Mark B. Thomas, 1991. "Basin History and Diagenetic Evolution of the Missisauga Formation, South Sable Basin—Offshore Nova Scotia—A Petrographic and Petrophysical Approach", 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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The Lower Cretaceous Missisauga sandstones, which form part of a major southward-prograding delta system, are the principal reservoir units in the South Sable Basin (Figure 1). In Missisauga sandstones of similar lithology and burial depth, porosity values are highly variable ranging from 12% in the Glenelg wells (3500 m) to over 20% in North Triumph (3850 m). Variations in porosity and the occurrence of porous and permeable rocks at depth can result from geopressuring, early hydrocarbon migration into the reservoir, and/or-the dissolution of a specific component or components in the rock.
To investigate porosity occurrence as a function of geopressuring, pressure-depth plots, as well as plots of shale interval transit time (ITT) versus depth were constructed. From these plots it is evident that hydropressuring exists from surface to the base of the Missisauga Formation. This study excludes deeper geopressured regions such as the Venture gas field. Petrographic examination of the Missisauga sandstones revealed that in the poorer quality reservoirs much of the primary porosity was destroyed by the combined effects of compaction and silica cementation, while some secondary porosity resulted from the dissolution of-feldspars and rock fragments. In the more porous and permeable sandstones the pore system resulted from the dissolution of a pervasive, texturally early ferroan calcite cement. The creation of porous reservoir units through a similar dissolution process has also been observed in sandstones from other areas such as the North Sea, offshore Newfoundland and Mesozoic reservoirs in Alberta. The porosity in these reservoirs depends not only on
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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.