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.

Rock types, depositional history, and diagenetic effects, Ivishak reservoir, Prudhoe Bay field

Abstract: The present-day pore system of the Ivishak reservoir is the result of depositional and postdepositional processes. The pore system is a dual system characterized by intergranular porosity, enhanced by leaching, and intragranular microporosity. The combined interaction of deposition and diagenesis together with burial history has caused porosity, permeability, net pay, and water saturation to be highly variable areally and vertically.

Major oil plays in utah and vicinity

Abstract: Utah oil fields have produced a total of 1.2 billion barrels (191 million m{sup 3}). However, the 15 million barrels (2.4 million m{sup 3}) of production in 2000 was the lowest level in over 40 years and continued the steady decline that began in the mid-1980s. The Utah Geological Survey believes this trend can be reversed by providing play portfolios for the major oil producing provinces (Paradox Basin, Uinta Basin, and thrust belt) in Utah and adjacent areas in Colorado and Wyoming. Oil plays are geographic areas with petroleum potential caused by favorable combinations of source rock, migration paths, reservoir rock characteristics, and other factors. The play portfolios will include: descriptions and maps of the major oil plays by reservoir; production and reservoir data; case-study field evaluations; summaries of the state-of-the-art drilling, completion, and secondary/tertiary techniques for each play; locations of major oil pipelines; descriptions of reservoir outcrop analogs; and identification and discussion of land use constraints. All play maps, reports, databases, and so forth, produced for the project will be published in interactive, menu-driven digital (web-based and compact disc) and hard-copy formats. This report covers research activities for the first quarter of the first project year (July 1 through September 30, 2002). This work included producing general descriptions of Utah's major petroleum provinces, gathering field data, and analyzing best practices in the Utah Wyoming thrust belt. Major Utah oil reservoirs and/or source rocks are found in Devonian through Permian, Jurassic, Cretaceous, and Tertiary rocks. Stratigraphic traps include carbonate buildups and fluvial-deltaic pinchouts, and structural traps include basement-involved and detached faulted anticlines. Best practices used in Utah's oil fields consist of waterflood, carbon-dioxide flood, gas-injection, and horizontal drilling programs. Nitrogen injection and horizontal drilling programs have been successfully employed to enhance oil production from the Jurassic Nugget Sandstone (the major thrust belt oil-producing reservoir) in Wyoming's Painter Reservoir and Ryckman Creek fields. At Painter Reservoir field a tertiary, miscible nitrogen-injection program is being conducted to raise the reservoir pressure to miscible conditions. Supplemented with water injection, the ultimate recovery will be 113 million bbls (18 million m{sup 3}) of oil (a 68 percent recovery factor over a 60-year period). The Nugget reservoir has significant heterogeneity due to both depositional facies and structural effects. These characteristics create ideal targets for horizontal wells and horizontal laterals drilled from existing vertical wells. Horizontal drilling programs were conducted in both Painter Reservoir and Ryckman Creek fields to encounter potential undrained compartments and increase the overall field recovery by 0.5 to 1.5 percent per horizontal wellbore. Technology transfer activities consisted of exhibiting a booth display of project materials at the Rocky Mountain Section meeting of the American Association of Petroleum Geologists, a technical presentation to the Wyoming State Geological Survey, and two publications. A project home page was set up on the Utah Geological Survey Internet web site.

Hydrocarbon-Bearing Submarine Fan System of Cellino Formation, Central Italy

Abstract: The Cellino Formation is a lower Pliocene submarine fan system that forms extensive subsurface reservoir rocks. The sequence consists of interbedded sandstones and shales which crop out in central Italy; it exhibits a definite geometric pattern of lateral fan accretion. It is 60 by 20 km (37 by 12 mi), elongate NNW-SSE, and it follows the trend of previous fan systems. The vertical and lateral sequences are interpreted from electric logs and supported by field observations. The Cellino Formation consists of a series of different turbidite facies associations which includes a lower basin-plain fan edge, overlain by outer fan and fringe facies associations. The lower part of the Cellino Formation here has been cut and deeply eroded in the northern part. A new sequence follo s, which activates the eastern migration of the fan system and deposits facies. Postdepositional deformation (compressional faulting and folding) decreases in the area in intensity eastward. Carbonate cements sandstone layers in the southwest part of the area. Associated hydrocarbons were trapped in outer fan lobes which were deformed into an anticline. The thin shale beds provide the cap rocks of the turbidite reservoirs. Many of the depositional lobes have their individual gas-water contacts.

