Showing papers on "Petroleum reservoir published in 1979"

Deep Basin Gas Trap, Western Canada

Abstract: Gas accumulations are distributed in a fashion similar to most other natural resources. The high-grade deposits are comparatively small. In general, as the grade decreases the size increases. Three of the largest sandstone gas fields in western North America are in low porosity-low permeability Cretaceous sandstone, in downdip structural locations, with porous water-filled reservoir rock updip. Examination of the details of these fields sets the stage for recognizing an enormous tight-sand gas trap in western Canada. The Mesozoic rock section, only 1,000 ft (300 m) thick on the shelf in eastern Alberta, thickens westward to over 15,000 ft (4,570 m) in the Deep Basin in front of the Foothills overthrusts. Most of the developed sandstone gas fields are in updip porosity traps, or minor structural traps, on the shelf. The porous, generally water-saturated sands of the shelf become less porous and permeable westward and downdip, passing from the water-bearing area with local gas traps through a transition zone to a gas-bearing area. This change is demonstrated by electrical resistivity logs and confirmed by drill-stem tests. Recent exploratory drilling in the Deep Basin has resulted in numerous discoveries in the area. Several hundred log analyses provide reliable data for measuring potential gas resources in the range of 400 Tcf. Recoverable gas at $2.00/Mcf net after royalty may reach 150 Tcf. The quantities of gas apparently present would be a major addition to the North American energy supply.

Factors Affecting Water Blocking and Gas Flow From Hydraulically Fractured Gas Wells

Abstract: This study presents results which were generated and analyzed over a 2-yr period. Several hundred computer runs were made during this project and an extensive amount of rock property data was reviewed to insure that these data were representative of tight gas reservoirs. The following conclusions reflect the combined information which was generated during the study. The reservoir properties, such as capillary pressure, change of capillary pressure in damaged zones, and relative permeability (in low permeability gas reservoirs) are primary factors in determining the behavior of a fractured well during cleanup. If the reservoir rock permeability is not damaged by frac fluid invasion, no serious water blockage to gas flow will occur when (1) the pressure drawdown is much greater than the capillary pressure in the formation, or (2) the capillary pressure and water mobility are large enough to rapidly imbibe the frac water into the formation. If the reservoir rock permeability is not damaged by frac fluid invasion, a complete water block to gas flow cannot occur; however, gas production can be severely curtailed if the pressure drawdown does not exceed the formation capillary pressure and the water mobility is so low that the frac water remains immobile nextmore » to the fracture face.« less

Oil and Gas Migration--Chemical and Physical Constraints

Abstract: Primary migration of oil in aqueous solution is not possible because the composition of dissolved hydrocarbons is vastly different from that of crude oils. Migration of oil solubilized in surfactant micelles is also rejected because of the large amount of surfactant required, and because there has been no demonstration that micelles are formed in source rocks. Migration by oil-droplet expulsion also is not feasible, because of the high interfacial forces of small droplets within fine-grained source rock; in addition, at least 7.5% organic matter by volume would need to be converted to oil to attain 30% oil saturation required for separate-phase flow; even higher oil saturations would be required for "squeezing" oil from pores. It is proposed that oil and gas are generated in, and flow from, source rock in a three-dimensional organic-matter (kerogen) network. Oil or gas flowing in this hydrophobic network would not be subject to interfacial forces until it entered the much larger water-filled pores in the reservoir rock. Oil saturation in the kerogen for oil flow to occur is indicated to be from 4 to 20%. Secondary migration of separate-phase oil and gas should occur by buoyancy, when their saturations attain 20 to 30% along the upper or lower surfaces of the reservoir rock. Oil or gas entering at the lower surface would intermittently cross the rock when the buoyancy head became sufficient. Efficient migration from source to trap could then occur as rivulets along the upper few centimeters in the reservoir rock. The volume of conducting reservoir rock attaining oil or gas saturation during secondary migration should be small, with most of the pores remaining water filled. In contrast, secondary migration of gas or oil in solution would be very inefficient and require large volumes of water. Unless all pores in the reservoir rock attained 20 to 30% gas or oil saturation, separate-phase flow could not occur, and oil and gas would remain locked in the pores and would not form reservoirs in trap positions. Attaining a 30% pore volume (PV) gas or oil saturation would require a flow of about 90 to 200 PV of gas-saturated water, and 15,000 to 200,000 PV of oil-saturated water. Residual gas and oil in cores taken along suspected secondary-migration pathways should show this residual gas or oil saturation, and recovered water should always contain equilibrium concentration of dissolved hydrocarbons, but this has seldom been observed. The proposed mechanisms of primary migration of oil and gas through a kerogen network, and secondary migration by separate-phase buoyant flow do not require the flow of water. Water flow probably disperses water-soluble constituents instead of concentrating them in reservoir traps.

