Petroleum reservoir

About: Petroleum reservoir is a research topic. Over the lifetime, 5403 publications have been published within this topic receiving 83535 citations. The topic is also known as: petroleum deposit.

Effects of capillarity and vapor adsorption in the depletion of vapor-dominated geothermal reservoirs

Abstract: Vapor-dominated geothermal reservoirs in natural (undisturbed) conditions contain water as both vapor and liquid phases. The most compelling evidence for the presence of distributed liquid water is the observation that vapor pressures in these systems are close to saturated vapor pressure for measured reservoir temperatures (White et al., 1971; Truesdell and White, 1973). Analysis of natural heat flow conditions provides additional, indirect evidence for the ubiquitous presence of liquid. From an analysis of the heat pipe process (vapor-liquid counterflow) Preuss (1985) inferred that effective vertical permeability to liquid phase in vapor-dominated reservoirs is approximately 10{sup 17} m{sup 2}, for a heat flux of 1 W/m{sup 2}. This value appears to be at the high end of matrix permeabilities of unfractured rocks at The Geysers, suggesting that at least the smaller fractures contribute to liquid permeability. For liquid to be mobile in fractures, the rock matrix must be essentially completely liquid-saturated, because otherwise liquid phase would be sucked from the fractures into the matrix by capillary force. Large water saturation in the matrix, well above the irreducible saturation of perhaps 30%, has been shown to be compatible with production of superheated steam (Pruess and Narasimhan, 1982). In response to fluid production the liquid phase will boil, with heat of vaporization supplied by the reservoir rocks. As reservoir temperatures decline reservoir pressures will decline also. For depletion of ''bulk'' liquid, the pressure would decline along the saturated vapor pressure curve, while for liquid held by capillary and adsorptive forces inside porous media, an additional decline will arise from ''vapor pressure lowering''. Capillary pressure and vapor adsorption effects, and associated vapor pressure lowering phenomena, have received considerable attention in the geothermal literature, and also in studies related to geologic disposal of heat generating nuclear wastes, and in the drying of porous materials. Geothermally oriented studies were presented by Chicoine et al. (1977), Hsieh and Ramey (1978, 1981), Herkelrath et al. (1983), and Nghiem and Ramey (1991). Nuclear waste-related work includes papers by Herkelrath and O'Neal (1985), Pollock (1986), Eaton and Bixler (1987), Pruess et al. (1990), Nitao (1990), and Doughty and E'ruess (1991). Applications to industrial drying of porous materials have been discussed by Hamiathy (1969) arid Whitaker (1977). This paper is primarily concerned with evaluating the impact of vapor pressure lowering (VPL) effects on the depletion behavior of vapor-dominated reservoirs. We have examined experimental data on vapor adsorption and capillary pressures in an effort to identify constitutive relationships that would be applicable to the tight matrix rocks of vapor-dominated systems. Numerical simulations have been performed to evaluate the impact of these effects on the depletion of vapor-dominated reservoirs.

Reservoir Formation Damage; Reasons and Mitigation: A Case Study of the Cambrian–Ordovician Nubian ‘C’ Sandstone Gas and Oil Reservoir from the Gulf of Suez Rift Basin

Abstract: Reservoir formation damage is a major problem that the oil and gas industry has to mitigate in order to maintain the oil and gas supply. A case study is presented that identifies the impacts of formation damage and their causes in the Nubian ‘C’ hydrocarbon reservoir within Sidki field located in the Southern Gulf of Suez, Egypt. In addition, a formation damage mitigation program was designed and implemented involving an effective stimulation treatment for each well experiencing reservoir damage. The data available for this study include core analysis to provide rock mineralogy and lithology; analysis of production fluid data; water chemistry; drilling fluid composition; perforations and well completion details; workover operations; and stimulation history. The diagnosis of formation damage based on the integrated assessment of the available data is associated with several benefits, (1) The integration of the data available helps provide a robust analysis of formation damage causes and in establishing suitable remediation actions, (2) Workover fluid is confirmed as the primary cause of reservoir damage in the studied well, (3) Several reservoir damage mechanisms were identified including water blockage, solids and filtrate invasion, fluid/rock interaction (deflocculation of kaolinite clay), salinity shock and/or high-sulfate content of the invaded fluid, (4) Irrespective of the potential causes of formation damage, the primary objective of a gas production company is to mitigate its effects and the integrated dataset helps to design appropriate and effective stimulation treatments to overcome formation damage, and (5) In gas reservoirs, especially low permeability ones, extra precautions are necessary to avoid potential reservoir damage due to workover fluid invasion.

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.