Spirit River Formation--A Stratigraphic-Diagenetic Gas Trap in the Deep Basin of Alberta

Abstract: The Spirit River Formation is a prolific gas producer in the Deep Basin of Alberta. The lower Wilrich Member consists of coarsening-upward clastic cycles from 50 to 100 m (165 to 330 ft) thick. In the southern part of the study area, the Falher Member (the major producer) comprises nonmarine clastics and coals. Around the Elmworth gas field, this member comprises five transgressive and regressive cycles, with alternating marine and nonmarine deposits. Each cycle consists of low-angle, laminated, fine-grained sandstone with varying amounts of coarser sandstone and conglomerate, locally capped by a thin coal. The fine sandstones were deposited by waves in shallow-marine and shoreface environments. Granule conglomerates, which are well sorted, matrix-free, and present immedi tely under the coal, are interpreted as beach deposits. Pebbly conglomerates with poorer sorting, sandy matrix, some cross-bedding, and sharp bases cut into shoreface sandstone are interpreted as distributary-channel deposits, or as shoreface deposits reworked a short distance from a channel. Coarser sandstones and conglomerates of the shore zone form conventional reservoirs with porosities up to 15% and permeabilities to 1 darcy. The fine-grained shoreface and shallow-marine sandstones are "tight sands" with permeabilities of 0.001 to 0.5 md. Petrography has shown that they have lost porosity because of (1) formation of quartz overgrowths, (2) crushing of sedimentary rock fragments, and (3) cementation by carbonates and clays. These processes have also operated in the conglomerates but much primary porosity has been preserved and some secondary porosity has been formed. Deep gas generation from coal has filled the well-connected pores in the conglomerate and the poorly connected pores left in the tight sands. The tight sands have lower permeabilities than some shales and form the seals that trap gas in the basin by retarding updip flow. The Spirit River gas deposits can be considered the result of combined stratigraphic-diagenetic trapping.

Influence of depositional sand quality and diagenesis on porosity and permeability; examples from Brent Group reservoirs, northern North Sea

Abstract: Multivariate statistical analysis was applied to examine correlations between reservoir quality and petrology in two data sets from the Middle Jurassic Brent Group. One of the data sets is from relatively shallow depth and has been little affected by chemical diagenesis (Statfjord Nord and Ost Fields; 2.3-2.6 km below the sea floor), while the second data set is from a more deeply buried reservoir having an advanced degree of diagenesis (Huldra Field; 3.6-3.9 km). Much of the total variation in porosity and permeability within each data set (0.02 mD to > 7 D in both sets) can be accounted for by laboratory measurements of parameters mainly related to depositional sand quality, including "shaliness" (represented by bulk-rock alumina/silica ratio), early carbonate cement, feldspar co tent, and grain size. Despite major differences in the proportions of different sedimentary facies in the two data sets, they have similar ranges of depositional sand quality and therefore probably had similar reservoir quality early in their burial history. Deeper burial diagenesis at Huldra Field has shifted the average of both porosity and permeability to lower values and produced a bimodal permeability distribution, apparently reflecting preferential preservation of permeability in the cleaner sandstones. On the basis of these examples, we outline an approach for unmixing the diagenetic and lithologic components of variation in regional compilations of sandstone porosity-permeability data. The procedure and its consequences are illustrated using a regional compilation of core data fr m the Brent Group of the northern North Sea.