Effect of Oil and Bitumen Saturation on Source-Rock Pyrolysis

Abstract: Mass production of pyrolysis instrumentation such as the "Rock-Eval" has led to general application of whole-rock pyrolysis as a means of identifying and characterizing petroleum source beds. One of the problems inherent in the whole-rock technique is the effect of petroleum or bitumen on the measured amount of thermally extracted hydrocarbons from the kerogen. Under pyrolysis, migrated oil or bitumen in the rock gives a major response near 250 to 350°C on the program (S1). However, solid bitumen and the "heavy-end" fraction of petroleum produce a measurable response (S2) in the 350 to 450°C range as well as in the same region where kerogen conversion to hydrocarbons occurs. Thus, large quantities of bitumen or migrated petroleum in rocks can affect the size and the maximum temperature of the S2 peak and can cause nonsource rocks to be misidentified as source rocks. These problems can be overcome by rinsing the sample in a chlorinated hydrocarbon solvent prior to analysis.

Natural Convection in a Multi-Layered Geothermal Reservoir

Abstract: The effect of layered structure of rock formation on free convection in a geothermal reservoir is investigated in this work. The model examined is that of a rectangular reservoir comprised of three horizontal permeable layers with different permeabilities. The reservoir is considered to be bounded by impermeable surfaces on the sides and at the bottom. The upper boundary of the aquifer is permeable, which permits the recharge and discharge of water to and from the aquifer. A transient two-dimensional convective flow is developed when the impermeable boundaries are raised suddenly to high temperatures. The governing nonlinear partial differential equations with appropriate boundary and initial conditions are solved numerically by finite difference methods. Application of the direct method for solving Poisson’s equation for stream function made it possible to carry out the solution for a much longer time than possible with iterative techniques. Numerical results are obtained for various parameters and configurations of the geothermal reservoir. The influence of a less permeable middle layer on the flow and heat transfer characteristics in the aquifer is discussed. The computed vertical temperature profiles are similar in shape to the complex temperature profiles observed at the HGP-A well.

Differential Entrapment of Oil and Gas in Niagaran Pinnacle-Reef Belt of Northern Michigan

Abstract: The Niagaran pinnacle-reef belt in the northern part of the Michigan basin is about 170 mi (270 km long) and 10 to 20 mi (16 to 32 km) wide. Since 1969, 360 oil- and gas-producing reefs and 72 salt-plugged or otherwise barren, water-saturated reefs have been found in the belt. The reefs are of small areal extent (average 80 acres; 32 ha.), high relief (up to 600 ft; 180 m), and steep flanks (30 to 45°) and are effectively sealed by the lower Salina evaporite deposits. The reefs are hydraulically interconnected through the Lockport Formation, their common permeable substrate, which dips basinward at 70 to 140 ft/mi (13 to 26 m/km; 0.76 to 1.52°). Reef height, pay thickness, burial depth, reservoir pressure, hydrogen sulfide content, and extent of salt plugging in rease progressively in a basinward direction across the belt, whereas oil gravity and degree of dolomitization increase systematically in the opposite direction. The belt is distinctly partitioned in an updip direction into three parallel bands of gas-, oil-, and water-saturated zones. This zonation of reservoir fluids is in full accord with Gussow's classic theory on the differential entrapment of oil and gas and provides a textbook example of its applicability on a regional scale in a natural case history. Interruptions in the continuity of the water-saturated band are interpreted as indicating passageways through which hydrocarbons may have migrated farther updip into the carbonate-shelf platform bounding the pinnacle-reef belt on the north. This reasoning leads to the delineation of two additional favorable target areas for further exploration.

