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 Bolívar Coast Heavy Oil Fields (Tía Juana, Lagunillas and Bachaquero), located at the eastern onshore area of Maracaibo Lake, Western Venezuela, contain some 37 billion barrels of Oil Originally In Place. The recovery from these three giant fields is 5.5 billions (15% STOOIP), and is expected to reach 7.7 billions (21% STOOIP) under current primary recovery method (Cyclic Steam Injection). It has been estimated that an additional 39% of STOOIP in potential areas for steamflooding could be recovered by this process. Previous conceptual studies, and field projects in Bolivar coast area has showed high recovery factor and marginal economics. Those project were conducted under conventional application of technology. In the last 10 years, technology has evolved in such a way that monitoring can be improved and the performance enhanced for secondary recovery process. These new technologies, such as 4D seismic, Tomography, fiber optic, new approach for steam generation etc., have been tested in different steamflood projects with high impact in the added value. PDVSA E&P has adopted a new approach to carry out technological projects under the philosophy of the Integrated Field Laboratories. This concept is a wider definition of a Pilot Test, since it encompasses the ideas of evaluating a secondary recovery process and performing the corresponding reservoir management. The reservoir management includes the evaluation of different technologies for monitoring and control and the simulation and visualization of the process itself, so injected fluid fronts can be tracked down the reservoir. This will allow the creation of an integrated data base and the use of intelligent information systems in order to predict changes and perform decision analysis. The lesson Learned in this Lab will help us to optimize and become marginal projects into profitable ones. This paper presented the results obtain up to date in the integrated field laboratory that for heavy oil is conducted in W-6 area of Lagunillas Field in the Bolivar coast.

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