Reservoir Geology of the Taylor Sandstone in the Oak Hill Field, Rusk County, Texas: Integration of Petrology, Sedimentology, and Log Analysis for Delineation of Reservoir Quality in a Tight Gas Sand
C. L. Vavra, M. H. Scheihing, J. D. Klein, 1991. "Reservoir Geology of the Taylor Sandstone in the Oak Hill Field, Rusk County, Texas: Integration of Petrology, Sedimentology, and Log Analysis for Delineation of Reservoir Quality in a Tight Gas Sand", 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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This case history deals with the delineation of reservoir quality in a tight gas sand, the Taylor Sandstone (Cotton Valley Group—Upper Jurassic) in Rusk County, Texas. The purpose of the study was to determine the geologic controls on reservoir performance and to provide a wireline log model of net pay for reserve calculations. This study was based on petrologic and sedimentologic analysis of five cored wells, and log analysis of 118 wells.
The Taylor interval consists of tightly cemented, very fine- to fine-grained quartzose sandstones interbedded with mudstones, siltstones and carbonates. Matrix porosity and permeability are quite low, even for tight gas sands: helium permeability rarely exceeds 0.1 md, and porosity is typically less than 10 percent. Cores examined to date appear virtually devoid of open natural fractures.
Six major rock types or petrofacies can be distinguished based on petrographic criteria. Each petrofacies is characterized by a unique combination of dominant pore geometry (pore size, shape, sorting and interconnectivity) and pore-filling mineralogy. Of the six petrofacies identified, three have reservoir potential: (1) Primary Macroporous Quartz-cemented, (2) Moldic Macroporous Quartz- cemented and (3) Microporous Clay-cemented. The Primary Macroporous Quartz-cemented Petrofacies is characterized by quartz-cemented sandstone with primary macropores interconnected by slot-like pore throats. This petrofacies has the highest reservoir quality. The Moldic Macroporous Quartz-cemented Petrofacies is characterized by virtually isolated secondary pores (molds) in quartz-cemented sandstone. Reservoir quality is intermediate. The Microporous Clay-cemented Petrofacies is characterized by sandstones with abundant clay cement and a pore geometry dominated by microporosity. This pore geometry results in the lowest reservoir quality of the reservoir petrofacies.
A wireline log model to calculate porosity was based on a shale-corrected neutron- density cross-plot solution, with corrections applied for matrix and calibration errors. The porosity model included identification of macroporous, microporous, and nonreservoir petrofacies based on the calculated porosity and Vshale. Different grain densities were used for each petrofacies, thus requiring an iterative solution. Water saturation calculations were carried out using Archie’s equation with laboratory-determined coefficients a, m, and n.
Petrofacies types show a strong association with depositional environment, even though the primary pore network has been strongly altered by diagenesis. The depositional environment interpreted for the Taylor sandstone bodies is a barrier island with back-barrier, foreshore, shoreface and inner shelf sub-environments. Two such barrier island complexes are present in the Oak Hill Field. The Primary Macroporous Petrofacies is associated with clean, well-winnowed sandstones comprising foreshore and tidal channel/delta environments. The Moldic Macroporous Petrofacies occurs in upper shoreface and some back-barrier sandstones. The Microporous Petrofacies is associated with clay-rich, more poorly sorted, generally bioturbated sandstones that comprise lower shoreface, inner shelf and some back-barrierllagoonal sandstones.
The Taylor interval was subdivided into correlative zones and sub-zones based on unconformities and sedimentological sequences observed in core that identified major sandstone bodies within the stratigraphic interval. This, combined with the wireline petrofacies model, permitted mapping and tracing petrofacies around the field. This information permitted the recognition of stratigraphic and geographic zones of good and intermediate .reservoir quality (primary and moldic macroporosity) associated with foreshore, upper shoreface and tidal channel facies and its relationship to zones of poorer quality (microporous) reservoir rocks associated with lower shoreface, inner shelf and various back-barrier facies.
This study demonstrates the utility of an integrated petrologic, sedimentologic and wireline log analysis study in identifying the controls on reservoir quality at the pore level and extending this understanding to the interwell and fieldwide scale via a depositional model and log analysis.
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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.