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.

Upper Cretaceous Microbial Petroleum Systems in North-Central Montana

Abstract: Cenomanian to Campanian rocks of north-central Montana contain shallow economic accumulations of dry natural gas derived from microbial methanogenesis. The methanogens utilized carbon dioxide derived from organic matter in the marginal marine sediments and hydrogen from in situ pore water to generate methane. The most recent USGS assessment of the shallow gas resources of eastern Montana used a petroleum systems approach, identifying the critical components of a petroleum system (source rock, reservoir rock, seal rock, and trap) and their temporal relationships. As a part of this effort, geochemical data from natural gas wells and associated formation waters were used to identify two microbial gas systems and the timing of methanogenesis. Two microbial gas families are identified in north-central Montana based on stable carbon isotope and gas composition. The Montana Group gas family has heavier δ13C methane values, slightly lighter δD methane values, and a lower carbon dioxide and nitrogen content than the Colorado Group gas family. The two gas families may reflect, in part, the source rock depositional environments, with the Colorado Group rocks representing a more offshore marine depositional environment and the Montana Group rocks representing proximal marine, deltaic and nonmarine depositional environments. Assuming the gas families reflect only source rock characteristics, two microbial petroleum systems can be defined. The first petroleum system, called the Colorado Group microbial gas system, consists of Colorado Group rocks with the shales in the Belle Fourche Formation, Greenhorn Formation, and the Carlile Shale as the presumed source rocks and the interbedded Phillips and Bowdoin sandstones and the Greenhorn Formation limestones as reservoirs. The second petroleum system, called the Montana Group microbial gas system, consists of the Montana Group rocks that include the Gammon Shale and possibly the Claggett Shale as source rocks and the Eagle Sandstone and the Judith River Formation as reservoirs. The Niobrara Formation is tentatively placed in the former system. The geographic extent of the two microbial systems is much larger than the study area and includes an area at least from the Alberta basin to the northwest to the Powder River basin to the southeast. Upper Cretaceous microbial gas accumulations have been recognized along these basin margins at burial depths less than 3000 ft, but have not been recognized within the deeper parts of the basins because subsequent charge of thermogenic oil and gas masks the preexisting microbial gas accumulations. Methanogenesis began soon after the deposition (early-stage methanogenesis) of the Cenomanian to Campanian source sediments, and was either sustained or rejuvenated by episodic meteoric water influx until sometime in the Paleogene. Methanogenesis probably continued until CO2 and hydrogen were depleted or the pore size was compacted to below tolerance levels of the methanogens. The composition of the Montana and Colorado Group gases and coproduced formation water precludes a scenario of late-stage methanogenesis like the Antrim gas system in the Michigan basin. Some portion of the methane charge was originally dissolved in the pore waters, and subsequent reduction in hydrostatic pressure caused the methane to exsolve and migrate into local stratigraphic and structural traps. The critical moment of the microbial gas systems is this timing of exsolution rather than the time of generation (methanogenesis). Other studies suggest that the reduction in hydrostatic pressure may have been caused by multiple geologic events including the lowering of sea level in the Late Cretaceous, and subsequent uplift and erosion events, the youngest of which began about 5 Ma.

Porosity prediction, prior to drilling, in sandstones of the Kekiktuk Formation (Mississippian), North Slope of Alaska

Abstract: Porosity in sandstones of the Kekiktuk Formation was successfully estimated prior to drilling of the 1 Leffingwell wildcat well (North Slope of Alaska). The estimate was based on a calibration dataset used to evaluate the effects of (1) framework grain composition, (2) depositional facies, and (3) postdepositional processes on porosity of Kekiktuk sandstones. The sandstones of the Kekiktuk Formation are chert-bearing sublitharenites and quartzarenites characterized by a homogeneous composition of the detrital framework in the study area. Thus, mineral composition is not a major factor responsible for differences in reservoir quality. Based on outcrop and available core observations, the Kekiktuk Formation was interpreted to include several wet fan-deltas. The depositional model suggested that the 1 Leffingwell well would penetrate the distal, fine-grained facies of one such system. A petrographic study indicated that in fine- and very fine-grained Kekiktuk sandstones, such as those predicted in the wildcat, porosity was reduced primarily by silica cementation. Silica cementation, in turn, is related to burial history. Because of the relationship among porosity, silica cementation, and burial history, burial history diagrams provided a measure of the effect of burial history on porosity in available calibration wells. A synthetic burial history curve was constructed prior to drilling of the 1 Leffingwell well from available seismic data. This burial history curve was then used to estimate the well's porosity based on the previously established porosity-burial history relationship.

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.

Heavy Oil Production by Electromagnetic Heating in Hydraulically Fractured Wells

Abstract: The results of numerical studies of heavy oil production by radio frequency–electromagnetic heating (RF–EM) from hydraulically fractured low-permeability reservoirs are presented. The fluid flow to a single vertical high-conductivity fracture is considered assuming that electrical and thermal properties of the reservoir rock and fluid-saturated fracture are the same. Comparative analysis is performed for the cases of heavy oil recovery by RF–EM radiation with hydraulic fracturing and “cold” production. Modeling of the combined multi-stage method and economic analysis for different RF–EM generator powers, differential pressure between the well and formation, and the fracture conductivity showed that the method is most effective for wells with “short” and low-conductivity hydraulic fractures.