Abnormal P-Wave Delays in The Geysers—Clear Lake Geothermal Area, California

Abstract: Large teleseismic delays, exceeding 1 second, are found near Mount Hannah in the Clear Lake volcanic field and in the steam-production area at The Geysers. The delays are superimposed on a general delay field of about 0.5 second extending over the volcanic rocks and the steam reservoir. It is postulated that a magma chamber under the surface volcanic rocks with a core of severely molten rock beneath Mount Hannah and a highly fractured steam reservoir probably underlain by partially molten rock at The Geysers are responsible for the observed delays. Both zones extend to depths of 20 kilometers or more.

Secondary Reservoir Porosity in the Course of Sandstone Diagenesis

Abstract: Secondary porosity plays an important role in the diagenesis of sandstones. The volume of secondary porosity equals or exceeds that of primary porosity in the sandstones of many sedimentary basins worldwide and a significant percentage of the world's reserves of natural gas and crude oil are contained in secondary sandstone porosity. The main geological and economic significance of secondary sandstones porosity is that it extends the depth range for effective sandstone porosity far below the depth limit for effective primary porosity. Generation and primary migration of hydrocarbons occurs mainly below the range of effective primary porosity, and therefore the path of primary migration and the site of accumulation of hydrocarbons are commonly controlled by the distribution of secondary porosity. In this paper, secondary porosity in sandstone diagenesis is discussed in detail. Genetic-textural classes of secondary sandstone porosity are given along with recognitition criteria, geological occurrence and diagenetic origins of secondary porosity.

Eolian-fluviatile (continental) origin of ancient stratigraphic trap for petroleum in weber sandstone, rangely oil field, colorado

Abstract: An anclent stratlgraphic trap for petroleum exists in continental deposits at Rangely oil field, about 24 km south of Dinosaur National Monument, where the eol Ian Weber Sandstone (pennsy lvanlan-permian) intertongues with the Maroon Formation of fluvlal origin. The stratigraphic trap developed as a result of the progradation of eolian dunes toward the ancient Uncompahgre uplift. Fine silt and conglomeratic material brought into the dunes along the margins of the dunefield became impermeable layers--due to postdepositional diagenetic cementation and intrinsic textural properties. The conditions which created the stratlgraphic trap at Rangely may have developed ' in other areas along the margins of ancient Pennsylvanian uplifts in Colorado, Wyoming, and Utah. Analysis of cores from Rangely oil field indicates that porosity and permeability within the oil-productive sandstone Is affected by primary and secondary diagenetic processes. Reduction of porosity and permeability in the reservoir sandstones Is due to burrowing and contortlon of laminations, which destroyed or ~dified previously well-sorted laminations of sandstone units. Cementation is most complete in the burrowed and contorted Intervals. Evidence for eol Ian origin of the Weber Sandstone near Dinosaur National Honument includes: (a) large scale tabular-planar cross-stratified u nits with few horizontal symmetric ripples, but many low-relief, asymnetric ripples oriented up and down slipface deposits; (b) raindrop imprints on slipface deposits at Deerlodge Park, Colorado; (c) characteristics of contorted stratification, lamination style, and burrowing that e xactly match those of modern eolian deposits and some inferred ancient eolian deposits, and which can be interpreted in the l ight of known eol Ian processes; (d) interbedding of we1 I-sorted quartz sandstones and poor1 y sorted, mica-r ich siltstones and conglomerates at Rangely oil field, which Is interpreted to be interbedded eolian dune and fluvial sediments; (e) consistent southward transport directions In the Weber Sandstone are more compatible with a wind- driven depositional system than a marine depositional system, since steady ocean currents flowing south to south- east would be forced to flow upslope toward the anclent Uncompahgre and Front Range up1 ifts; (f) absence of appre- ciable clay or chert In the Weber Sandstone in the study area, in contrast to the occurrence of these minerals in marine rocks of the Weber Sandstone farther west; (g) thin, lentlcular carbonates (usually only .31-.61 m thick) restricted to extensive dlastems In the Weber Sandstone In the study area which indicate t hat the carbonates were deposited in non-marine ponds associated with interdune areas; (h) striking dl fferences between the lenticular, brecciated, unfossiliferous dolomites In the Weber Sandstone and the t hick, fossiliferous cherty limestones of approximately the same age in marine deposfts within the Weber Sandstone, and the older underlying Morgan Forma- tion. Shortly after deposition. the eollan deposlts of the Weber Sandstone became saturated with water and were then subjected to penecontemporaneous deformation that produced complex folding and breaking of laminations.

