin positions.« less

Current oil and gas production from North American Upper Cretaceous chalks

Abstract: Production of oil and natural gas from North American chalks has increased significantly during the past five years. Chalk reservoirs have been discovered in the Gulf Coast in the Austin Group, Saratoga and Annona Chalks, Ozan Formation, Selma Group, Monroe gas rock, (an informal unit of Navarro age), and other Upper Cretaceous units. In the Western Interior, production has been obtained from the Cretaceous Niobrara and Greenhorn Formations. Significant discoveries of natural gas and gas condensate also have been made in the Upper Cretaceous Wyandot Formation on the Scotian Shelf of eastern Canada. All North American chalk units share a similar depositional and diagenetic history. The diagenetic history of a chalk is critical in determining its reservoir potential. All chalk has a stable composition (low-Mg calcite) and very high primary porosity. With subsequent burial, mechanical and chemical (solution-transfer) compaction can reduce or completely eliminate pore space. The degree of loss of primary porosity in chalk sections is normally a direct function of the maximum depth to which it has been buried. Pore-water chemistry, pore-fluid pressures, and tectonic stresses also influence rates of cementation. Oil or gas reservoirs of North American chalk fall into three main groups: 1. Areas with thinmore » overburden and significant primary porosity retention. 2. Areas with thicker overburden but considerable fracturing. 3. Areas with thick overburden in which marine pore fluids have been retained.« less

Energy extraction characteristics of hot dry rock geothermal systems

Abstract: The LASL Hot Dry Rock Geothermal Energy Project is investigating methods to extract energy at useful temperatures and rates from naturally heated crustal rock in locations where the rock does not spontaneously yield natural steam or hot water at a rate sufficient to support commercial utilization. Several concepts are discussed for application to low and high permeability formations. The method being investigated first is intended for use in formations of low initial permeability. It involves producing a circulation system within the hot rock by hydraulic fracturing to create a large crack connecting two drilled holes, then operating the system as a closed pressurized-water heat-extration loop. With the best input assumptions that present knowledge provides, the fluid-flow and heat-exchange calculations indicate that unpumped (buoyant) circulation through a large hydraulic fracture can maintain a commercially useful rate of heat extraction throughout a usefully long system life. With a power cycle designed for the temperature of the fluid produced, total capital investment and generating costs are estimated to be at least competitive with those of fossil-fuel-fired and nuclear electric plants. This paper discusses the potential of the hot dry rock resource, various heat extraction concepts, prediction of reservoir performance, and economic factors, andmore » summarizes recent progress in the LASL field program.« less

Geologic characteristics of a portion of the Salton Sea geothermal field

Abstract: The examination of drill cuttings and core samples from the Magmamax Nos. 2 and 3 and Woolsey No. 1 wells indicate that the sequence of sedimentary rocks in the Salton Sea geothermal field from the surface to below 4000 ft can be divided into three categories: cap rock, unaltered reservoir rocks, and hydrothermally altered reservoir rocks. The cap rock extends from the surface to a depth of approximately 1100 ft in all three wells. There is evidence to suggest that the cap rock has undergone self-sealing through time as a result of the circulation of hot brine through the rocks. Essentially unaltered reservoir rocks extend from a depth of 1100 ft to approximately 3000 ft. The mineralogical and textural changes that occur at depth can be attributed to the process of hydrothermal alteration. Alteration has occurred in a chemically open system and the important variables in the alteration scheme have been temperature, permeability, brine composition, and rock composition. The transition from unaltered to altered reservoir rocks is marked by the replacement of calcite by epidote. The first appearance of epidote correlates reasonably well with the top of the alteration zone as determined in other studies by electric log analysis. Biotite more » and chlorite, potential indicators of alteration zones, are considered to be of detrital origin rather than hydrothermal origin. The primary effect of hydrothermal alteration on the reservoir rocks in the Salton Sea geothermal field has been the reduction of porosity and permeability with depth. Petrographic analysis indicates that porosity and permeability in the field is enhanced by the presence of fractures in shales. The geologic picture that emerges from spontaneous potential (SP) log correlation is that of a structural basin whose axis lies to the northwest of Magmamax No. 2. The data suggest that unaltered reservoir rocks on the periphery of the field offer good production possibilities. « less

