Showing papers on "Petroleum reservoir published in 1973"

Small-Scale Fracture Density in Asmari Formation of Southwest Iran and its Relation to Bed Thickness and Structural Setting

Abstract: Knowledge of the distribution of rock fractures in the Asmari limestone reservoir rock of the prolific Khuzestan oilfield belt of southwest Iran provides for a better understanding of the production mechanism. Though the high productive capacity of wells in this area has been ascribed predominantly to fracturing of the reservoir rock, quantitative work on this topic has been neglected in the past. Details of small-scale fracturing have been investigated locally on individual anticlines and regionally in Asmari limestone outcrops over an elongate area of about 2,000 sq mi (5,180 sq km) of the Zagros Mountains foothills. Fracture density has an inverse logarithmic relation to bed thickness, but it is independent of structural setting. Such findings make necessary the rejection of a theory involving a genetic relation of fractures of this scale to the folding process, at least in the area studied. The early formation of fractures is such that their orientations are related to localized irregularities, and their initiation by shock waves is suggested. Specific values for average fracture spacing in the Asmari limestone beds provide valuable data for the reservoir engineer. Fold formation by the exploitation of appropriate preexisting fracture sets enhances reservoir porosity and permeability in preferred directions.

Laboratory study of the effects of confining pressure on fracture flow and storage capacity in carbonate rocks

Abstract: Natural fracture systems are the principal source of flow capacity of many reservoirs and constitute a major portion of the storage capacity of some reservoirs. Declines in reservoir fluid pressure, due to production which increases net overburden pressure, reduce fracture flow and storage capacity and would be expected to have important influences on reservoir performance. A laboratory study was made to develop means to predict the effects of increased net overburden pressures on fracture capacity. Permeabilities of jacketed, fractured cores were measured as uniform triaxial confining pressure was varied over a range of 50 to 20,000 psi. Fabricated cores containing uniform, planar, longitudinal fractures were studied first and then reservoir core samples containing natural fractures were investigated. Response to confining pressure increase was found significant and similar in mode for both facbricated and natural fracture systems. A linear relationship was found between the cube root of permeability, theoretically proportional to fracture porosity, and the logarithm of confining pressure. (22 refs.)

Wattenberg field denver basin, colorado

Abstract: Wattenberg field produces from a large gas accumulation (1.1 Tcf estimated recoverable reserves) in the "J" sandstone of Cretaceous age. The trap was formed in the delta-front environment of a northwesterly prograding delta. The gas is contained in a stratigraphic trap straddling the axis of the Denver basin. Reservoir characteristics are poor, and fracturing by artificial means is necessary to test a well. Large extensions to the field may be made in the future by following the trend of the delta-front environment. Industry exploration efforts will be dependent on gas-price economics.

Jay Field--A Jurassic Stratigraphic Trap

Abstract: The first Jurassic oil discovery in Florida was made in June, 1970, near Jay, 35 miles north of Pensacola. Current estimates indicate recoverable reserves in the Smackover Formation should exceed 300 million stock tank barrels of oil and 300 billion cubic feet of gas. Production occurs on the south plunge of a large subsurface anticline with the updip trap formed by a facies change from porous dolomite to dense micritic limestone. The Smackover consists of a lower transgressive interval of laminated algal mat and mud flat deposits and an upper regressive section of hardened pellet grainstones. Early dolomitization and freshwater leaching have provided a complex, extensive, high quality reservoir. Irregular distribution of facies presents difficult problems in development drilling, unitization, and planned pressure maintenance programs. Hydrogen sulfide content of the hydrocarbons requires expensive processing facilities and well investment. A typical completed well costs $650,000 with an additional $200,000 for flowline and inlet separation facilities. Add to this $550,000 for plant facilities to sweeten the oil for market, and each well investment approaches $1,400,000. Daily production from Jay Field will approach 85,000 barrels from approximately 85 wells less than three years after discovery. This rapid development results from a coordinated development program with modular plant design.

Effect of Postsedimentation Processes on Carbonate Reservoir Rocks in Volga-Urals Region, USSR

Abstract: Porosity and permeability of carbonate rocks are controlled by (1) sedimentation conditions, which determine primary textural features, and (2) secondary postsedimentation processes. Bioclastic carbonates, with small amounts of cement and without any appreciable amounts of secondary minerals, form the best carbonate reservoir rocks. Postsedimentation processes appreciably alter the primary textures and thus affect the reservoir rock properties. Such processes as solution and formation of fractures and stylolites considerably improve porosity and permeability of carbonate rocks. Processes of sulfatization, calcitization, and silicification, resulting in filling and sealing of pores, cavities, and fractures, adversely affect reservoir properties. Processes of secondary mineral formation, however, indirectly improve the flow capacity of rocks by creating heterogeneous texture, which favors the formation of fractures and solution cavities. The development of carbonate rock porosity is very complex because of the alteration by solution and secondary mineral-formation processes. Porosity and permeability of carbonate reservoirs were found to be related closely, with the correlation factor ranging from 0.7 to 0.8.

