This paper describes a three-dimensional (3D), three-phase, black-oil model being used to simulate naturally fractured reservoirs. The program is fully implicit and can perform single-porosity, dual-porosity, or dual-permeability computations. Sample simulations are presented to illustrate the differences between the three computational techniques. Single-porosity recoveries are much larger than the recoveries predicted by the dual techniques. The dual-permeability, primary-depletion recoveries are very similar to the dual-porosity, primary-depletion recoveries, while the dual-permeability waterflood recoveries are significantly larger than the dual-porosity waterflood recoveries.Pseudocapillary pressures are generated from fine-grid, single-matrix block studies. The pseudocapillary pressures are then used in the dual-porosity simulations to account for fluid distributions in the matrix and fracture systems.

SPE Members Abstract This paper examines the sensitivity to gridding of first-contact miscible and three-component multicontact miscible condensing-gas drive predictions made with an upstream differenced simulator. These cross-section simulations are made for various reservoir descriptions and for models of increasing numbers of grid blocks. The largest models range from 5000 to 24,000 grid blocks. The paper examines gridding sensitivity when the coefficients of convective terms are evaluated by the single-point upstream method, and it also examines the utility of two-point upstream weighting and selectively refined initial gridding for moderating gridding sensitivity. These simulations show the following behavior. For some problems with single-point upstream weighting, ultimate recovery changes monotonically with an increasing number of grid blocks. The change in recovery with increasing grid blocks can either be a decrease or an increase depending on the particular reservoir description, although decreasing recovery was the most common behavior for the reservoir descriptions examined here. Two-point upstream weighting and selectively refined initial gridding reduced, but didn't eliminate, this sensitivity. Some predictions appear to converge almost linearly with predictions appear to converge almost linearly with grid size to approximately the same answer in the limit of zero grid block size (i.e., infinite grid blocks) when the problem is worked in different ways, e.g., single-point weighting, two-point weighting, selectively refined initial gridding. Other problems, however, do not appear to be converging for the largest models that were feasible. Addition of physical diffusion/dispersion of a magnitude that might occur in reservoirs didn't affect the gridding sensitivity for two of the three reservoir descriptions examined, at least not for grid sizes that were feasible. However, for one reservoir description, recoveries computed with and without physical diffusion/dispersion appear to be diverging physical diffusion/dispersion appear to be diverging with grid refinement. Introduction Miscible flood predictions and designs are cormonlv made with finite-difference simulators in which the l (Ppxpikrp)/up coefficients of the convective terms are evaluated at the upstream grid block. It is well known that this single-point weighting -auses truncation error that results in sensitivity to grid block size. The truncation error from single-point upstream differencing causes an artificial dispersion! that in one-dimensional problems is equivalent to a physical dispersivity of magnitude Ax/2 and is physical dispersivity of magnitude Ax/2 and is qualitatively similar to physical dispersion in two-dimensional problems. As grid block size decreasesli the influence of this artificial dispersion decreases, i although in reservoir-scale problems, grid block sizei would have to be intractably small for this artificiall dispersion to be on the order of realistic physical dispersion. Also, with a five-point differencing scheme, such a formulation resuits in sensitivity to grid orientation as well as to the number of grid blocks. Young gives an example of gridding sensitivity for ani upstream differenced simulator and for a first-contact miscible, unfavorable mobility ratio, homogeneous, two-dimensional areal five-spot calculation. He used a nine-point difference approximation to reduce gridi orientation sensitivity but with single-point upstreami weighting and with no physical dispersion. He shows that as grid size decreases, recovery decreases monotonically, and an unchanging answer is not approached. He concludes that in the absence of physical dispersion, the problem is not well posed andl physical dispersion, the problem is not well posed andl such a result is not unreasonable. In Young's problem the influence of gravity is not a factor. P. 59

