Detailed experimental data of the phase behavior of a rich gas displacing a Middle Eastern crude are given. These data include constant composition expansion, differential liberation, saturation pressure, and multiple contact PVT data as well as slim tube data at several pressures. The phase behavior of the reservoir oil / rich gas system was modelled using a cubic equation of state (EOS) with fifteen components. The critical properties of the heavy fractions, the binary interaction parameters and the volume translation parameters were adjusted by regression to match the experimental data. A good match of the experimental data was obtained. With the aid of pseudo-ternary diagrams and pressure-composition diagrams generated from the EOS the mechanism of oil recovery was interpreted as a condensing / vaporizing process with significant upper phase extraction (vaporization). The EOS fluid description was then utilized in a compositional simulator to model the experimental slim tube results. A good match of the experimental data was achieved by including the effect of interfacial tension (IFT) on relative permeabilities. Once the primary recovery mechanisms were identified, the fifteen components were reduced to six using the technique described by Nutakki et al1. The calculations using six components were almost identical to the calculations with 15 components for both the PVT and the slim tube data. The results clearly show that for a condensing / vaporizing process the traditional interpretation of slim tube recoveries is not valid. The break in the slim tube recovery curve with increasing pressure does not indicate multiple contact miscibility, but rather a region of reduced IFT. To model properly this behavior in a compositional simulator, the effect of interfacial tension on relative permeability must be accounted for. Because of the reduced IFT, it is possible to obtain high recovery even though the displacement process is not miscible.
This papr was selected fu presenfatlon by an SPE Program Committee follovdng review ol information cmnmined in an qbstmct submttfed by the author(s). Contents of bpqw, as presented, haw not be-m rwiewd by the Society of Petmlwm Enginews and am subjected tocomwtkm by the aulhor(s). The material, as pmented, dms nti necessarily mfkf any postin of tie .%cie(y of Petroleum Engineem, & ofiicam, of msmbws. Papers presented at SPE meetings are subject to publication review by ediir!al committees C4 the Sccidy of Petroleum EWinwrs Penn-to COPYis msbided toanabsbactdnd mom &wn3C0 wuds. Illushatk.ns mav not be caoied TM a-should ccmtain conso4cuous acknowledgment of'Aernandby W& the paper was -ad Write Libmri8n, @E, P.0, SOXS33S36, Rkhardson, TX 7ws3-3sw. U. S. A., fax 01-214-SS2-94SS. AbstractThis paper outlines the results of a reservoir characterization study conducted on the low quaIity, fkactured Mississippian limestones and dolomites in Waterton Sheet III, one of the largest gas fields in Camda, having an initial raw gas in place of approximately 100 billion cubic meters (BCM). Although average matrix porosity in the field is less than d~o, iNtia] Wi?l] pOkIIti~SOf greder than 1.2 MdhOSI cubic meterslday were not unusual.As part of this integrated study, data from well logs, cores, drilling and production records, pressure transient analyses, and resemoir engineering analyses were used to characterize the variations in fracture and matrix properties in the re,wvoir. The results of this characterization were utilized in a simulation study, deseribed in a subsequent paper'.Conventional, tectonically-induced fracture intensity was found to vary with lithology (dolomite vs. limestone) and structural position. However, such 'conventional' descriptions were inadequate to account for large, but highly variable drilling mud losses in some zones, variable productivities that did not correlate strictly to structural position, and estimatcxi volumes of initial-hydrocarbon-in-place.In several key zones, solution enhanced fractures or karst development is proposed to account for these variations. This hypothesis is consistent with pressure transient analyses of most wells. The presence of such high porosity/permeability volume elements within the overall flow network of the reservoir has a profound influence on field developmen~in terms of recovering additional gas and liquid condensate. As a result, dual porosi~models are required to diagnose dynamic reservoir behavior and investigate future development options.
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