Showing papers on "Petroleum reservoir published in 1969"

Evaporite Formations with Petroleum Reservoirs in Devonian and Mississippian of Alberta, Saskatchewan, and North Dakota

Abstract: In the sedimentary basins of the northern United States and western Canada large amounts of rock, broadly described as evaporitic, are either petroleum bearing or so situated in their geologic association with petroleum that evaporite geology bears directly on the petroleum occurrence. The evaporites are members of facies assigned to two distinct groups--a coastal-shoal/salt-flat suite and a reef/salt-basin suite, illustrated by Devonian and Mississippian examples. (1) Desert-zone coastal salt flats (sabkhas) have the peculiarity of transforming calcareous sediment to microdolomite containing quantities of gypsum and anhydrite. The permeability changes thus effected make stratigraphic traps for oil and gas. Fossil sabkhas among Late Devonian strata of the Western Canada basin and the Mississippian rocks of the Williston basin hold large reserves of sulfur and petroleum. (2) Middle Devonian reefs in the Elk Point evaporite basin were built up in stages. The first reef stage (Winnipegosis-Black Creek) forms part of an association of sedimentary units deposited in the following order: (1) platform; (2) reef, ending with laminar dolomite on both reef and basin floor; (3) bituminous calcitic and anhydritic laminites on the basin floor (not on reef sites); and (4) laminar halite filling the interreef tracts nearly to reef-top level. The reefs are not in stratigraphic-facies relation to the salt, for during calcitic laminite and salt sedimentation they were exposed subaerially (not implying any change in general sea level outside the basin). Much diagenetic activity affected the laminite deposits, some of it apparently occurring independently (perhaps yearly) in each lamina. Some anhydrite is nodular-dolomitic, resembling primary anhydrite of present-day sabkha capillary-zone type, though most of it is associated so intimately with laminar organic matter that it can be described as mineralized algal mat.

Geologic Reservoir Analysis, Mississippian Madison Formation, Elk Basin Field, Wyoming-Montana

Abstract: The Elk Basin field is in the north end of the Big Horn basin, on the Wyoming-Montana state line. The structure is a NW-SE-trending asymmetric anticline approximately 8 mi long, 4 mi wide, and has about 5,000 ft of structural closure. Oil production from the Mississippian Madison Group was discovered in 1946. Cumulative production is now more than 75 million bbl of oil from 5,100 acres; productive closure is about 1,400 ft. A recent core study of the Madison reservoir shows it can be divided into several separate, distinct geologic and production units. The Madison carbonate sequence has been greatly altered and distorted by groundwater erosion, by the formation of karst topography and subsequent solution brecciation in Late Mississippian-Early Pennsylvanian time, and by selected remineralization in certain areas of the field. The overall effect of karst activity was the collapse of sections of the upper Madison, up to 300 ft thick, into brecciated rubble zones. As a result of such collapse, entire blocks of the upper Madison have no effective communication with each other. There are areas of remineralization which, because of redeposition of dissolved carbonates, silica, and anhydrite into pore space and fractures by the downward-percolating groundwater, have local, relatively impermeable zones. These zones form local stratigraphic traps. Zones of insoluble residue of clay and rock fragments form an effective barrier between the A and B producing zones, and explain the different reservoir characteristics of each zone. Groundwater action removed the more soluble limestone but left the less soluble dolomite, and formed the good secondary porosity now found in the Elk Basin Madison. The secondary porosity zones can be correlated and subdivided into readily recognizable and distinct units. The fact that such subdivision is possible demonstrates a certain degree of continuity of solution action. The understanding of this continuity is necessary to the evolution of efficient drilling and flooding programs. Electric-log and core evaluations of the Madison in other Big Horn basin fields indicate reservoirs similar to the Elk Basin Madison reservoir. However, most of the other Madison fields do not show the same degree of karst development. From the above-mentioned variations, a multiple working hypothesis can be developed for reservoir engineering analysis. The overall hypothesis provides a good vertical and areal model of the Elk Basin Madison reservoir. Practical application of the hypothesis has resulted in a rather dramatic production response. The exploration implications are that geologists need to understand the characteristics of known reservoirs before they can conduct effective exploration for new reservoirs.