Petroleum Geology of Eastern Brazilian Continental Margin

Abstract: Five petroleum provinces are known on the eastern Brazilian continental margin: Reconcavo, Sergipe-Alagoas, Espirito Santo, Potiguar, and Campos. Analysis of the petroleum habitat in these areas differentiates five petroleum reservoir systems: Late Jurassic, Neocomian, Aptian, Albian-Santonian, and Late Cretaceous-Tertiary. These systems are associated with five stages in the tectono-sedimentary evolution of the Brazilian coastal basins. 1. In the Late Jurassic petroleum reservoir system the reservoir rock is a fluvial blanket sandstone deposited during the prerift intracratonic stage. The petroleum migrated from Neocomian shales and was trapped by faulted blocks or unconformities on the crest of regional highs. The Agua Grande and Dom Joao fields in the Reconcavo basin, as well as the Caioba field in the offshore part of the Sergipe basin, are typical examples of this system. 2. The Neocomian petroleum reservoir system is associated with the deltaic-lacustrine depositional suite of the rift-valley stage. The oil is trapped in arched structures within regional depressions which have subsided along major fault trends. The Miranga and Aracas fields in the Reconcavo basin are the best examples. Minor stratigraphic fields such as Candeias in the Reconcavo basin also belong to this system. 3. The Aptian petroleum reservoir system is associated with the evaporitic stage. The petroleum was generated in euxinic shales and accumulated in conglomerates and sandstones. The traps are broad and gentle paleogeomorphic highs or structures contemporaneous with the evaporitic section. The Carmopolis and Riachuelo fields in the Sergipe-Alagoas basin are typical examples. 4. The Albian-Santonian petroleum reservoir system is associated with sandstones and carbonate rocks of the shallow-marine proto-oceanic stage. The oil accumulations are sealed in faulted blocks and paleogeomorphic traps. The Garoupa and Namorado fields in the Campos basin are examples. 5. The Late Cretaceous-Tertiary petroleum reservoir system is in turbidites of the open-oceanic stage. The oil fields are stratigraphic-trap type and the source rocks are continental-slope shales of the Calumbi Member and Urucutuca Formation. The Guaricema field in the offshore part of Sergipe basin and the Fazenda Cedro field in Espirito Santo basin are good examples of this system.

Patterns of Porosity and Cement in Ooid Reservoirs in Dogger (Middle Jurassic) of France

Abstract: In the Chailly oil field (Dogger, Middle Jurassic) of the Paris basin, France, an ooid facies is the producing reservoir, but not all wells are productive. The initial porosities of modern oolitic sands range from approximately 35 to 45%. In the ooid facies of the Chailly wells of this oil field the only cement is a fringe of radial crystals coating the ooids; most initial porosity, an estimated 30%, has been preserved. In the St. Brice-Villeneuve wells initial pore space has been obliterated in two ways: by pressure solution which created a tightly compacted oolitic limestone lacking porosity, and by cementation with calcite crystals (generated elsewhere by pressure solution) of noncompacted ooids. In the Marolles wells of this oil field porosity is present above a paleo ater table in the former vadose zone, but original pores have been eliminated below the paleowater table in the former phreatic zone. Thus the patterns responsible for the presence or absence of porosity are related to pressure solution with its attendant reduction of porosity and generation of cement which occludes pores elsewhere in noncompacted ooids, and the position of a paleowater table in the original depositional environment.

