TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractOur chemical flooding simulator UTCHEM has been under development for many years and continues to evolve as a general purpose chemical simulator. We have extended the capability of this simulator to process advanced oil recovery methods which use surfactant, polymers, gels, alkaline chemicals, foam, and microorganisms as well as various combinations of these. We have developed and implemented a multiphase and multicomponent dual porosity model so in addition to targeting conventional oil reservoirs, the use of chemical methods in naturally fractured oil reservoirs can be evaluated. The model includes complex chemical phenomena previously modeled with UTCHEM for both fracture and matrix, e.g. the effects of reduced interfacial tension on phase trapping, surfactant adsorption, and so forth. In this paper we only discuss the dual porosity, foam, and microbial enhanced oil recovery models recently developed and implemented in UTCHEM. Model Description and ValidationDual Porosity Model. Discovery and development of naturally fractured reservoirs has increased dramatically during the past 15 years. Many oil reservoirs in the United States are naturally fractured. More than 20 billion barrels of oil remain in large Texas fields such as the Spraberry, 4-6 Yates, 7-9 and Ellenberger fields 10,11 but relatively little research has been done on the use of advanced oil recovery methods. In addition, very little success has been achieved in increasing the oil production from these complex reservoirs. The use of chemical methods of improved oil recovery from naturally fractured reservoirs has been particularly neglected. Some laboratory experiments have been done to investigate the use of surfactants in fractured chalk. 12-15 However, the results of these studies are hard to interpret and to apply to field-scale predictions without a model that takes into account both the fluid flow and chemical phenomena in both fractures and rock matrix. The most efficient approach to modeling naturally fractured reservoirs appears to be the dual-porosity model, first proposed by Barenblatt et al. 16 and introduced to the petroleum industry by Warren and Root. 3 The dual-porosity model assumes that two equivalent continuous porous media are superimposed: one for fractures and another for the intervening rock matrix. A mass balance for each of the media yields two continuity equations that are connected by so-called transfer functions that characterize flow between matrix blocks and fractures. Since Kazemi et al. 17 introduced the first multiphase dual-porosity model, almost all subsequent dual-porosity models have been based on modifications of the transfer functions.These transfer functions are what distinguish various dual porosity models in the literature.The formulation and details of the multiphase, multicomponent, dual porosity model to simulate the performance of reservoirs that are naturally fractured are discussed in Pope et al. 18 The dual porosity model in UTCHEM adds additiona...

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TX 75083-3836, U.S.A., fax 01-972-952-9435.Abstract CO 2 mixed with NGL is being evaluated as a method to enhance viscous oil recovery from Schrader Bluff and other oil reservoirs at Milne Point, Alaska. The sequestration of CO 2 is a secondary objective of these proposed projects. Mixtures of CO 2 and NGL with the crude oil show a large three-phase liquid-liquid-gas region, so three and four-phase flow may occur in the reservoir when water is alternated with the miscible injectant. A compositional EOS simulator has been used to simulate the oil recovery for both three-phase and four-phase flow cases. The objective was to understand how important it is to simulate four-phase flow rather than use a three-phase flow approximation. Two methods were used to model three and four-phase relative permeabilities from twophase relative permeabilities as well as to evaluate the sensitivity of the results to the relative permeability parameters. A two-dimensional vertical cross-section of the reservoir was modeled with a stochastic permeability field to approximate heterogeneities. These simulations clearly show that under these conditions, four-phase flow is significant. Four-phase flow occurs over a significant part of the reservoir and affects both the sweep efficiency and the injection and production rates when the wells are pressure constrained and the production pressure corresponds to the three-phase region of the phase diagram. The results are also very sensitive to the relative permeability parameters regardless of which relative permeability model is assumed. The project life is particularly sensitive to the relative permeability and is longer for fourphase flow than predicted by a three-phase flow approximation because the relative permeability of each phase is lower when four phases are modeled.

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