The Archie Approach to Characterizing Carbonate Reservoirs
Published:January 01, 1991
F. Jerry Lucia, D. G. Bebout, C. Kerans, 1991. "The Archie Approach to Characterizing Carbonate Reservoirs", 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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Modem methods of characterizing carbonate reservoirs include geologic and engineering studies of various types and at a range of scales, all focused on describing the volume and distribution of oil and gas saturation and the flow characteristics of the reservoir. Such activities include (1) constructing the geologic reservoir framework at the sequence scale, (2) making detailed facies maps at the parasequence scale, (3) analyzing petrophysical data through integration of rock-fabric, facies, porosity, permeability, and water saturation, (4) mapping petrophysical parameters, (5) interpolating deterministic data between wells using geostatistical methods, (6) analyzing production data, and (7) inputting data into computer flow simulators for performance evaluation.
In 1952, G. E. Archie published a landmark paper showing that petrophysical properties can be related to rock textures. Although this relationship forms a fundamental basis for all reservoir characterization studies, it is often overlooked, resulting in beautiful geologic reservoir descriptions that cannot be converted into engineering parameters or in exquisite engineering studies that defy geologic understanding. This is particularly true in carbonate reservoirs, where correlations are uncertain, pore geometries complex, and log analysis perplexing.
Research on several carbonate fields in the Permian Basin and published datafrom fields in other basins and from other geologic ages, have shown the significant rock-fabric parameters for carbonate reservoir characterization to be (1) size and sorting of depositional and diagenetic particles, (2) volume of interparticle pore space, (3) volume of separate-vug pore space, and (4) presence or absence of touching-vug porosity. The three-dimensional spatial distribution of these four parameters together
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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.