Entrapment of Petroleum in Isolated Porous Bodies

Abstract: Isolated traps form a place for hydrocarbon accumulation that precludes water when the supply of oil and gas is adequate. Water is precluded by capillary displacement pressure in the preferential occupation of a porous mass completely surrounded by a less permeable matrix (preferably unoxidized organic shale, as a source bed). Such an isolated porous mass is designated herein as an "isolani." The isolani concept is useful in the understanding of many stratigraphic accumulations of hydrocarbons and their subsequent preservation. This concept explains the closed areas of low potential coincident with many large gas deposits. Isolated reservoirs can be identified by the primary characteristics of the isolani, the occurrence of anomalous sinks or swells in a potentiometric surface, or the presence of little or no bottom or edge water. The secondary characteristics are the presence of water updip toward the outcrop in the stratigraphic unit, the absence of water downdip, and the general irrelevance of structure. Where water does occur with hydrocarbons in an isolani reservoir, it may take up a minor part of the entire reservoir system in contrast with structural traps or ordinary stratigraphic traps, wherein water is the main component of the system downdip in a basinward direction. Isolani traps are an important class of stratigraphic reservoirs, forming very large fields in the basin structural lows. Examples are some of the fields in Cretaceous sandstone of the San Juan and Denver-Julesburg basins; the Muddy sandstone of the Powder River basin; the Cherokee sandstone of eastern Oklahoma and Kansas; the Atoka limestone and Morrow sandstone of the deeper part of the Delaware basin; the shoestring sandstones of Michigan; the fractured Niobrara shale of Colorado, Wyoming, and other parts of the Rockies; and some of the older fields of Pennsylvania, West Virginia, and Ohio. Isolani traps can be divided broadly into primary and secondary types, depending on the coincidence of their formation with the completion of either sedimentation or compaction. Primary isolani are largely filled with oil. Secondary isolani can be oil filled, but more commonly are filled with gas. The primary isolani generally are related to the larger shale units by inclusion, and most secondary isolani are found in juxtaposition to the larger shale units. Certain stratigraphic models can be identified broadly with either type. Primary isolani contain oil toward the basin center and gas toward the outcrop or high on the limbs; secondary isolani generally contain gas wherever found. Such variations can be a guide to exploration. Isolani-type fields can occur anywhere in a basin at any depth, but are most conspicuous in the basin structural lows. Because isolani traps are dependent on stratigraphic models and not structure, there are vast untested areas of basins without structures which are excellent targets for oil and gas deposits. Isolani have produced some of the largest gas fields found in the United States. Because isolani so commonly are large in areal extent, they represent an important target for future petroleum reserves, especially gas.

Log-injected-log system

Abstract: This invention relates to determining the oil saturation in the underground rock reservoir by use of a log-inject-log technique. The formation rock adjacent the well bore is prepared such that the saturation conditions there are representative of those in the interwell area. A thermal decay time log is then run. A chlorinated hydrocarbon oil mixture or blend miscible with the formation oil and having a chlorine content about the same as the formation water is used to displace all the formation oil from adjacent the well bore. A second thermal neutron decay time log is then run. These two logs are then used to determine reservoir characteristics.

Effects of permeability variation and production rate on recovery from partial water drive gas reservoirs

Abstract: A 2-dimensional reservoir simulator has been used to investigate the effect of areal permeability variation and production rate on gas recovery from partial water drive gas reservoirs. The prototype reservoir is typical of those found on the Gulf Coast, i.e., it is low dip, highly porous and permeable, and exhibits wide areal variation in permeability. For the uniform well pattern and areal permeability variation studied, recovery efficiency was essentially independent of the degree of permeability variation and the dimensionless gas production rate. Gas recovery from individual wells at equivalent structural positions, however, varied widely. It was concluded that areal permeability variation and production rate can influence the uniformity of aquifer encroachment in partial water drive gas reserviors. Under conditions of irregular well pattern and the wide areal variation in permeability typically encountered in Gulf Coast reservoirs, it is suggested that not only well but also reservoir recovery will be influenced by degree of permeability variation and production rate. (13 refs.)

Engineering waterfloods for improved oil recovery

Abstract: The basis for an engineering design of a waterflood is a prediction of expected performance. The basic data required are (1) rock properties; (2) reservoir fluid characteristics; (3) overall reservoir description; and (4) a measure of the reservoir heterogeneity. These factors, together with judgment of possible flooding patterns, yield the calculated performance when used with a prediction technique. Two basic types of rock properties are (1) those influenced by the rock skeleton along; and (2) those influenced jointly by the rock and reservoir fluids. Reservoir fluid characteristics required for a prediction of reservoir performance consist primarily of oil and water viscosities at reservoir temperature and pressure. The mobility ratio is the single most important characteristic of a waterflood--a combination of rock and fluid properties.

