Mara west field located onshore Lake Maracaibo in Western Venezuela, was discovered in 1951 by well DM-115. Other wells drilled afterwards showed rather goods productivity, but the economics and prevailing market conditions discouraged full field development. Initial reserves were estimated at 33 MMSTB, by volumetric calculation. Additional exploratory drilling in 1972 and improvements in oil prices allowed a development program consisting of 6 producers in a 600 acres areal span. Production reached 10 MSTB/D at the maximum field potential by 1974. Planned production rate could not be optimized because of the lack of sufficient information about the current resources (STOOIP) and reservoir heterogeneity. A multidisciplinary study was carried out to determine the upside potential of the field reserves. Static and dynamic probabilistic approaches were used to estimate the reserves and identify the associated uncertainties. A Monte Carlo probabilistic approach combined with the new data from the updated geological and petrophysical models produced new STOOIP numbers, which were also estimated separately, by multiple material balance calculations using the system (matrix plus fracture) compressibility, as the variable with the most uncertainties. The study found new areas of additional development, that had no been explored. Drilling activities restarted in 1994 to tap these new opportunities with some success. The study is being continuously updated with the new data. Probable and possible reserves are currently being assessed to evaluate the merits for implementing an enhanced recovery process. In view of high degrees of uncertainties associated with the reservoir variables, a deterministic approach of reserves calculation can never be counted as a truly unique solution. Therefore, dynamic and static probabilistic approaches provided more general and viable solutions by bracketing these solutions with associated risks. Literature Survey Numerous publications can be cited in the petroleum industry about, the various definitions, interpretations, techniques and applications of reserves calculations and terminologies. Only a few recent articles are referred here that pertain to the present case study. The latest reserves definitions approved by the SPE Board of Directors on February 27, 1987 appeared as an official publication on October 1, 1988. The official SPE position on the definitions of "proved" and "unproved" reserves was summarized in this publication. The "unproved" reserves were further categorized as "probable" and "possible" reserves. The means of recovering reserves from the in-place hydrocarbons were also outlined, such as recovery by natural reservoir energy or improved recovery methods. During the same year, 1987, the SPE approved the oil and gas reserves definitions, the World Petroleum Congress (WPC) approved the classification and the nomenclature for petroleum and petroleum reserves. Even though there was no coordination or discussion between the SPE and the WPC groups responsible for these efforts, the concepts and definitions in the two documents were very similar. Extensive research throughout all sectors of the oil industry in most of the oil producing countries went into both the SPE and WPC reserves definitions. Finally, the two organizations joined their efforts together to produce a single set of reserves definitions as a de facto standard for worldwide use in the petroleum industry. The result was a single set of reserves definitions drafted by the Task Force of Petroleum Reserves Definitions of both the organizations in 1997 with input from outside organizations, companies and individuals. P. 557^
The objective of this work was to create an integrated model of the F4U, F4L, F5, F67, F8, H12 and H3U,L clastic reservoirs, within the Lower Miocene Oficina Formation of the Oritupano B field (Eastern Venezuela Basin) in order to evaluate different development alternatives for these reservoirs. Based on the 3D seismic data reinterpretation, a new model was developed integrating new structural data and sequence stratigraphy as well as defining the different depositional sequences. A new sedimentological interpretation and stratigraphic framework from correlations and two available cores were used to determine the main sedimentary bodies and trends of deposition. The static model was developed using geostatistical techniques and incorporating the new structural and sedimentological models as well as the available petrophysical data. Stochastic simulations were performed in order to obtain the areal and vertical properties distribution for the different deposits. The results showed consistency with the depositional model previously defined. Two numerical simulation models were created: a stochastic model, based on the results of the geostatistical analysis, and a deterministic model, based on the new conventional static model. Both simulations yielded similar results. The adjustment of the static/dynamic models allowed the determination of oil reserves associated with these reservoirs and the refinement of the optimal exploitation strategy. The new geological model indicates that the main structural features of the field are normal faults and extensional reverse drag folds, unlike the preexisting model in which a gentle homocline structure was suggested. A SW-NE depositional trend for the erosive channels and NW-SE depositional trend for coastal bars, parallel to the paleocoastline, were determined. In addition, four depositional sequences were defined formed by transgressive and highstand systems tracts. Both, the stochastic and the deterministic model suitably represent the dynamic behavior of the studied reservoirs. The communication between the F-H sands of the up-thrown block, with the A9-A13 sands of the down-thrown block, was demonstrated through both dynamic models, which also improved the characterization of the aquifers within the reservoirs. Based on the results of this study, 3 new vertical wells and 5 additional workover wells were recommended. It is expected that these wells will increase the recovery factor of the F-H sands by 12 %. Introduction The Oritupano B field is a part of the Oritupano-Leona Block, located in the Eastern Venezuela Basin. The field was discovered in 1954 with the drilling of the well ORM-1. The F67 sand reservoirs were discovered in 1970 with the completion of well ORM-8. These sands constitute the most important reservoirs of the field. The F-H sands are associated to large and active aquifers that constitute the main production mechanism. Oil gravity ranges between 15 and 18°API and Productivity Index between 18 and 20 bbl/d/psi. Estimated STOOIP for these reservoirs is 106 MMbbl, with cumulative production of 23,5 MMbbl and cumulative Recovery Factor of 22.1%. The existing geological model for the field consists of a gentle homocline, dipping to the north at an angle of 3 to 6 degrees. The structure is limited by three E-W main normal faults, fault planes dipping 35 to 40 degrees to the South. Throws vary from 50 to 550 ft. There are some secondary faults of very low vertical displacement. They run parallel to the main fault and are associated to the main system. The sedimentological model indicates the predominance of a fluvial deltaic sedimentation environment with facies associated to erosive channels and coastal bars deposits.
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