Geothermal and Geopressure Patterns of Bayou Carlin-Lake Sand Area, South Louisiana: Implications

Abstract: The Bayou Carlin-Lake Sand area is part of a well-known "hot belt" and geopressured region of south Louisiana. The area is characterized by a rim syncline (with Cote Blanche salt dome) on the northwest, a gulfward-dipping growth fault on the south, and productive structures of Lake Sand, East Lake Sand, and Bayou Carlin fields. Lake Sand field produces mostly gas from the anticline on the downthrown side of a growth fault. In East Lake Sand field gas accumulations are on the upthrown side of the eastward extension of the growth fault. Bayou Carlin field consists essentially of stratigraphic traps north and northeast of the two fields. The mapping of the geopressured zone shows that its roof shallows over the structural highs and the downthrown side of the growth fault, an that the geopressure roof has thermal halos over the structural highs. The geothermal mapping of structural horizons in the hydropressured and geopressured zones indicates that the isothermal contours approximate the subsurface structures. The geoisotherms (depth contours) of the 250°F (121°C) datum and isotherms (temperature contours) at four depth levels (10,000; 12,000; 14,000; and 16,000 ft or 3,048; 3,658; 4,267; 4,877 m) suggest that the structural highs are associated with thermal highs, and that the rim synclinal zone of the Cote Blanche salt dome is hot because of a greater heat flow from the salt diapir. These features also are reflected by the computerized residuals of the isotherms from the first-order polynomial surfaces at those depth levels. The geothermal highs on the productive structures, particularly those associated with growth faults, easily are explainable in terms of the mechanism of primary migration of hot fluids from the deeper levels up the fault planes into the permeable sand bodies in the vicinity of the faults. The geothermal mapping technique, possibly with appropriate computer applications, has great potential as an effective adjunct to the conventional tools used for petroleum exploration. The geothermal approach is recommended for selecting areas of possible petroleum prospects prior to detailed appraisal, for delineating untested rollover anticlines against growth faults, and for locating deeper hydrocarbon accumulations of commercial significance.

Process for recovery of hydrocarbons

Abstract: A process for the recovery of hydrocarbons from oil field reservoirs, wherein dry pipeline quality natural gas, essentially entirely methane, is injected, stored and recycled in the wells of the reservoir to effect a significant recovery of the oil in the reservoir while storing and holding the gas for ultimate use only after the oil has been recovered from the reservoir, whereby the relatively scarce gas is utilized to its maximum extent and oil is produced which would be otherwise difficult or uneconomical to produce by prior known processes. The process can be utilized in an oil reservoir at any stage of pressure depletion; but, is most uniquely applicable in oil reservoirs which are: (1) essentially depleted of primary energy, (2) reservoirs which have undergone successful secondary recovery processes (primarily water flooding), (3) reservoirs which have undergone unsuccessful secondary recovery efforts due to adverse rock or fluid properties which caused premature breakthrough of injected or "driving" fluid, (4) in primary depleted reservoirs which are not considered as candidates for secondary recovery processes, or (5) reservoirs which have undergone tertiary recovery processes which have left substantial volumes (or percentage saturation) of oil in-place.

Natural Gas From Geopressured Aquifers

Abstract: This paper examines potential for natural gas production from geopressured Gulf Coast reservoirs whose thermal and mechanical energy production would be marginal or sub-marginal in relation to requirements for electricity generation. A base case evaluation with reservoir characteristics similar to those previously published for Frio Formation reservoirs in South Texas revealed reservoir criteria for producing natural gas to be much less stringent than for electricity generation. Parametric studies of cost for producing natural gas as the value of individual reservoir parameters is varied to reveal maximum sensitivity to those parameters most difficult to quantify. These are effective in-situ permeability, pay zone thickness, reservoir drive and drainage area. Potential significance of reservoir characteristics not reflected in the calculations are qualitatively discussed. These are the pressure dependence of compaction drive and permeability, the possibility of a gas drive due to gas trapped in pores as a result of relative permeability and the possibility of an increasing gas/water ratio due to expansion of the trapped gas resulting in finite permeability to natural gas.

