Experimental Evaluation of the Effect of Carbonate Heterogeneity on Oil Recovery to Water and Gas Injections (2013)

The natural structural variations in petroleum carbonate reservoirs often dictate the best displacement strategy and always impact the ultimate recovery. Quantifying the impact of these structural heterogeneities can ultimately guide reservoir performance optimization techniques such as well placement and can reduce the uncertainty in reserve calculations. Nuclear Magnetic Resonance (NMR) and Computerized Tomography (CT) were used to build on previous work and add mechanistic information that in the past has been unattainable. This study investigates the effect of moderate carbonate heterogeneity on oil recovery from immiscible N2 gas injection. Initially, the variations of porosity and permeability within the scale of a core plug sample using NMR and CT are charactrized. The results from visually classifying 51 core samples showed that the samples can be classified into three main heterogeneity groups: low rock heterogeneity (LRH), moderate rock heterogeneity (MRH), and high rock heterogeneity (HRH). Additional rock characterization was conducted including wettability, mercury injection, and petrographic image analysis. The results indicated intermediate wetting system, various pore size distributions, and complex diagenetic process, respectively. A new permeability-predictor correlation was established, by linking the Kozeny-Carman (K-C) empirical correlation with the NMR total surface area of pores, and it was verified using the selected samples. The results showed a good match between the measured and predicted permeabilities, suggesting that the pore connectivity in these specific rocks may not be critical to capillary based recovery processes. Based on the rock heterogeneity classification results, centrifuge and gasflood experiments were carried out. The centrifuge experiments, performed at 80oC, were conducted on nine core samples. The gasflood experiments were performed on nine core stacks, in which six runs were conducted at 80oC and a pore-pressure of 1034 kPa while three runs were performed at 80oC and a pore-pressure of 17237 kPa. Five of the low pore-pressure’s (LPP) experiments were conducted in secondary recovery mode while one run was performed in tertiary recovery mode. Three of the high pore-pressure’s (HPP) gasfloods were conducted in secondary recovery mode. All of the gas-oil displacement experiments were carried out to evaluate the effect of single-and multi-rock heterogeneities on oil recovery. The results from the centrifuge experiments suggested that oil recovery is generally less sensitive to rock heterogeneity under favourable gravity drainage conditions. On the other hand, oil recovery from the LPP gasfloods showed a monotonic trend with rock heterogeneity. The LRH rocks showed the highest oil recovery (41.94% OOIP) while the HRH rocks showed the lowest oil recovery (29.33% OOIP). The oil recovery from the multi-rock heterogeneity showed outstanding results (47.82% OOIP) as compared to the LRH, MRH, and HRH results (41.94%, 34.02%, and 29.33% of OOIP, respectively). The results from the high pore-pressure’s (HPP) runs showed almost similar oil recovery trend with rock heterogeneity to that from the LPP gasfloods. The injection of water as a secondary recovery process resulted in higher oil recovery (64.78% OOIP) than all secondary gasfloods. Injecting N2 gas in tertiary mode resulted in similar recovery to the MIRH secondary mode (34.80% ROIP vs. 34.02% OOIP). However, if the waterflood recovery (prior to N2) is considered, the ultimate recovery of the tertiary mode is much higher at a later time. The combined recovery from waterflood and gasflood (tertiary) is found to be 83.23% of OOIP. These results suggest that implementing secondary waterflooding and tertiary gas injection in the actual reservoir could be very beneficial. A lab simulator was used to history match the results from secondary gasfloods in order to estimate the “true” oil recovery. It was found that the HRH rocks were highly affected by capillary end-effect as compared to the MRH rocks. The corrected oil recovery for the HRH rocks was higher than the MRH rocks leading to the conclusion that the HRH may not be harmful rock heterogeneity to the capillary number based recovery process.