Recovery of crude oil utilizing hydrogen

Abstract: Hydrogen is injected into an underground petroleum reservoir that is devoid of natural gas. Due to its high rate of diffusion, hydrogen disperses rapidly throughout the reservoir, including the tight portions that are relatively impermeable to the injection of water. Pressure is lowered in the reservoir when the crude oil is substantially saturated with hydrogen. Hydrogen then migrates from the tight portions of the reservoir, sweeping petroleum into the more permeable portions. Expanding hydrogen experiences a temperature rise which in turn heats the crude oil and further reduces the viscosity for added mobility. A water sweep displaces the oil to production wells. In an alternate embodiment hydrogen is injected into an underground petroleum reservoir as a prelude to fire flood techniques. The absorbed hydrogen dilutes the crude in place and provides a fuel with much wider flammability limits to sustain the underground fire.

Fractures in Cretaceous Rocks from Selected Areas of San Juan Basin, New Mexico--Exploration Implications

Abstract: Fracture reservoirs are present in the Verde, Boulder, West Puerto Chiquito, and East Puerto Chiquito oil fields of the San Juan basin, New Mexico. Brittle, competent siltstone and carbonate-rich interbeds within Cretaceous shale intervals are fractured in areas of maximum curvature along the Hogback monocline. Surface observations indicate that there are usually three sets of fractures along limbs of folds. Open fractures trend parallel with fold axes and occur on convex sides of folds. Dip fractures and oblique fractures are commonly tight. Exploration for traps with fracture reservoirs should focus on areas of maximum curvature of folds where brittle interbeds can be expected in the subsurface. Monoclines are common along the margins of many basins in the Rocky Mountain region and provide many exploration targets, as they probably formed at relatively low confining pressures, thus facilitating fracture of brittle rocks in the Cretaceous System.

Hydrocarbon Potential of Aleutian Basin, Bering Sea

Abstract: The Aleutian basin is the deep-water (more than 3,000 m) basin that lies north of the Aleutian Islands adjacent to the Bering Sea continental shelf. The basin, about the size of Texas, is underlain by a flat-lying sequence of mostly Cenozoic sediment 2 to 9 km thick that rests on an igneous oceanic crustal section. Prior to 1974, marine investigations in the Aleutian basin were directed at understanding the basin's regional geologic and geophysical framework; more recent investigations by the U.S. Geological Survey have been aimed at assessing the basin's hydrocarbon potential. Preliminary results suggest that the four major requirements for hydrocarbon accumulations may be present--structural and stratigraphic traps, source rocks, reservoir beds, and an adequate thermal nd sedimentation history. The recent energy-resource studies indicate that: (1) numerous structural features (gentle folds, diapirs, basement ridges) are present in the central and eastern parts of the basin; (2) acoustic features called VAMPs (velocity amplitude features) are common (over 350 identified) in the central basin; these features may be caused by pockets of gases and possibly other hydrocarbons that have been trapped in the sedimentary section; (3) the sedimentary section consists of diatomaceous sediment overlying indurated mudstones; high porosities (58 to 85%) and good permeabilities (10 to 35 md) in the diatomaceous sediment suggest that it is a potential reservoir unit and the thick section of underlying mudstone may contain the source beds; (4) concentrations of organic gases, primarily metha e, in the upper 1 to 3 m beneath the seafloor are very small, increase with depth, and are highest in areas near VAMPs; (5) the thermal gradient and the sediment thickness are sufficiently large to allow hydrocarbon maturation at depth, if suitable organic material is present. Our initial results suggest that the Aleutian basin deserves further exploration as a site for possible hydrocarbon accumulations.

