Determining Reservoir Fluid Properties from Unconventional Reservoir Core Analysis

Abstract Determination of reservoir fluid type for unconventional reservoirs is quite challenging but very important for reservoir development planning. This work presents a method for predicting the reservoir fluid formation volume factor, Bo and fluid type from routinely conducted core analyses. The proposed method utilizes the gas, oil, and water saturations measured from crushed core samples. The saturations represent the percentage of pore volume occupied by each fluid and are used to calculate the "Apparent formation volume factor" of reservoir fluid which, in turn, allows fluid classification as black oil, volatile oil, gas condensate, or gas. The analysis also allows calculation of important characteristics such as gas-oil ratio/condensate-gas ratio for the candidate reservoir fluid. To demonstrate the method, it was applied to various unconventional reservoir samples across several wells and reservoir intervals. Oil formation volume factor, solution gas oil ratio, and condensate gas ratio were calculated from experimental results and used to determine the reservoir fluid type. The predicted fluid types are compared to those observed from other industry standard methods. The workflow, equations, and evaluation criteria used are shared and results obtained from using fluid saturations from both the gas research institute (GRI) method and the mudrock reservoir properties (MRP) method were utilized to show the versatility of the methodology. The results demonstrate that the method offers an efficient approach for estimating reservoir fluid type, and gas-oil ratio/condensate-gas ratio using routinely available core analysis.