The Hassi Berkine South (HBNS) field is an undersaturated, low-viscosity, moderate permeability oil field within the center of the Berkine Basin in Algeria (Fig 1). Discovered in January 1995, the HBNS field had first oil production in 1998 from the Trias Argilo-Greseux Inferieur (TAGI) reservoir with a reservoir development plan (RDP) of crestal, miscible gas injection and peripheral waterflood. Full-field water-alternating-gas (WAG), as a secondary recovery process, is currently under investigation for the potential increased oil recovery and higher oil rate. A 14-month miscible water-alternating-gas (MWAG) pilot program successfully provided valuable information for reservoir simulation. This paper describes the application of WAG pilot results in reservoir simulation and the use of the novel miscible interpretation of the Reservoir Saturation Tool (RST) in history matching the observation well data. A fine-grid simulator sector model was used to simulate the WAG pilot program. The pilot observation well data were used to fine tune the reservoir model and establish the criteria for the realistic simulation tool for the full-field WAG evaluation. The technique for correcting observation well-log data to reflect the miscible displacement process was needed to history match the hydrocarbon saturations. The simulations also examined the impact of various reservoir description assumptions on predicted solvent and water behavior at the observation well. Minimum vertical layering requirement was also investigated for realistic WAG simulation. Introduction WAG injection processes have been accepted as a viable Improved Oil Recovery (IOR) technique1. Because of the complexity associated with the WAG process, a pilot program is often implemented before any large-scale application is undertaken2,3,4,5. This paper reviews the field measurements of two MWAG cycles in a WAG pilot within HBNS field and the analysis of these data using reservoir simulation. Proper analysis of miscible processes occurring in the observation well requires understanding of both the phase behavior of hydrocarbons (HC) as well as the interpretation of the fluid distribution. Between 1983 and 1987, an observation well pilot test was conducted in the Prudhoe Bay Flow Station 3 area4. The epithermal neutron log was used in the observation well DS 13–98 for the hydrocarbon saturation measurements. The miscible interpretation was based on static altered oil and altered gas compositions from the equation of state (EOS) simulations. The use of the static altered oil and altered gas compositions for HC saturation interpretation could result in ~50% error in the area that had not been sweeped by the solvent. This interpretation also led to an undesirable mingling of errors inherent in both the measured and simulation results. The standard log-derived HC saturations have been recognized as an immiscible interpretation5 and do not represent the miscible process. These HC saturations are based on static (constant fluid properties in time and space) conditions and need to be corrected to represent the true fluid displacement (miscible) process. Corrections are needed to relate the simulation results to the field measurements and to understand the process occurring within the reservoir. The WAG pilot design and the development of the miscible interpretation of the RST measurements were documented previously5. The geological model, the reservoir sector model, and the miscible interpretation of the RST measurements have been summarized in this paper for completeness.

The Hassi Berkine South field (HBNS) is an undersaturated, low-viscosity, moderate permeability oil field within the center of the Berkine Basin in Algeria (Fig. 1). Discovered in January 1995, the HBNS field had first oil production in 1998 from the Trias Argilo-Greseux Inferieur (TAGI) reservoir with a reservoir development plan (RDP) of crestal, miscible gas injection and peripheral waterflood. Full-field WAG, as a secondary recovery process, is currently under investigation for the potential increased oil recovery and higher oil rate. This paper describes the design of the miscible water alternating gas (MWAG) pilot test and presents novel techniques for correcting observation well log data to reflect the miscible displacement process. A simulator sector model for the pilot area was used to design the MWAG pilot parameters (e.g., solvent/water volume, WAG ratio, timing). Next, measurements from the first WAG cycle were used to calibrate key parameters in the sector model, and to define WAG parameters for subsequent cycles. For the initial pilot design analysis, the fine areal gridding and vertical layering were taken from the Prudhoe Bay pilot simulation experience1,2. The objective of the pilot design is to collect optimal data from the observation well in the shortest possible time. The initial simulation work defined solvent injection rates, slug sizes, cycle lengths, and WAG ratios to achieve these goals. Subsequently, reservoir calibration with surveillance measurements from the first WAG cycle allowed for fine-tuning of key MWAG parameters. This work required correcting hydrocarbon saturations from the surveillance tools to be representative of the miscible displacement process. A method has been developed to correct log-derived immiscible saturations to reflect the miscible process occurring in the reservoir and simulated in the sector model. Introduction An observation-well pilot test was conducted in the HBNS field (Fig. 2) to evaluate the benefit of MWAG as a secondary recovery process. This area of the field has had no water or gas encroachment, but the reservoir pressure has dropped about 75 bars from initial conditions. The current RDP of crestal gas miscible injection and peripheral waterflood allows for a simple transition to MWAG. This pilot is part of a staged development for full-field WAG in the HBNS field. The key advantage of MWAG3,4 over the current RDP is improved utilization of the solvent (contacts more oil) with less available solvent supply leading to improved ultimate oil recovery at a higher oil rate. Careful design in the WAG pilot program is critical to ensure that data collected in the observation well can be used successfully in tuning the simulator5. Three parameters (solvent slug size, cycle length, and WAG ratio) are controlled in the WAG pilot design. The WAG parameters are scaled to ensure the oil saturation change can be measured over a defined period of time at the observation well. In addition, dynamic and gravity forces in the pilot area must be representative of what is occurring between the wells during full-field WAG implementation. Injection rates too high will displace the oil faster than can be measured. Injection rates too low will allow for gravity segregation to occur too quickly and may change the vertical proportion of injected fluid. The usefulness of the WAG pilot diminishes as the moveable oil between the injector and the observation well decreases. Reservoir simulation was used to determine the initial WAG parameters and to history match the first cycle of the WAG. The simulator sector model was defined for the pilot area with a detailed geocellular geologic model. Boundary conditions for the sector model were taken from a history-matched, full-field reservoir model. Data from Reservoir Saturation Tool (RST) and Cased Hole Formation Resistivity Tool (CHFR) were measured regularly at the observation well to monitor water and gas saturations vs. depth as first solvent and then alternate water and solvent slugs were injected.