Geology and petroleum resources of the major oil-impregnated sandstone deposits of Utah

Abstract: Near surface, oil-impregnated rock deposits in Utah are estimated to contain as much as 29 billion barrels of petroleum. Over fifty individual deposits have been identified, primarily through field mapping. Over 96% of the oil in place occurs in sandstone host rocks in six giant deposits. Four of the deposits occur in the Uinta Basin of northeastern Utah, and contain petroleum which probably originated in the Green River Formation (Eocene). Three of these deposits, P.R. Spring, Hill Creek, and Sunnyside, also occur in the Green River Formation, but the Asphalt Ridge deposit occupies only older and younger strata. Two deposits occur in marine and marginal marine strata in the dissected plateau region of southeastern Utah. The Tar Sand Triangle is the largest deposit in the state, and occurs in the White Rim Sandstone (Permian). Circle Cliffs is a giant, low-grade deposit in sandstone and siltstone of the middle Moenkopi Formation (Triassic). The oil-impregnated sandstone bodies of the deposits are of variable number, thickness, and petroleum content, and occur under the influence of a variety of structural and topographic conditions. Tables provide summaries of various characteristics of the petroleum and the reservoir strata.

Importance of secondary leached porosity in lower Tertiary sandstone reservoirs along the Texas Gulf Coast

Abstract: Secondary leached porosity is common to dominant in near surface to deep subsurface lower Tertiary sandstone reservoirs along the Texas Gulf Coast. This secondary porosity is in the form of leached feldspar grains, volcanic rock fragments, carbonate cements, and carbonate-replaced grains. Leached porosity occurs in sandstones with compositions ranging from volcanic litharenite and lithic arkose to quartzose sublitharenite and quartzose subarkose. A generalized diagenetic sequence indicates that leaching is a multi-staged phenomenon occurring at or near surface, at burial depths of 4000 to 6000 ft, and at burial depths of 7000 to 10,000 ft. Feldspar grains are dissolved during the first stage, whereas grains, cements, and replacement products are dissolved during the last two stages. Intensity of leaching in each stage varies in different formations and in different areas. Plots of secondary porosity as a percent of total porosity versus burial depth show that secondary porosity is dominant beneath 10,000 ft, ranging from 50 to 100 percent of total porosity. Above 10,000 ft more than half the samples have secondary porosity as the dominant type. Similarly, individual plots for the Wilcox, Yegua, Vicksburgs, and Frio sandstones all demonstrate the predominance of secondary leached porosity. Primary porosity is destroyed by compaction and cementation with increasing depth of burial. If this were the only porosity type, no deep, high-quality reservoirs would exist. Leaching, however, restores reservoir quality after primary porosity has been reduced. Most productive lower Tertiary sandstone reservoirs, especially deep reservoirs, along the Texas Gulf Coast exist only because of secondary leached porosity.

Hydrocarbon Shows--Proximity Indicators for Stratigraphic Traps: ABSTRACT

Abstract: Stratigraphic traps may consist of three distinct zones: (1) downdip oil-water transition zone, (2) economic oil productive zone, and (3) updip waste zone (Dunham). As only one of these zones is economic, exploration efforts for stratigraphic traps should be geared toward determining if any show in a wildcat well is in one of these three zones of a trapped accumulation. If a well is thought to have drilled into the transition zone, calculations can be made as to how far structurally updip a well should be drilled to locate economic oil-water ratios. If a well is drilled in the economic zone of a trap, calculations can be made from the first wildcat well to estimate the downdip limits of the field. If a well is drilled in the updip waste zone of a trapped accumulation, cal ulations can be made to estimate the distance downdip to the oil-water contact. Cored wells updip from three economic stratigraphic traps were studied to determine if they were in the waste zone of the accumulation and to test the hypothesis that calculations to determine the oil-water contact in a field can be made from shows in updip waste-zone wells. Two oil-waste zones and one gas-waste zone were studied. Results of the calculations based on available data agree closely with documented oil columns in the fields studied. These results suggest that the concept is valid and can be used both qualitatively and quantitatively as an exploration tool in exploring for oil or gas as an exploitation tool in developing fields. End_of_Article - Last_Page 840------------

