Evaluating the Challenges in Pressure – Volume – Temperature (PVT) Analysis of Gas Condensate Reservoirs

Aims: The variations in production performances of the Black oil and compositional simulation models can be evaluated by simulating oil formation volume factor (Bo), gas formation volume factor (Bg), gas-oil ratio (Rs) and volatilized oil-gas ratio (Rv). The accuracy of these two models could be assessed. Methodology: To achieve this objective some basic parameters were keyed into matrix laboratory (MATLAB) using the symbolic mathematical toolbox to obtain accurate Pressure Volume Temperature (PVT) properties which were used in a production and systems analysis software to generate the production performance and hydrocarbon recovery estimation. Standard black oil PVT properties for a gas condensate reservoir was simulated by performing a series of flash calculations based on compositional modeling of the gas condensate fluid at the prescribed conditions through a constant volume depletion (CVD) path. These series of calculations will be carried out using the symbolic math toolbox. PVT property values obtained from both compositional modeling and black oil PVT prediction algorithm are incorporated to determine the production performance of each method for comparison. Results: The absolute open flow for the black oil PVT algorithm and the compositional model for the Rs value of 500 SCF/STB and Rs value of 720SCF/STB were 130,461 stb/d and 146,028 stb/d respectively showing a 10.66% incremental flow rate. Conclusion: In analyzing PVT properties for complex systems such as gas condensate reservoirs, the use of compositional modeling should be practiced. This will ensure accurate prediction of the reservoir fluid properties.

Compositional Modeling of Carbonate Acidizing Processes with CO2 Evolution in Aqueous Environments

Summary Several modeling studies have been conducted in carbonate acidizing, particularly in the area of aqueous environments. Yet, complete understanding of this complex subsurface process remains elusive. Characterizing the effects of evolved CO2, a product of the chemical reaction between carbonates and HCl (hydrochloric acid), has been ignored to date under the assumption that high operating pore pressures keep CO2 completely dissolved in the surrounding solution. However, the presence of CO2 in the porous media of the formation itself changes fluid-flow dynamics throughout the entire system. This paper describes a numerical simulation study to accurately model the physics of carbonate acidizing. A validation of the model is conducted by replicating experiments described in the published literature and by performing laboratory coreflood experiments of carbonate acidizing. The acid efficiency curve and initial pore pressure variations for single-phase experimental studies from the literature is matched by including the effects of evolved CO2 in the model. Two Indiana limestone cores of 6 in. length and 1.5 in. diameter were used to conduct (1) a tracer-injection study with 5 wt% KCl (potassium chloride) solution and (2) an acid-injection study with 15 wt% HCl solution. The experiments were conducted at 72°F, and 1,180 psi pore pressure. The Indiana limestone cores were characterized via computed tomography (CT) scans, and a detailed, accurate porosity profile of each core was used as input to the numerical model. The tracer fluid was used to characterize the porous environment and mechanical dispersion coefficients, and for subsequent calibration of the simulation model. From the conducted single-phase acidizing coreflood experiment, pressure drop values across the core were closely monitored with time to assess acid breakthrough, and the core effluent samples were collected at regular intervals and analyzed to determine the concentrations of calcium chloride (CaCl2) and HCl. CT scans of each core conducted post-acidizing describe its wormhole pattern. These parameters are accurately matched using the simulation model. A high pore pressure of 1,000 psi and above is not sufficient to keep all the evolved CO2 in solution during carbonate acidizing. The presence of CO2 as a separate phase hinders acid efficiency. Up to 24% by volume of pore space is shown to be occupied by the evolved CO2 that exists as a separate phase, and is located ahead of the acid front during the acidizing process, thus competing for flow with the incoming acid. The modeling of CO2 as a component for simulating the acid coreflood played a key role in acquiring a better match with experimental results, with limited dependency on empirical pore-scale parameters. In addition to wormhole propagation, the current model accurately forecasts effluent concentrations collected and quantity of rock dissolved from the acidized porous media. A new approach to accurately predict carbonate acidizing in porous media for an aqueous environment has been presented via compositional modeling using a reservoir simulator. The presented methodology can be incorporated in large field scale reservoir models.