Rock Compressibility and Failure as Reservoir Mechanisms in Geopressured Gas Reservoirs

Abstract: Rock compressibility has long been recognized as an important factor in material-balance calculations of oil in place for closed reservoirs producing above bubble-point pressure. For example, if the pore volume compressibility of the reservoir rock is half of the compressibility of the undersaturated oil, neglect of the rock-compressibility term results in about a 50% overestimation of oil in place. In general, it may be stated that in material-balance calculations on closed reservoirs, consideration of rock compressibility becomes increasingly important as the fluid compressibility decreases. A study of the N. Ossun field, Louisiana, reveals that as reservoir pressure is depleted, the increase in net overburden pressure initially causes rock failure, and as the failure continues with decreasing pore pressure, rock compressibility decreases until eventually it reaches a normal value. The N. Ossun field is a geopressured gas reservoir with an initial pore pressure of 8,921 psia at 12,500 ft subsea depth, or a gradient of 0.725 psi/ft. Tabular data give pertinent information on this reservoir. Good geologic control is indicated by a structure map.

Recovery of oil by low-pressure miscible gas injection

Abstract: An oil miscible gas such as carbon dioxide is injected into a subterranean oil reservoir to maintain a reservoir pressure near the critical pressure of the gas. Under predetermined conditions of temperature and pressure the miscible gas-crude oil mixture exhibits a three-phase vapor-liquid phenomena which enhances the recovery of oil from the subterranean reservoir. A miscible gasrich liquid phase is formed between the oil-rich liquid phase and miscible gas-rich vapor phase and exhibits a density and viscosity intermediate between that of the oil and gas regions. This phenomenon creates a unique fluid distribution and mobility relationship which provides for a significant increase in the efficiency of the displacement of the oil from the gas-swept reservoir.

Optimum oil recovery for carbon dioxide injection

Abstract: Carbon dioxide is injected into a subterranean oil reservoir to maintain a reservoir pressure between about 1 and about 250 p.s.i. above the bubble point pressure of the reservoir crude oil. Under predetermined conditions of temperature and pressure the carbon dioxide miscible gas recovery provides for an extremely efficient displacement of the reservoir crude oil. It has been found that at pressures slightly above the bubble point pressure of the reservoir fluid, the rate of solubility of the carbon dioxide in the reservoir fluid is much higher and recovery of oil is more efficient.

Geology of Petroleum in Wind River Basin, Central Wyoming

Abstract: The Wind River basin contains more than 60 oil and gas fields, located chiefly on structural traps that developed during Laramide deformation in latest Cretaceous and early Tertiary times. Seventeen different sedimentary formations are petroleum bearing. Principal reservoirs are the Pennsylvanian Tensleep Sandstone, Permian Park City Formation, Cretaceous Cloverly, Thermopolis (Muddy Sandstone Member), Frontier, and Lance Formations, and Paleocene Fort Union Formation. Until latest Cretaceous time central Wyoming was part of the stable shelf that sloped gently westward toward the Cordilleran geosyncline. Deposition occurred mainly in shallow seas, and slight changes in base level commonly resulted in widespread facies changes and unconformities within the Paleozoic and lower Mesozoic sedimentary sequences. Because (1) the regional dip of the strata was westward and (2) the overburden pressures were greater on the west during the pre-Laramide period, fluids generally migrated as far eastward into the present basin area as structure and individual reservoir conditions permitted. Regional stratigraphic and structural relations suggest that primary accumulation of hydrocarbons occurred in many reservoirs before folding began. Pronounced subsidence of the central basin area during the Laramide induced a secondary migration of fluids updip toward structural traps that developed contemporaneously along the basin margins. However, facies changes, unconformities, and porosity and permeability barriers within many of the pre-latest Cretaceous reservoirs inhibited wholesale flushing of all the oil and gas formerly trapped in the central basin area. Untapped stratigraphic traps or combinations of stratigraphic and structural traps therefore still may be present downdip from the present margins of the basin. Exploratory drilling has not tested the Frontier and older Mesozoic rocks in approximately 3,500 sq mi of the central, structurally deepest part of the Wind River basin; more than 4,500 sq mi of Paleozoic rocks is untested. The common reservoirs are less than 15,000 ft below the present ground surface in approximately 2,000 sq mi of the untested areas.