Exploration History of South Texas Lower Cretaceous Carbonate Platform

Abstract: The search for hydrocarbons in reservoirs of the Lower Cretaceous of south-central Texas has been continuous for more than 60 years. Accumulations have been found in significant quantities in only four areas: (1) the very shallow fault traps high on the San Marcos arch in Caldwell and Guadalupe Counties, (2) a fault trend stretching across central Atascosa County, (3) a fault trend extending from southeastern Atascosa County to southern Gonzales County, and (4) a narrow, elongate band extending across the entire area known as the Stuart City reef trend. Additional minor discoveries are widely scattered in the Maverick basin and San Marcos arch. Reservoirs which contain the hydrocarbons were deposited in many environments, all related to a broad carbonate shelf covered by an extremely shallow sea. The sea deepened dramatically at the shelf margin parallel with a reef trend. Dolomites contain the best accumulations in the fault trends, and porosity and permeability are reasonably good. Generally, limestones in the reef trend were not extremely porous initially, and late cementation has diminished even that porosity making the reservoir of lesser quality. Oil is the dominant hydrocarbon in the shallow fields, is less dominant in the other fault trends, and is nonexistent in the reef reservoirs. Proved ultimate hydrocarbons for the platform are about 363 million bbl of oil and 1.7 Tcf of gas. Reserves for the reef trend's dry gas reservoirs are difficult to estimate because of highly variable reservoir conditions, but they should fall between 1 and 1.5 Tcf. Exploration has been most intense for the uppermost Lower Cretaceous rocks. The Sligo limestone still holds the promise of success, but lies at considerable depths over much of the area. Edwards and Glen Rose rocks are more densely explored, but there are ample opportunities for new plays even in these formations. Geologists who examine cores and cuttings, determine depositional patterns, understand modern carbonate sedimentology, and study patterns of diagenesis will have an advantage in developing new concepts for exploration.

Petroleum Geology of Cook Inlet Basin, Alaska--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 1 well, drilled to a total depth of 3,776 m, penetrated the tops of Upper Cretaceous, Lower Cretaceous, and Upper Jurassic strata at 832, 1,541, and 2,112 m, respectively. Basinwide unconformities are present in this well at the tops of the Upper Cretaceous, Lower Cretaceous, and Upper Jurassic rocks. Sandstone of potential reservoir quality occurs 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 average 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 confirm the 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 gas in wells and in surface seeps. Extractable hydrocarbons from this strata are similar in chemical 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 uncomformable 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 time 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 in 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 Jurassic 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 the Miocene time. Pliocene deformation shut off this route and created localized structural traps, into which the oil moved by tertiary 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.

Geochemical Exploration in Powder River Basin, Northeastern Wyoming and Southeastern Montana: ABSTRACT

Abstract: Combined geochemical and geologic information from this structural basin accurately delimited areas and stratigraphic sequences prospective for crude oil and thermal hydrocarbon gases. Using volumetric and performance data for each effective source sequence, quantities of expelled oil and gas were calculated which readily account for in-place oil reserves of more than 6 billion bbl and minor amounts of associated gas. Oils expelled from Lower and Upper Cretaceous source beds are similar. The Mowry siliceous shale and Niobrara calcareous shale and marl expelled most of the oil indigenous to the basin. A second major oil type is correlated to the remote Permian Phosphoria source area centered in southeastern Idaho. Oil migration paths have been mapped, gathering areas identified, and time of migration determined. Three of five giant oil fields--Salt Creek, Lance Creek, and Bell Creek--are located on separate gathering areas around the basin periphery. Hilight and Hartzog Draw fields are stratigraphic traps paralleling structural strike on the basin's eastern flank, oriented to receive maximum flow of migrating oil. An Early Jurassic regional migration emplaced Phosphoria oil in upper Paleozoic reservoirs before the basin formed. Expulsion from deepest Cretaceous source rocks began in Eocene time and probably continued into Pliocene time as the expulsion front moved upsection and updip. Laramide structure controlled migration of Cretaceous oil. Recharge water affected oil preservation. Consequently, temperature and salinity anomalies are commonly associated with accumulations in recharge areas, where two types of bacterial alteration are recognized. More than 20 mutually supporting chemical and physical parameters from rocks and fluids proved useful in defining prospective areas. End_of_Article - Last_Page 497------------