An evaluation of the hydrocarbon potential of the proposed Great Bear Wilderness Area, Flathead, Teton, and Pondera counties, Montana

Abstract: The proposed Great Bear wilderness study area has very good potential for discovery of natural gas resources and somewhat lesser potential for oil production. The area contains numerous potential hydrocarbon reservoir and source rocks. Structural traps for the accumulation of gas in the subsurface cannot be determined without seismic surveys and possibly drill holes, but structural traps can be inferred from a comparison of the surface geology of the study area with that in gas producing areas to the north in Alberta, Canada. The proposed wilderness study area is in the northern disturbed belt of Montana which contains a structural and stratigraphic history similar to that in the Alberta disturbed belt which contains major reserves of gas and minor amounts of oil. Successful gas exploration has been conducted a few miles east of the study area, but no seismic or drilling operations have been conducted within the area. Five wells east of the area were drilled in the 1950's. All these wells recovered natural gas but were shut-in, or abandoned, because the region was too remote and the price of gas too low for profitable production. These wells had a total potential productive capacity of 6.3 million cubic feet ofmore » gas per day. The area contains potential hydrocarbon reservoir rocks of Devonian, Mississippian, Jurassic, and Lower Cretaceous ages of which most of them produce oil and/or gas from fields to the east on the Sweetgrass Arch. Some of the potential reservoir units thicken markedly within the study area. All potential reservoir units are overlain by shale, a common cap-rock for hydrocarbons.« less

Method for increasing the recovery of oil and gas from a water invaded geo-pressured water drive oil reservoir

Abstract: A method for the economic recovery of significant additional quantities of oil and gas from a geo-pressured water-drive oil reservoir where oil production has ceased by conventional production techniques and equipment. The method increases the recovery from this type of reservoir, after primary depletion by conventional techniques, by producing the water (and a quantity of oil) from the wells at an abnormally high rate of flow and thereby induces a significant pressure drop in the reservoir remote from the well. This will then induce a significant release of solution gas from the oil through the reservoir. Since the residual hydrocarbon saturation in a water-wet porous media is a constant value for a given reservoir rock, a part of the gas released from solution will increase the hydrocarbon saturation and allow a portion of the oil and gas to become mobile and migrate to the producing wells to be recovered.

An analysis of the production performance of the windalia sand reservoir of the barrow island oil field

Abstract: The Windalia Sand is a high porosity, low permeability oil reservoir. Currently 454 wells penetrate the unit for production or water injection operations, and are drilled on a north-south, east-west 16 ha (40 ac.) spacing. Early production performance data indicated a trend of water break-through into wells located east and west of water injection wells in an inverted nine-spot pattern. This early trend has continued and the east- west break-through has become more widespread with time. It was recognised that it could be possible to improve the performance of the waterflood if the factors causing the phenomenon were able to be identified. A detailed geological review of well data was initiated to investigate causes and possible controls of the phenomenon and to determine if oil recovery could be improved. This work was augmented by an engineering study of production data. Subsequently, a computer model was developed to investigate the simulated effects of changes to well patterns on the field's production performance. The geological review determined that the reservoir contains significant local and transitional irregularities (or inhomogeneities). The mapping of a number of reservoir parameters has shown there are genetic patterns or trends and these are postulated as being at least partial controls of preferential direction of fluid movement. Previously the reservoir had been regarded as being a more uniform "layer-cake" sand. Well completion practices and timing together with production and injection methods are thought to have accentuated the latent genetic controls. Imposed pressure parting has been postulated, on engineering premises, as a control of fluid movement. The modelling study used the notion of anisotropic permeability in attempting to history-match production performances. Because of the reservoir size and anisotropy it was impractical to model the entire field. Selected type areas within the reservoir were studied. Good history-matching of various well types (based on location within a pattern) was possible. Predictions of production performance can be made for various simulated pattern changes allowing feasibility studies to be made of possible conversion programs. East-west producing wells are being converted to injectors as they water out. This program has converted part of the reservoir to a line-drive injection configuration and improved performance in these areas is evident.