Application of aerial photographic interpretation to the study of reservoir natural fracture systems

Abstract: Natural fracture systems are planes of failure in rocks resulting from large- or small-scale, regional or local stresses. Fracture plane attitude remains essentially the same within the sedimentary section in tectonically undisturbed areas. Thus, surface fracture trace patterns may be potential sources of information on the fracture plane attitude within reservoir intervals. The survey of these patterns over large areas of oil- producing basins can be accomplished easily on aerial photomosaics. A field application involving 8 W. Texas reservoirs is presented. Despite some statistical noise in the fracture frequency plots and the directional uncertainties involved in interpreting reservoir fluid movements, a fair match between predominant surface fracture trace direction and reservoir performance was found in all of the examples. Based on these observations and the experiences of others, aerial photography appears to hold excellent promise as a practical tool in preliminary analysis of natural fracture system attitude in reservoirs. (24 refs.)

Elk Basin Madison Heterogeneity Its Influence on Performance

Abstract: The 920-ft thick Madison limestone of Mississippian is one of the 7 producing horizons in the Elk Basin field, located on the Wyoming-Montana border near Yellowstone Park. Full section coring, done nearly 20 yr after the horizon was discovered and after more than 65,000,000 bbl oil had been produced, has shown the reservoir rock to be distorted highly by ground-water erosion, solution, and remineralization that took place at the end of Mississippian deposition. Geologic interpretation of the new data has helped to define reservoir discontinuities and to explain anomalies previously noted in reservoir performance, and has provided a better basis for analyzing current performance. An improved understanding of reservoir heterogeneity led to a development drilling program which has increased production from 16,000 bopd to a peak rate of 24,600 bopd. Waterflood efficiency also has been improved by adjusting injection water distribution to account for difference is subzone performance and for discontinuities.

Algal-Bearing Carbonate Reservoirs of Pennsylvanian Age, West Texas and New Mexico: ABSTRACT

Abstract: Leafy, platy, or phylloidal algae have been observed in many well cores from hydrocarbon reservoirs at various localities in the Permian basin of west Texas and southeastern New Mexico. These algae have a significant bearing on the quality, and in some cases the existence, of the reservoir. Three examples have been chosen to illustrate these relations. Nena Lucia field, Nolan County, Texas, produces from massive limestone of Desmoinesian (Strawn) age on the east side of the Midland basin. Inferences of eolian depositional environment published previously are not supported, for the dominant reservoir lithofacies is algal calcareous wackestone. Saunders field, Lea County, New Mexico, produces from both massive and well-bedded limestone of Permo-Pennsylvanian age on a well-defined structure just north of the Delaware basin. Although diverse elements contribute to the different porous zones, platy or phylloidal algae are a dominant factor in some of the zones. Conley field, Hardeman County, Texas, produces from three separate formations, including a limestone reservoir in the early Missourian (Canyon) Palo Pinto Formation. This unit is articularly noteworthy for the profusion of algae and the nearly complete dependence of reservoir development on the organisms. Though much smaller in volume, this reservoir is petrologically very similar to that described from the Aneth field complex of the Paradox basin. Phylloid algal reservoirs commonly are surrounded by nonporous mudstone and wackestone and thus fall in the class of reservoirs wherein sediment genesis is an important factor in pore origin. An initial pore network End_Page 726------------------------------ controlled by plate morphology helps localize later diagenetic events, which ultimately produce a well-connected, predominantly large-pore network. This provides for large initial production rates and relatively high recovery factors, which are very desirable reservoir attributes from an economic standpoint. End_of_Article - Last_Page 727------------

