Vertical Seismic Profile Applications for Definition of Reservoir Heterogeneity—South Texas, Vicksburg and Frio Sandstones: A Secondary Gas Recovery Project
S. G. Zinke, L. A. Jirik, R. P. Langford, R. J. Finley, 1991. "Vertical Seismic Profile Applications for Definition of Reservoir Heterogeneity—South Texas, Vicksburg and Frio Sandstones: A Secondary Gas Recovery Project", The Integration of Geology, Geophysics, Petrophysics and Petroleum Engineering in Reservoir Delineation, Description and Management, Robert Sneider, Wulf Massell, Rob Mathis, Dennis Loren, Paul Wichmann
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Approaches to defining the distribution of unrecovered natural gas resources in mature fields are being developed and tested as part of the Secondary Gas Recovery Project, a program supported by the Gas Research Institute, the U.S. Department of Energy, and the State of Texas. The study emphasizes integrated geological, geophysical, petrophysical and engineering assessments of potential reservoir compartmentalization. Selected clastic reservoirs in South Texas have been studied in cooperation with Mobil Exploration and Producing U.S., Inc., Oryx Energy Company, and Shell Oil Company. Vertical seismic profiles (VSP's) have been used to help delineate reservoir sandstones and define structural complexities.
Gas reservoirs of the middle Frio Formation (Oligocene) along the Vicksburg fault zone at Seeligson field (Jim Wells County) consist of fluvial, channel-fill and associated splay sandstones that can be identified using well log correlation and facies analysis. Floodplain and levee mudstones vertically and laterally separate the reservoirs. Production and pressure data confirm lateral reservoir discontinuities. Offset VSP's, having close (30 ft) geophone stations, allow resolution of boundaries of composite channel systems defined using log data. Multi-offset VSP's providing continuous interwell coverage were utilized to interpret fluvial channel boundaries in the 19C-04 reservoir. Forward modelling corroborates the interpretations.
McAllen Ranch field (Hidalgo County) produces from overpressured deltaic reservoirs of the Oligocene Vicksburg Formation. Shingled, southeastward-tapering wedges of the Vicksburg depositionally overlie a basal decollement of the Vicksburg growth fault zone, resulting in complex interplay between sedimentation and tectonism. Gas production is from the shelf-edge, deltaic sandstone packages within the lower Vicksburg.
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The Integration of Geology, Geophysics, Petrophysics and Petroleum Engineering in Reservoir Delineation, Description and Management
Bima Field, offshore northwest Java, is a sizeable reservoir containing reserves of approximately 700 MM bbls OOIP with a 50 BCF gas cap. At present only the northern 1/3 of the field is developed, with 7 platforms and 54 producing wells, of which 20 are horizontal. The field has multiple drive mechanisms and high viscosity oil (21 cp), resulting in rapid GOR and water-cut increase after 3 years of production. The high stakes (both reserves and facility investments) and the reservoir's complexities, make an effective reservoir management scheme critical. For this reason an integrated geological, geophysical and engineering description was carried out to provide a 3-D Reservoir Simulation Model to evaluate development options. Geologically, the Oligo-Miocene age Batu Raja Limestone was deposited on the Seribu Platform, a basement-controlled, fault- bounded structure. The Upper Batu Raja carbonate build-up is thickest on the structurally highest parts of the platform where the rock comprises a series of "cleaning upwards" cycles (muddy deposits overlain by progressively more grain-rich sediments). A Lower Miocene drop in sea-level caused subaerial exposure of much of the platform and leaching by meteoric fluids. This diagenetic event resulted in contrasts in the reservoir quality (porosity, permeability, fluid saturations) at various intervals of the Upper Batu Raja. Based on these dissimilarities, the reservoir was zoned into 6 model layers. Once zonation was established, well logs could be calibrated to whole and sidewall core. A dense grid of seismic data were used to map the Batu Raja structure. From these data, color seismic inversion sections were produced and calibrated to the well logs. The calibrated seismic data were then used to map the top of structure, the carbonate build-up's edges, the total thickness of the Upper Batu Raja (needed to control aquifer size in the model) and the thickness of the main pay zone (layers 1-3). Engineering reservoir description began with a detailed compilation of capillary pressure, relative permeability, production and DST data. The 3-D simulation model required special treatments, including varying the GOC depths to honor separate gas cap closures; making permeability pressure dependent in poorly-consolidated zones; and setting up horizontal well completion treatments. Results suggest that water injection into the oil rim and gas cap is an effective approach toward maximizing recoveries and minimizing gas cap resaturation. However, waterflood reserves are sensitive to injection timing. The synergistic approach of geological, engineering and geophysical input into the Bima reservoir study has had impact by delivering a reservoir management tool that can evaluate future development expansion and possible gas sales. The simulation model can also track fluid migration during the field's producing life. The geological/geophysical model led to an enhanced understanding of Batu Raja depositional and diagenetic processes that has potential in regional exploration strategies.