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.

Relationship of Unconformities, Tectonics, and Sea Level Changes in the Cretaceous of the Western Interior, United States: Part III. Middle Rocky Mountains

Abstract: Intrabasin tectonics and sea level changes influenced patterns of deposition and geographic distribution of major unconformities within the Cretaceous of the Western Interior. Nine major regional to near regional unconformities have been identified. Previous workers have related five of these unconformities to sea level changes and to well known regressive-transgressive cycles. The origin of the other four unconformities may be related either to tectonic movement or sea level changes. The approximate dates for unconformities are estimated as follows (formations involved are in parentheses): (1) late Neocomian to early Aptian, 112 m.y. (base lower Mannville, Lakota, Lytle); (2) late Aptian-early Albian, ~100 m.y. (upper Mannville, Fall River, Plainview); (3) Albian, ~97 m.y. (Viking, Muddy, Newcastle, or J Sandstone); (4) early Cenomanian, ~95 m.y. (lower Frontier-Peay, and D); (5) Turonian, ~90 m.y. (base upper Frontier or upper Carlile); (6) Coniacian, ~89 m.y. (base Niobrara or equivalents); (7) early Santonian, ~80 m.y. (Eagle, lower Pierre and upper Niobrara); (8) late Campanian, ~73 m.y. (mid-Mesaverde Ericson, base Teapot); (9) late Maestrichtian, ~66 m.y. (top Lance or equivalents). Variations in the accuracy of the dating are probably within 1 m.y. because f problems in accurately defining the biostratigraphic level of the breaks and in the precision of radiometric dates. The unconformities are grouped into three types: those completely within nonmarine strata such as at the base and top of the Cretaceous, those involving both marine and nonmarine strata, and those within marine strata, as currently mapped. Three examples are described as typical of the unconformities, all thought to be related primarily to drops in sea level, but with minor influence by tectonic movement. One is the ~97 m.y. unconformity, with which the petroleum-producing J and Muddy Sandstone is related. A second is ~90 m.y. unconformity which is recognized by relationships within the shelf, slope, and basin deposits of the Greenhorn, Carlile, and Frontier formations. The third is the ~80 m.y. unconformity within the basin and shoreline regression associated with the upper Niobrara, lower Pierre, Eagle, and Shannon formations. Several billion barrels of oil were found in sandstones associated with unconformities in the Cretaceous of the Rocky Mountain region. Future stratigraphic trap exploration is guided by a knowledge of tectonic influence on sedimentation during sea level changes and how these factors control distribution of source rock, migration patterns, reservoir rock, and seal.

Amplitude map analysis using forward modeling in sandstone and carbonate reservoirs

Abstract: The extent to which seismic amplitude maps can contribute to the analysis of hydrocarbon reservoirs was investigated for clastic and carbonate reservoirs worldwide. By using a petrophysical-based, forward modeling process called incremental pay thickness (IPT) modeling, five lithology types were quantitatively analyzed for the interplay of seismic amplitude versus lithology, porosity, hydrocarbon pore fluid saturation, bedding geometries, and reservoir thickness. The studies identified three common tuning curve shapes (concave, convex, and bilinear) that were primarily dependent upon the lithology model type and the average net porosity therein. While the reliability of pay and porosity predictions from amplitude maps varied for each model type, all analyses showed a limited thickness range for which amplitude data could successfully predict net porosity thickness or hydrocarbon pore volume. The investigation showed that systematic forward modeling is required before amplitude maps can be properly interpreted.

Brine reservoirs in the Castile Formation, Waste Isolation Plant Plant (WIPP) project, southeastern New Mexico

Abstract: The analysis and interpretations by three disciplines - geology, hydrology, and chemistry - have been integrated to form a model of brine reservoir genesis, and to assess the current and future status of brine reservoirs as they relate to the WIPP site. In summary, the brine reservoirs appear to be local, isolated features that have reached equilibrium with their environment. Evidence for long-term hydraulic and chemical isolation includes: Hydraulic heads that are substantially different from reservoir to reservoir and higher than the heads of local ground waters. The containment of gas by the reservoirs. Brine and associated gas chamistries that differ from reservoir to reservoir. Geographic separation and nonuniform distribution of reservoirs, i.e., extensive drilling has taken place in this area, but only a few wells have intercepted pressurized brines. There is no evidence for a continuous, extensive aquifer in the Castile. Bulk chemical equilibrium between the brine, gas, and reservoir rock in the ERDA-6 and WIPP-12 reservoirs.

Quantitative Seismic Reservoir Characterization of an Oligocene Miocene Carbonate Buildup: Malampaya Field, Philippines

Abstract: The complex reservoir architecture of the Malampaya carbonate buildup offshore Palawan, Philippines, was initially controlled by a rugged clastic basement morphology, which was overgrown by atoll structures during the Oligocene and early Miocene. Additional factors with major impact on reservoir quality are frequent and high-amplitude relative sea level fluctuations, ocean currents, and prevailing wind directions. Primary depositional reservoir-quality distribution has been overprinted by diagenetic events, primarily as a result of repeated platform-top exposure and submarine cementation. Inherent noise within the previous seismic data introduced by the complex overburden and buildup morphology has resulted in inconsistent seismic attribute distribution. Therefore, earlier reservoir modeling efforts used seismic horizon and volume interpretation only, coupled with the sequence- and cyclostratigraphic architecture and the concept of reservoir rock types for field development planning. Prior to gas-development drilling, another attempt was made to extract direct reservoir-quality information from the reprocessed three-dimensional (3-D) seismic data to validate the earlier deterministic reservoir models. Improved 3-D prestack depth migration based on a new velocity model has been the foundation of the quantitative seismic analysis for reservoir characterization, static modeling, reserves estimation, and optimized gas development and oil appraisal well targeting. High-porosity areas in the upper part of the reservoir were identified using top-reservoir reflection amplitudes. This provided the tool to minimize penetration of low-porosity, fractured zones prone to mud losses in the gas development wells. A series of acoustic-impedance inversions were applied to create reservoir porosity cubes from seismic and to target wells in good reservoir areas. Porosity cubes are also essential for a correct time-depth conversion of the static model, using a linear porosity-velocity relationship in clean carbonates, which was derived from well data. Several static model realizations were created using the porosity cubes from seismic as a backdrop combined with 3-D seismic facies analysis and a depositional model based on well data and analogs. The results of the five gas-development wells have confirmed the modeled reservoir-quality distribution within the lagoonal part of the northern Malampaya accumulation. Early production performance following first gas in October 2001 is indicative of excellent lateral pressure communication in this area of the buildup, in accordance with earlier dynamic models. Porosity-height realizations created from the different seismic porosity cubes proved valuable to visualize uncertainty in reservoir-quality distribution within the Malampaya oil rim and formed the basis for targeting a horizontal appraisal well. The MA-10 horizontal oil-rim appraisal well drilled at the end of 2001 confirmed the forecasted facies distribution and reservoir properties as derived from the model. Based on the new quantitative seismic reservoir characterization, additional areas of potentially good reservoir quality have been identified in the southern Malampaya culmination and on the western flank of the northern culmination. Both areas were previously considered to contain low-porosity reservoir caused by pervasive early marine cementation.