Mississippian Combination Trap, Bindley Field, Hodgeman County, Kansas

Abstract: Bindley field, Hodgeman County, Kansas, is a combination paleogeomorphic and facies trap developed in lower Mississippian dolomite. Mapped originally as a simple domal anticline in an area of slightly thicker Mississippian section, this oil trap was found to be localized in a highly porous, low relief, bryozoan-mound facies of the "Warsaw" Formation. The reservoir facies was exhumed and given additional relief by at least two periods of erosion before final burial beneath Middle Pennsylvanian sediments. Paleontologic evidence indicates that beds of Salem age are present in the so-called "Warsaw" of the Bindley field area. Diagenesis drastically has modified original patterns of sediment texture. Early cementation of crinoid grainstones occluded porosity; dolomitization of muddy facies and dissolution of skeletal particles enhanced porosity; and silica replacement of evaporite and carbonate sediments further modified original sediment properties. Solution cavities and nontectonic fracturing are obvious results of subaerial weathering overprinted on other sediment features. Factors to be considered in future exploration for other oil traps in the subcropping trend of rocks of similar age in western Kansas are: (1) the difficulty of predicting areas of bryozoan-mound facies development, and (2) the fact that seismic-reflection mapping may not disclose the true vertical relief of the reservoir facies within the enclosing sedimentary rocks. Once production is established, complex reservoir behavior in fields of this type may be explicable in terms of details of reservoir lithology.

Ratio of Petroleum to Water During Primary Migration in Western Canada Basin: GEOLOGIC NOTES

Abstract: Studies on the mechanism of primary migration involve some estimate of how much oil is carried out of the source rocks with the expelled water. A few ppM hydrocarbon in water can be explained by a solution mechanism but an oil-phase migration mechanism would require a much higher concentration of oil in water. The calculation of the oil/water ratio of fluids expelled during compaction of the Western Canadian basin was made for latitudes 49 to 60/sup 0/N. A table shows the porosity loss for each rock type and the total volume of water expelled from the fine-grained sediments. This porosity decrease calculates as a water loss of about 480,000 cu km, equivalent to about 480 x 10/sup 12/ MT for this part of the Western basin. Calculations are also made for ultimate recoverable oil potential and the mass of oil that is released by a given mass of source rocks. Results indicate that the quantity of hydrocarbons released from the source beds stand at about 6 to 16 percent of that still in place. (MCW)

Deep-Water Oil Sand Reservoirs—Ancient Case Histories and Modern Concepts

Abstract: Written after the author had an opportunity to sudy reservoir rock strata deposited by a variety of transport agents while part of the Deep Sea Drilling Project, this publication provides information and figures relating to the study of modern and ancient turbidites, and the interpretations of Deep Sea Drilling Project data, as well as nonturbidite sand transport mechanisms.

Solution chemistry and scaling in hot dry rock geothermal systems

Abstract: Field and laboratory experiments have focused on measuring the kinetics and equilibria associated with the transport of minerals from granite to circulating aqueous solutions. Presently two wellbores drilled to a depth of approximately 10,000 ft in the Valles Caldera region of the New Mexico Jemez mountains permit closed-loop circulation of fluid through a hydraulically fractured granite geothermal reservoir containing rock at 200/sup 0/C. Field measurements have dealth primarily with the buildup of dissolved and suspended material in water as it is circulated through the fractured region. Chemical treatment methods, involving the selective dissolution of quartz (SiO/sub 2/), a major component of granite, with sodium carbonate solutions have been employed to increase the in situ permeability of the rock matrix. Laboratory measurements have concentrated on identifying the effects of temperature, pH and chemical additives on the solubility of granite samples taken from the two test wellbores. Promising results from these solubility experiments are tested in a laboratory-scale circulating system to examine kinetic parameters influencing rock dissolution and reprecipitation (scaling) under conditions that simulate the in situ reservoir and heat exchange environments.

Cambro-Ordovician potential of the Rome trough of Eastern Kentucky

Abstract: Studies of the Rome trough in central and E. Kentucky have delineated several large, untested areas containing thick pre-Knox, Cambrian sandstone reservoirs at moderate (5,500- to 10,000-ft) depths. Potentially productive reservoirs in the overlying Upper Cambrian and Lower Ordovician Knox Dolomite in Kentucky are equivalent in age and lithology to the prolific Ellenburger Dolomite of W. Texas and the Arbuckle Dolomite of the Mid-Continent. The Ordovician Trenton-Black River-St. Peter sequence of Kentucky is equivalent to the productive Simpson-Viola of Oklahoma. A lithological chart shows the oil- and gas-bearing zones. Age dating of hydrocarbons recovered from the Rome and Conasauga zones shows Cambrian origin, and shows of high-gravity oil or gas have been recorded in the zones indicated. Souce beds within the Cambro-Ordovician have been identified which interfinger with excellent sandstone and dolomite reservoirs. There is good evidence that growth faults developed with thick Cambrian sand buildups on their downward, basinward sides. Graphical presentations include (1) surface structure form lines and faults, Rome trough; (2) south to north cross section; and (3) pre-Knox cross section.

