This study describes the stratigraphic characteristics and distribution of fluvial deposits of the Upper Cretaceous Williams Fork Formation in a portion of Rulison Field and addresses 3D geologic modelling of reservoir sand bodies and their associated connectivity. Fluvial deposits include isolated and stacked point-bar deposits, crevasse splays and overbank (floodplain) mudrock. Within the Williams Fork Formation, the distribution and connectivity of fluvial sandstones significantly impact reservoir productivity and ultimate recovery. The reservoir sandstones are primarily fluvial point-bar deposits interbedded with shales and coals. Because of the lenticular geometry and limited lateral extent of the reservoir sandstones (common apparent widths of ∼500-1000 ft; ∼150-300 m), relatively high well densities (e.g. 10 acre (660 ft; 200 m) spacing) are often required to deplete the reservoir. Heterogeneity of these fluvial deposits includes larger scale stratigraphic variability associated with vertical stacking patterns and structural heterogeneities associated with faults that exhibit lateral and reverse offsets. The discontinuous character of the fluvial sandstones and lack of distinct marker beds in the middle and upper parts of the Williams Fork Formation make correlation between wells tenuous, even at a 10 acre well spacing. Some intervals of thicker and amalgamated sandstones within the middle and upper Williams Fork Formation can be correlated across greater distances. To aid correlation and for 3D reservoir modelling, vertical lithology proportion curves were used to estimate stratigraphic trends and define the stratigraphic zonation within the reservoir interval. Object-based and indicator-based modelling methods have been applied to the same data and results from the models were compared. Results from the 3D modelling indicate that sandstone connectivity increases with net-to-gross ratio and, at lower net-to-gross ratios (<30%), differences exist in the cumulative volume of connected sandstone bodies between the indicator-and object-based lithology models. Therefore, the types of lithology-modelling methods used for lower net-to-gross ratio reservoir intervals are important.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Orocual field is located in northern Monagas State of Venezuela and is owned and operated by Petroleos de Venezuela, S.A. (PDVSA), the national oil company of Venezuela. This paper presents the results of the geological and geostatistical modeling aspects of an integrated study for the San Juan Reservoir in Orocual Field, Eastern Venezuela. The objective of this work was to establish a static model to be used in dynamic modeling to determine development potential, risk, and hydrocarbon reserves. Special interest exists in untested but highly prospective areas.A recently acquired 3-D seismic volume was integrated with a detailed core based sedimentology study used to define the depositional environment and facies connectivity. Based on this description, the San Juan Formation is subdivided into 3 major sedimentological units: Lower, Middle and Upper. A stochastic method was used to quantify model uncertainty.The fine grid geostatistical model was up-scaled to provide facies consistency for reservoir modeling. The prediction of heterogeneous fractured reservoir was added to the complexity. Numerical simulation was performed and will be discussed.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Orocual Field is made up of four structurally compartmentalized fault blocks. The upper two, San Juan 3 (SJ3) and San Juan 6 (SJ6) are more developed. The lower block structures, San Juan 7 (SJ7) and San Juan 9 (SJ9), are more than 1500 feet deeper and are separated by a major thrust fault. These reservoirs primarily consist of light condensate. Recent development suggests that significant potential exists in the SJ6 and SJ7 areas. The difficulty in defining the hydrocarbon column associated with each block, because of limited development, shows significant sensitivity in calculating oil reserves. The San Juan formation is a naturally fractured sandstone reservoir, and has historically produced low sustained rates of less than 1000 BOPD. New techniques in the area have been studied to increase sustained rates to at least 3000 BOPD.This project was designed to develop a method to analyze the probable results of a development program. A reservoir simulation model was constructed as part of an integrated study focused on geostatistics modeling of tight matrix and fracture systems to predict production by extending the proven area of the field. The producing areas have limited data, and previous studies did not consider the fractured nature of the reservoir. The application of geostatistical methods for reservoir characterization, and the use of simulation to assess the static model heterogeneity were identified objectives. The complex structure and fluid columns add to the uncertainty. Various sensitivities were run by applying different constraints to the permeability model, variance in fluid definitions, and well design.The reservoir simulation model shows sensitivity to matrix characterization and less to fracture characterization. This sensitivity is related to well productivity as a function of matrix permeability. The matrix is so tight that a multiple increase of permeability has little effect on well productivity. The permeability appears to be predominately from fractures. Fracture density or fracture permeability shows less effect to change well productivity than matrix permeability. Over 100 simulations were run to predict well and reservoir behavior. Results allow realistic assessment of risk in both reserves and production and to rank alternatives.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Orocual Field is made up of four structurally compartmentalized fault blocks. The upper two, San Juan 3 (SJ3) and San Juan 6 (SJ6) are more developed. The lower block structures, San Juan 7 (SJ7) and San Juan 9 (SJ9), are more than 1500 feet deeper and are separated by a major thrust fault. These reservoirs primarily consist of light condensate. Recent development suggests that significant potential exists in the SJ6 and SJ7 areas. The difficulty in defining the hydrocarbon column associated with each block, because of limited development, shows significant sensitivity in calculating oil reserves. The San Juan formation is a naturally fractured sandstone reservoir, and has historically produced low sustained rates of less than 1000 BOPD. New techniques in the area have been studied to increase sustained rates to at least 3000 BOPD.This project was designed to develop a method to analyze the probable results of a development program. A reservoir simulation model was constructed as part of an integrated study focused on geostatistics modeling of tight matrix and fracture systems to predict production by extending the proven area of the field. The producing areas have limited data, and previous studies did not consider the fractured nature of the reservoir. The application of geostatistical methods for reservoir characterization, and the use of simulation to assess the static model heterogeneity were identified objectives. The complex structure and fluid columns add to the uncertainty. Various sensitivities were run by applying different constraints to the permeability model, variance in fluid definitions, and well design.The reservoir simulation model shows sensitivity to matrix characterization and less to fracture characterization. This sensitivity is related to well productivity as a function of matrix permeability. The matrix is so tight that a multiple increase of permeability has little effect on well productivity. The permeability appears to be predominately from fractures. Fracture density or fracture permeability shows less effect to change well productivity than matrix permeability. Over 100 simulations were run to predict well and reservoir behavior. Results allow realistic assessment of risk in both reserves and production and to rank alternatives.
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