This paper presents a comparison of stochastic and deterministic reserves estimation methods as related to the various stages of development of an oil or gas field, with emphasis on offshore environment. The current debate concerning stochastic and deterministic reserve estimates and definitions is framed with respect to the various stages of field development. Advances in technology in terms of three-dimensional seismic data and reservoir simulation appear to narrow the range of reserves estimates. Field examples are presented to compare stochastic and deterministic reserves estimates. Stochastic methods are preferable during exploration and pre-development, while both methods can be used in practice to support the decision to proceed with development. In the later stages of development, deterministic methods become more practical as other data become available. Advances in technology are leading to better deterministic estimates as well as stochastic estimates with narrower ranges. Practices in the industry vary from complete dedication to deterministic or stochastic to a choice of the method depending on the stage of development. This paper offers recommendations as to which reserves estimation technique is more suitable at specific stages of field development based on data scope and availability. Introduction The comparison and assessment of stochastic and deterministic reserves estimation methods presented in this paper originated through a standardisation program at Petroliam nasional Berhad (Petronas), the national oil company of Malaysia. The Petronas Geosciences Committee was subsequently assigned the responsibility for developing appropriate guidelines for the estimation of hydrocarbon reserves. This Committee's scope of work included reserves estimation in both exploration and development projects, which necessitated comparison of stochastic and deterministic methods. Petronas reviews reserves estimates submitted by several oil companies, each with a preference for one method or the other. A simple method for translating from deterministic to stochastic and vice versa became necessary. The elimination of ambiguity, the adoption of an appropriate and clearly-defined system, and comparison with existing worldwide definitions were other objectives. P. 309
The Dulang Field is located offshore east coast of Peninsular Malaysia in water depths of approximately 75 m. The field, discovered in 1981, is about 24 km by 3.5 km. After drilling 14 exploration/appraisal wells by both Carigali and its partner Esso Production Malaysia Inc., the central part of the field was developed as a unitized area in November 1990. Three 32-slot platforms have been installed in the unitized area, and development drilling is ongoing. Production commenced in March 1991 and is currently maintained at approximately 50,000 BOPD. The estimated OIIP (oil-initially-in-place) for the unitized area is in the order of 700 million barrels. There are 19 reservoir sands in Groups D and E which are of Middle-Late Miocene age. During the exploration/appraisal phase, oil and gas were encountered in the Group E and only gas in the Lower D1 reservoirs. Wireline formation pressure test data taken in the Lower D 1 reservoir in these wells plotted along a common trend with a gradient of 0.06 psi/ft. The lowermost gas pressure point was only 6 m above the normal hydrostatic gradient. It was therefore concluded that an oil column, even if present, would be thin. At the time, it was understandable that the gas pressures plotted along the same trend because the hydrocarbon column of the Lower D1 reservoir was large and extended beyond the limits of the major faults, suggesting a common pool. However, during the development drilling phase, it was discovered that the Lower D1 sandstone was a major oil reservoir, with estimated oil-in-place of about 100 million barrels. Oil columns of 75 m and 40 m have been proven up in the northern and southern flanks of the field, respectively, in the Lower D1. In addition, development plans were flexible enough to be able to effectively exploit the discovery. The well and formation pressure test data suggest that the Lower D 1 has a common pressure system in the gas cap over the central part of the field but different systems in the oil columns. Faulting is suspected to have provided both conduit and seal at different times to accommodate this phenomenon. P. 385
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