Oil recovery by a combination of solution gas drive and waterflooding

Abstract: Improved oil recovery from an oil-bearing reservoir is obtained by a combination of solution gas drive and water flooding whereby the reservoir is produced by solution gas drive until the pressure of the reservoir is reduced below the bubble point pressure and a critical gas saturation is established, and thereafter the reservoir is produced by a water flood until the rate of oil production reaches a predetermined value or termination point, whereafter the cycle is repeated

Natural and induced fracture systems and their application to petroleum production

Abstract: The Morgantown Petroleum Research Laboratory, U.S. Bureau of Mines, is investigating the orientation of hydraulically induced fractures in petroleum reservoirs to help guide producers in better location and spacing of wells for more efficient fluid injection and petroleum production. The results of analyses of surface and subsurface information show a definite correlation between surface lineations and azimuths of hydraulically induced fractures. Joint systems determined from remote sensing imagery and/or surface surveys have been correlated with subsurface fracture orientations to depths of 3,000 ft and used to predict the bearing of hydraulically induced fractures in the Appalachian Basin. Possible applications of fracture orientation prediction to petroleum production are also discussed. (15 refs.)

Turner Valley Formation of the Jumping Pound Area, Foothills Southern Alberta

Abstract: The Mississippian Turner Valley Formation contains the main reservoir rock in such foothills fields in Alberta as Turner Valley, Quirk, Jumping Pound, Wildcat Hills and Jumping Pound West. A complete section of Turner Valley Formation consists of approximately 350 ft of sediments, essentially all carbonates. The formation is subdivided in ascending order into the Mt3A, Mt3B, Mt3, Mt2 and Mt1. Post Mississippian pre-Jurassic erosion has removed about 100 ft of the upper part of the Turner Valley formation in the Jumping Pound field, however, at Jumping Pound West a full uneroded section is generally present. Major reservoir development is limited to the Mt1 and Mt3A. In these two units clean marine carbonates occur in which crinoids are present in varying abundance. Porosity is fossilmoldic, interparticulate and intercrystalline. Dolomitization and resulting porosity appears to be closely related to environmental conditions existing during deposition of the Turner Valley and overlying Mt. Head Formations. Sediments in part of the Mt1, in the Mt2 and Mt3 are usually unfossiliferous microcrystalline dolomites and generally contain varying small amounts of terrigenous silt and clay. These sediments are interpreted to be the product of a very shallow restricted marine to supratidal environment. Considerable intercrystalline porosity may be present in these rocks, however, permeability is characteristically low. The Turner Valley Formation has undergone a complex penedepositional-post-depositional history. Discussed are: chertification, dolomitization, post-Mount Head pre-Nordegg unconformity, Nordegg deposition, deep burial during Cretaceous deposition, Laramide thrusting, solid hydrocarbon, fracturing, stylolites and spar calcite.

Sedimentation and petroleum potential of the jurassic sequence in the southwestern great artesian basin

Abstract: Along the western margins of the southwestern Great Artesian basin the Jurassic sequence is an almost continuous sandstone section. In the eastern part of the same area, this sandstone sequence is broken by two shale-siltstone intervals, the Birkhead and Westbourne Formations. Towards the western margins of the basin these facies change into sandstone. The Murta Member of the Mooga Formation develops in the area north of Lake Frome through a facies change in the upper part of this formation from sandstone to siltstone and shale. It is postulated that the depositional conditions in the southwestern Great Artesian basin were dominantly fluviatile during most of the Jurassic and that the fine grained sediments of the Birkhead and Westbourne Formations and the Murta Member of the Mooga Formation were deposited under low energy lacustrine conditions. Abundant good quality potential petroleum reservoir rock exists throughout the entire Jurassic sequence. The lack of hydrocarbon filled traps found to date and the change of the main siltstone-shale intervals into sandstone facies in the west and southwest, imply that the Jurassic in the southwestern Great Artesian basin has been effectively flushed. However, the complex facies relationship of the sandstone and shale beds indicates that stratigraphically controlled traps may exist. The most prospective part of the Jurassic for commercial hydrocarbons appears to be in the lower part of the Hutton Sandstone.