Simulation of the depletion of two-phase geothermal reservoirs

Abstract: The simulator SHAFT79 has been used to study the depletion of different types of geothermal reservoirs Investigations of idealized systems include effects of gravity and fluid injection Pressure decline is analyzed as a function of cumulative production The main conclusions are as follows: (1) the well-known p/Z-method for estimating fluid reserves is not applicable to two-phase geothermal reservoirs; (2) there is a strong tendency towards spatially uniform boiling This causes a pressure decline which allows in many cases estimates of the total reservoir volume and of the total heat content of the reservoir rock; (3) propagation of a boiling front through a deep water table, as a consequence of fluid production, gives rise to a peculiar pattern of pressure decline This may allow prediction of the distance of the water table from the producing wells and of the vertical thickness of the water zone, thereby giving important clues to estimating fluid reserves; (4) the pressure effects of injection of colder fluid depend strongly on (one- or two-) phase conditions in the reservoir, upon injection rate, and upon absolute permeability Average pressure may actually decline in two-phase reservoirs rather than increase due to injection Preliminary results of a case-history investigation ofmore » the Serrazzano zone at Larderello, Italy, are presented SHAFT79 has been used for a fully three-dimensional simulation of a geologically accurate model of the Serrazzano reservoir Comparison of computed results with field data allows improved estimates of reservoir conditions and parameters« less

Nature and Potential of Belly River Gas Sand Traps and Reservoirs in Western Canada

Abstract: The economically important basal Belly River is defined and its general nature described. Sand reservoirs in the Belly River Formation are capable of economic gas production in Alberta and Saskatchewan despite their characteristically high clay content. Many instances of disappointing production may be explained by limited reservoir, washed-out sands and, most frequently, mud damage. To illustrate their reservoir qualities the production history and the configuration, composition and mechanical-log character of Belly River sands from several localities are described. These localities are sufficiently widespread to give a general picture not only of the sands, but of the types of hydrocarbon traps in the Belly River Formation, which are: updip sand pinchouts into marine shale, gentle structures involving widespread sands, stratigraphic traps in fluvial sands.

Recent seismic studies upgrade the petroleum prospects of the toko syncline, georgina basin

Abstract: The Georgina Basin covers an area of 325,000 sq km in the Northern Territory and Queensland. Most of the basin contains less than 500m of Palaeozoic sediments, but the Toko Syncline, in Queensland, contains up to 5000m of Middle Cambrian to Middle Ordovician shallow marine carbonate, sandstone and shale. The syncline is bounded on its western margin by the Toomba-Craigie Fault system Hydrocarbon shows are known within the Middle Cambrian to Middle Ordovician strata and some of the rocks have fair source rock potential. Potential reservoir rocks are vuggy dolostones and sandstone. Ordovician siltstones and shales may provide cap-rocks. The southern, deepest part of the syncline appears to have been protected from flushing. AOD Ethabuka-I well, drilled in the southern part, encountered gas in the Ordovician, but drilling problems prevented penetration of the deeper section. A Bureau of Mineral Resources (BMR) seismic survey in 1977, linked lines shot on earlier surveys, tied to wells and examined the Toomba Fault system. The results show that two previously unidentified reflectors represent the top of Upper Cambrian Georgina Limestone and the base of the Middle Cambrian section. Substantial thickening of Ordovician and slight thinning of Middle and Upper Cambrian strata occurs southeast along the axis of the syncline. Southeast progradation of some Middle Cambrian strata and possible bioherms were observed. The Toomba Fault is a high-angle reverse fault and several possible anticlines are present in the adjacent folded and faulted zone. The two largest ones, the Ethabuka and Mirrica Structures, were partially outlined by Alliance Oil Development (AOD). They are shown to lie within a larger structure which has a minimum vertical closure of 700m over a minimum area of 130 sq km. Possible stratigraphic traps are located on the northeastern flank and along the axis of the syncline. The seismic work has better defined the prospective section and confirmed closure on a large structure. The next step in exploration should be to drill the Mirrica-Ethabuka Structure, where about 1500m of section remains to be tested.