Hydrology of the Piceance Basin and its impact on oil shale development

Abstract: The Piceance Basin is a structural downwarp in NW. Colorado. The Green River Formation, the uppermost stratigraphic unit in the basin, contains the richest oil shale deposits in the U.S. The near-surface rocks are commonly jointed. The joint density is a function of the competency and thickness of the individual layers, the lateral distance to a free surface, and the depth below the surface. These joints provide permeable paths for the flow of ground water. Consequently, soluble elements in the rock have been leached, thereby enhancing the transmissivity by fracture enlargement. Thus, the oil-shale layers are part of the aquifer matrix, and the richest layers of oil shale occur between, below or are part of the basin's complex aquifer system. Well over 1 million acre-ft of potable water is contained in the Green River ground-water system.

Subsurface stratigraphic analysis, lower Hoxbar Group (Pennsylvanian), Dutton-Verden-Norge trend, Caddo and Grady counties, Oklahoma

Abstract: The area of investigation is approximately 168 square miles in western Grady and eastern Caddo Counties, Oklahoma. It is on the west-central flank of the Anadarko Basin, a northwestward trending structural and depositional basin in southwestern Oklahoma where Paleozoic sediments reach a thickness of more than 35,000 feet. This investigation involves a stratigraphic analysis of the lower part of the Late Pennsylvanian (Missourian) Hoxbar Group, which attains a total thickness of 2,800 feet in this area. The Hoxbar Group includes strata between the top of the No-Ho-Co "formation" and the base of Marchand. Major sandstone developments in this group are (in descending order): Wade sand, Hedlund sand, Medrano sand and Marchand sand. The Marchand sand is the only sand of economic importance to date in the area investigated. The major objectives of this investigation were (1) to determine the geometry of the Marchand sand, (2) to reconstruct the paleodepositional environment of the sand; and (3) to determine the relative importance of structure versus stratigraphy in oil accumulation in the Marchand sand. The Marchand sand appears to be marine offshore bars, the tops of which have been partially truncated during a still-stand or regression of the sea. Vertical and lateral variations in porosity and permeability in the reservoir rocks result in oil accumulation in upper, middle, lower and even multiple units within the sand. Structure exerts only minor effects upon accumulation; the trapping mechanism being essentially stratigraphic. One probable source area of the Marchand sand is to the southeast where sediments were carried by longshore currents from tectonically active source lands within and along the eastern flanks of the Anadarko Basin. Other possible sources include the Wichita Mountains to the southwest, local growth structures such as the Cement anticline, and the shelf area to the northeast which may have been exposed to subaerial erosion intermittently in Early Missourian time. The Marchand sand extends for more than 16 miles trending northwest-southeast. The first production in the area was discovered in 1967 in N. E. Verden Field. At the end of December, 1970, 45 wells were producing and by the end of May, 1971, 74 producing wells had been completed utilizing 160-acre spacing. The reservoir sand ranges in thickness from zero to 260 feet, the sand is undersaturated and the gas/oil ratios are approximately 700 to 1. Reserves for wells with thickest pay sections are more than 750,000 barrels of oil (Graff, 1971, p. 1687-88). Similar stratigraphic trends may be presented in the upper units of the Hoxbar Group in the area investigated.

Petroleum geology, Sweetgrass Arch, Alberta

Abstract: The Sweetgrass Arch is a positive structural feature extending from central Montana into SE. Alberta. Rock units ranging in age from Precambrian Beltian to Upper Cretaceous Montanan are exposed along the 350-mile axis. Early exploration for hydrocarbons was naturally focused on the search for structural traps because such a large positive trend would be expected to have many faulted and domal anomalies. Active development work over the years proved that the stratigraphic trap predominated as the setting for hydrocarbon accumulation. Even the large, closed structural anomaly of the Kevin-Sunburst Dome does not entirely cause the entrapment of oil and gas there, but irregular porosity development in Mississippian carbonates and lensing and pinchout of Cretaceous sandstones more accurately accounts for the accumulation found to date. Large gas reserves are found in thin blanket sandstones of Upper Cretaceous age, principally in the Medicine Hat and Second White Specks zones. Minor gas deposits also are found in the Lower Cretaceous Bow Is. Formation in long, narrow sand bars. A 300-ft thick interval of silty and sandy shale in the Milk River Formation has been known to contain gas for some time, but only recently has this enormous deposit been developed. (10 refs.)

Delineating a Subsurface Fracture System in A Petroleum Reservoir-An Experiment

Abstract: The use of a multisensor array has shown that hydraulic pressurization can be useful in delineating subsurface fracture systems in petroleum reservoirs. It can help in establishing effective patterns of injection and production wells to avoid premature waterfront breakthrough, and thus increase sweep efficiency and oil recovery in flooding operations.

Indications of oil and gas in the upper Precambrian

Abstract: As in the basins in Siberian and Russian platforms and elsewhere, economic inflows of oil and gas occur in the Wendian complex, particularly in its base and at its contacts with the Riphean. This is explainable by initial buildup of the hydrocarbons in the transgressive sedimentary series and by improvements in reservoir properties in the host rocks next to the contacts.