Geology of the Elk Run gas pool, Jefferson County, Pennsylvania

Abstract: The Elk Run gas pool is a stratigraphic trap typical of the NE.-trending series of Oriskany gas pools on the E. limb of the Sabinsville anticline in W.-central Pennsylvania. Entrapment is largely due to an updip porosity loss, which is about a mile downdip from a regional pinchout of the Ridgeley Sandstone of the Oriskany Group. Minor portions of the entrapment are due to a NE.-trending, downthrown-to-the-south fault at the N. end of the pool, and a SW.-plunging nose at the S. end. Downdip entrapment is against the gas-water contact at minus 5,940 ft. Porosity is largely intergranular, with a maximum of about 20% and a mean of 7.75%, increasing in quality and thickness downdip. The reservoir is considered to be localized by the distribution of Ridgeley Sandstone having greater than 6% porosity. The original shut-in pressure was 3960 psi, an overpressure of about 440 lb for an average depth to the Ridgeley Sandstone of 7246 ft. The original producible gas in place is estimated at 46,670,000 Mcf, with a recovery factor of 809.7 Mcf per acre-ft. (10 refs.)

Phylloid Algal Banks: ABSTRACT

Abstract: Phylloid algal banks form reservoir rocks in Upper Pennsylvanian shelf carbonates in many oil provinces of the United States. They are of special exploration interest in the Strawn (Desmoinesian) of West Texas and eastern New Mexico. Furthermore, the quantity of hydrocarbons in major fields which produce from these stratigraphic traps compares favorably with that produced from structural traps. Phylloid algal banks were studied by the writer. Data were derived from studies of surface and subsurface occurrences of these carbonate buildups. The stratigraphic and regional distribution of these algal banks, their mode of formation, their environmental dependencies, and their synecological associations with other fossil assemblages were studied together with the evaluation of reservoir properties, such as formation and destruction of porosity, log characteristics, production data, and statistics on primary and secondary reserve estimates of major representative fields. Algal mounds are formed by the sediment-baffling action of leaf-like (i.e., "phylloid") algae of the Ivanovia group, a branch of CaCO3-secreting green algae of the family Codiaceae. The dense, pitchy growths of these algae on local shoals on the sea floor form an efficient sediment baffle. Fine-grained carbonate sediment accumulates between the algal blades where it is sheltered from winnowing by wave and current action. This results in the gradual building of a mound-like accumulation of sediment in those places where dense growths of these algae occurred. Thus, these algal mounds are biogenic banks, which, if preserved in the geologic record, would be bioherms and biostromes. Lithologic and paleontologic evidence indicates that these algal banks preferred shallow-water, wave-sheltered shelf environments in areas of clean carbonate deposition, distant from sources of land-derived clastics. Changes of water depth during transgressive and regressive cycles apparently exercised a sensitive control on the growth of these algae. The most luxuriant growth of these algae is obviously confined to an energy level below wave base, although these algae probably could endure intermittent higher wave action. Whenever the water became too shallow and the algal growths were above wave base, the algal mound development was interrupted. In many places, algal mounds are interbedded with layers of cleanly winnowed, well-sorted calcarenite or oolite. Phylloid algae have been reported in the United States from areas in southeast Kansas, the Panhandle of Oklahoma, north-central Texas, the eastern shelf of the Midland basin, the northwestern shelf of the Delaware basin, Hueco Mountains, Franklin Mountains, Sacramento Mountains, Robledo Mountains, and the Four Corners area. These phylloid algae range in age from Morrowan to Wolfcampian in the United States, and to early Middle Permian in Europe. The major occurrences of these algal banks in the Permian basin area are in strata of Desmoinesian, Virgilian, and Wolfcampian ages. In general, algal banks show evidence of a high primary porosity which formed when the highly warped algal blades were piled into a mound having a loose, or open fabric. The presence of such high primary porosity and permeability commonly leads to the development of secondary leaching porosity. Most commonly, the CaCO3 mud matrix between the algal blades is leached. Selective leaching of the algal blades End_Page 207------------------------------ is less common. Recrystallization of the CaCO3 mud matrix also is a common source for secondary porosity development. The combined amounts of primary and secondary porosity and the resulting permeability values may be large. In Greater Aneth field, Four Corners area, porosity values range from 3.5 to 26.2 percent, with an average of 10 percent. Permeability values reach a maximum of 932 md, with an average of 25 md. Estimated primary and secondary petroleum reserves may amount to 500 million bbl. Porosity destruction is caused primarily by secondary sparry calcite vug filling. Extensive leaching in the upper zones of an algal bank forms solutions which are oversaturated in CaCO3. When these supersaturated solutions percolate downward into the lower zones of the mound, precipitation of sparry calcite commonly begins. A rarer type of porosity destruction is that which results from a total collapse of the algal fabric. A relatively rapid diagenetic hardening of the CaCO3 mud matrix apparently is required to prevent collapse of the algal fabric under the weight of overlying sediment. In some places, anhydrite caused porosity occlusion. In one example, the porosity in a core had been destroyed completely by vug fillings composed of isolated small dolomite rhom ohedra. Synecological fossil assemblages associated with algal mounds or mound-associated facies have different compositions in mounds of different stratigraphic and regional settings. The following groups of fossils were recorded in algal banks: Foraminifera, including ophthalmid and encrusting Foraminifera, and fusulinids, ostracods, fenestellid and fistuliporoid Bryozoa, crinoids, echinoids, gastropods, tetracorals, brachiopods, sponges, Chaetetes (tabulate corals), Komia (questionable stromatoporoid), Girvanella (blue-green algae), and Ungdarella (red algae). End_of_Article - Last_Page 208------------