Relative permeability during cyclic steam stimulation of heavy oil reservoirs

Abstract: Reliable relative permeability data are important to the overall planning for prospective thermal recovery projects. Empirically derived relative permeability functions presented have characteristics that are dissimilar from those determined experimentally. The empirical functions emerged from simulations of numerous, on-going thermal projects in California's unconsolidated, heavy-oil reservoirs. 12 references.

Geological Techniques Utilized in Trap Spring Field Discovery, Railroad Valley, Nye County, Nevada

Abstract: The trap at Eagle Springs Field is a combination stratigraphic truncation-subcrop-fault trap. Production occurs from matrix and fracture porosity in reservoirs in the Sheep Pass Formation (Cretaceous and Eocene) and the Garrett Ranch volcanic group (Oligocene). Probably the most unique feature about the field is that the production occurs from the highest position on the lowermost fault block at the basin margin. On the adjacent higher fault blocks the reservoir beds were removed by erosion during the basin and range orogenic event. The position of the truncated edge of the lower Tertiary reservoir units is controlled by the fault pattern at the margin of the valley-basin Graben. Detailed geomorphic studies indicated that this fault pattern may be identified at the surface. Regional geomorphic mapping of fault patterns was conducted to localize areas with possible subcrop truncation patterns similar to Eagle Springs Field. 20 references.

Naturally fractured reservoirs. Part 12. Studies show occurrence of fractured reservoirs

Abstract: In Part 12, H.K. van Poollen and Associates Inc. and Canada's SOQUIP review the published accounts of naturally fractured reservoirs found in sandstones, carbonates, shales, cherts, siltstones, and basement rocks. The percentage of the total porosity made up by fractures for any given reservoir may be very small or up to 100%, making the evaluation of naturally fractured reservoirs a unique research problem for each application.

Facies and Reservoir Characteristics of a Shelf Sandstone: Hartzog Draw Field, Powder River Basin, Wyoming

Abstract: Hartzog Draw field is a stratigraphically controlled oil reservoir which produces from the Upper Cretaceous Shannon Sandstone at depths from 9,000 to 9,600 ft (2,700 to 2,880 m). The producing interval consists of a large, midshelf sand-bar complex deposited below effective normal wave base more than 100 mi (160 km) from shore. The productive interval in the bar complex has a maximum thickness of 65 ft (19.5 m), is over 21 mi (34 km) long, and up to 3.5 mi (5.6 km) wide. Over 170 wells have been completed on 160-acre (64 ha.) spacing since its discovery in 1975, and ultimate oil recovery may exceed 100 million bbl. The reservoir is completely enveloped in shale, has a solution-gas drive, no water table, and no produced formation water. Even zones calculated from logs to have water saturations of over 65% do not produce water. Net pay is primarily a product of porosity, permeability, and thickness of the sandstone, and is directly related to sedimentary facies. Of six facies observed in cores, only the central bar facies--a high angle, trough-cross-bedded, glauconitic quartz sandstone--is a consistently high-quality reservoir. Two others, the bar-margin facies, a ripple to trough cross-bedded sandstone with abundant shale and siderite clasts, and the interbar facies, a rippled, interbedded sandstone and shale, generally are marginal-quality reservoirs. Data from three cores indicate the central bar facies to have a significantly better average porosity and permeability (12.7%, 6.5 md) than either the bar-margin facies (8.1%, 3.7 md) or interbar facies (6.2%, 2.1 md). In addition, wells with a thick central bar facies appear to maintain higher reservoir pressures. Recognition of the facies, and understanding their distribution and interrelations are prerequisites to developing a program which will maximize oil recovery from the field. End_of_Article - Last_Page 491------------

Geothermal well log interpretation midterm report

Abstract: Reservoir types are defined according to fluid phase and temperature, lithology, geologic province, pore geometry, and salinity and fluid chemistry. Improvements are needed in lithology and porosity definition, fracture detection, and thermal evaluation for more accurate interpretation. Further efforts are directed toward improving diagnostic techniques for relating rock characteristics and log response, developing petrophysical models for geothermal systems, and developing thermal evaluation techniques. The Geothermal Well Log Interpretation study and report has concentrated only on hydrothermal geothermal reservoirs. Other geothermal reservoirs (hot dry rock, geopressured, etc.) are not considered.