Diagenetic patterns of the Austin group and their control of petroleum potential

Abstract: The chalk of the Austin Group shows striking regional variations in porosity, permeability, and trace element and isotopic geochemistry. Porosities and permeabilities are highest across the San Marcos arch, where average values of 15 to 30% porosity and 0.5 to 5 md matrix permeability are measured. The future oil and gas discoveries in the Austin and equivalent lithologies will probably be concentrated in 3 types of areas: (1) where the chalks may have had any type of pore fluid but have not been deeply buried; (2) where marine pore fluids were retained and fresh water was excluded; and (3) where abnormally high pore-fluid pressures have reduced effective compressive stresses. Other production may come from areas that have low matrix porosity but intense fracturing (as along sharp flexures or faults) or from areas of abnormal lithology (e.g., bioherms, intrusive volcanic rocks, calcarenites).

Structural Style in Relation to Oil and Gas Exploration in North Park-Middle Park Basin, Colorado

Abstract: North Park-Middle Park basin is one of the smaller of the intermontaine basins and one of the more structurally complex. Several stages of Laramide tectonism occurred, ultimately creating thrust faults with over 10,000 feet of displacement along the east and north margins of the basin, and within the basin itself. Thrusting was directed generally in a westerly and southwesterly direction. In places, pre-Tertiary erosion breached sediments on the intrabasin thrusts down to rocks of Dakota age or older. Additional thrusting is found throughout the basin, occurring as bedding-plane thrusts or detachments. Thrusts appear to be present in all of the structures examined, some with displacements up to several thousand feet. Direction of bedding plane thrusting is generally out of the basin, as a result of sharp synclinal basin folding; in many cases detachmentfolds were formed, and these folds are thought by the author to contain most of the oil and gas production in the basin. The basin is still in the early stages of exploration, with relatively few wildcat wells located away from the existing producing areas. The southern half of the basin is sparsely drilled, with no oil or gas production to date. Field geology must be coordinated with existing well control and seismic data, utilizing sound structural geologic techniques, to find hidden structures and to reevaluate unsuccessfully drilled structures. Attention should also be given to potential stratigraphic traps and fracture production within the basin.

Beaver River middle Devonian carbonate: performance review of a high relief fractured gas reservoir with water influx

Abstract: The Beaver River field, located in the fold belt of NE. British Columbia and the S. Yukon Territory, produces from a massive, extensively fractured carbonate reservoir. Development in this frontier location was supported by reserve estimates in excess of 1 tcf and high well deliverabilities. After going on stream in 1971, a severe decrease in recoverable reserves and deliverability resulted from water influx. This history portrays the need to examine the potential for influx in view of both the properties of the reservoir rock and the nature of the aquifer.

Stratigraphy and Entrapment of Hydrocarbons in the San Miguel Sands of Southwest Texas

Abstract: The San Miguel section of the middle Taylor in the Maverick Basin of the Rio Grande Embayment is a series of overlapping sand bars striking northeast-southwest. Grain size plots and core descriptions indicate that these bars developed in a shallow marine shelf environment. There are as many as five cycles of sand sedimentation, all but one having production established. These sands have a cumulative production of over 50,000,000 bbls. of oil since 1948. Over 30,000,000 bbls. of oil have been produced from stratigraphic type fields discovered since 1970. Stratigraphic type fields have produced over 90% of the total production. Structural traps, caused by differential compaction over volcanic necks, account for the remainder. Torch Field, associated with a volcanic neck in Zavala County, and Sacatosa Field, a stratigraphic trap in Maverick County, are typical fields. The depth and density of control, as well as the subtle expression of the traps, leave many prospective areas.