Computers calculate flood potential

Abstract: Electronic computers played a vital role in putting Pennel and Lookout Butte fields, Fallon County, Montana, under waterflood Vast amounts of well and reservoir data were fed to a computer which drew impartial maps to aid in forming the unit Then the computer checked several ways to conduct the waterflood and selected the method with the highest recovery The project, which will be in full operation by late fall, covers 29,000 acres, and will recover an additional 18 million bbl of oil not obtainable by primary means Shell Oil Co is the unit operator Since discovery in 1955, the fields have produced more than 23 million bbl of oil Current producing rate is over 5,000 bpd from 150 wells, most on 160-acre spacing Production is from Mississippian, Ordovician, and Silurian reservoirs at depths from 7,000 to 9,000 ft A good sampling of cored wells provides many rock properties, as cores are available from nearly one well in each 640-acre tract These cores provide porosity, original oil saturation, and permeability data Other porosity data come from sonic and neutron logs

Oil Recovery from Fracture Blocks by Cyclic Injection

Abstract: Results obtained from a number of laboratory tests confirm the previously proposed idea that a cyclic pressuring/depressuring process in fractured reservoirs may have considerable merit over conventional waterflooding. A new idea brought out by these tests is that conservation of reservoir gas and a supplementary gas injection appear to be necessary for the success of pressure pulsing in applicable reservoirs. A description is given of the laboratory experiments, including the rock properties of the reservoir rock. The history of a typical laboratory test is illustrated by a graphical representation. Primary recovery was followed by 8 pressure-pulse cycles and a final blowdown. Primary recovery was 20% of stock-tank oil initially in place. Water injection in the first pressure pulse equaled the volume vacated by the primary gas and oil production. Oil production in the first pressure pulse equaled 15% of oil initially in place. The graph shows that additional oil was produced in successive pressure- pulse cycles, but that the oil yield declined and the water production rose successively in each of the first 4 cycles.