No abstract

We have performed a miscible CO 2 flood study using fractured and unfractured carbonate cores and 31° API west Texas oil to evaluate oil recovery under three main injection modes: SWAG, WAG, and CGI. For each injection mode, three cases were considered: unfractured, one horizontal fracture and two fractures (one horizontal and one vertical). Increasing the number of fractures will investigate different shape factors such as the elongated slab and sugar cube models. Then, a commercial simulator was used to match the experimental results and model the fractures. The experimental results may be summarized as follows. First, for the unfractured case, the oil recoveries for SWAG, WAG, and CGI are 98, 92, and 75 % of OOIP, respectively. Second, for the elongated slab case (one horizontal fracture), the oil recoveries for SWAG, WAG and CGI decreased to 72, 70, and 27 %, respectively. Third, for sugar cube model (two fractures), the oil recoveries for SWAG, WAG and CGI are 79, 79, and 55 %, respectively. The simulation shows that the improvement in recoveries during SWAG and WAG over CGI is a result of a better conformance provided by the injected water which hindered CO 2 mobility and decreased its cycling through the fracture. Also, the sugar cube model has shown better results than the elongated slab because of the presence of a vertical fracture in the middle which helped CO 2 to diffuse more in the matrix and contact oil. The results suggest that injecting CGI in fractured cases is not recommended and injecting water (wetting phase) along with CO 2 is essential. Finally, among all injection modes, SWAG has resulted in the most uniform displacement profile with the lowest residual oil saturation after the flood. This injection mode combines the benefits of water to transfer into the matrix with CO 2 excellent displacement.

While enhanced oil recovery using carbon dioxide (CO2-EOR) is a mature technology and known to concurrently store large volumes of CO2, it is not currently viewed by industry as a CO2 storage process. Application of CO2-EOR for CO2 storage to reduce anthropogenic CO2 emissions 1) enables carbon capture and storage (CCS) technology improvement and cost reduction; 2) improves the business case for CCS demonstration and early movers; 3) supports the development of CO2 transportation networks; 4) may provide significant CO2 storage capacity in the short-to-medium-term, particularly if residual oil zones (ROZ) are produced and hybrid CO2-EOR/CCS operations are considered; 5) enables knowledge transfer; and 6) it helps gaining public and policy-makers acceptance. Although there are a number of commonalities between CO2-EOR and pure CO2 storage operations, currently there are a significant number of differences between the two types of operations that can be grouped in five broad categories: 1) operational; 2) objectives and economics, including CO2 supply, demand and purity; 3) legal and regulatory; 4) long term CO2 monitoring requirements; and 5) industry's experience. There are no specific technological barriers or challenges per se in adapting or converting a pure CO2-EOR operation into a CO2 concurrent or exclusive storage operation. The main differences between the two types of operations stem from legal, regulatory and economic differences between the two. The legal and regulatory framework for CO2 storage is being refined and is still evolving and it is clear that CO2 storage operations will likely require more monitoring and reporting. Because of this, CO2 storage will impose additional costs on the operator. A challenge for existing CO2-EOR operations which may, in the future, adapt to concurrent or exclusive CO2 storage operations is the lack of baseline data for monitoring, except for wellhead and production monitoring for which there is a wealth of data. Thus, in order to facilitate the transition of a pure CO2-EOR operation to concurrent or exclusive CO2 storage, operators and policy makers have to address a series of legal, regulatory and economic issues in the absence of which this transition cannot take place.

Enriching the injection water with CO2 has demonstrated promising results as a method for improving oil recoveries and securely storing CO2 in oil reservoirs. However, the mutual interactions taking place between carbonated water and reservoir oil at elevated reservoir conditions are not fully understood. Here we present the results of a thorough investigation of the processes leading to additional oil recovery through integrating pore-scale visualisations and coreflood experiments. Four pore-scale visualization (micromodel) experiments were performed at reservoir conditions using the recombined live oil under different injection scenarios (tertiary and secondary). Having identified the underlying dynamic interactions at pore-scales, the performance of different injection scenarios for carbonated water injection (CWI) was investigated using carbonate reservoir rocks. Five coreflood experiments were carried out using both fully and half-saturated carbonated water to sensitise the impact of CO2 content of injection water on the performance of CWI. In-situ liberation of gaseous phase was identified (from direct visualisations) as the predominant mechanism controlling the performance of carbonated water injection. The gas phase formation would bring about higher degrees of oil swelling, and it would also create a three phase flow regime which leads to further reduction of residual oil saturation. The observations confirm that the performance of CWI should be investigated under reservoir conditions using multi-components live oil and reservoir cores. Any simplification, e.g. one components make-up gas or reduced pressure/temperature, of the reservoir conditions would misleadingly change the pore-scale event and hence, the performance of CWI. From the core displacement tests, it was observed that secondary CWI could recover a significant amount of additional oil, which was 26% compared to plain seawater injection. The tertiary carbonated water would effectively mobilise 15.3% of the residual oil (after seawater injection). When CO2 content of injected CW (carbonated water) was halved, the oil recovery dropped by 13. The results revealed that the oil recovery would be lower if CO2 concentration is reduced but the extent of oil recovery reduction would be much less than the level of reduction in CO2 concentration. The unique and integrated research approach employed here enables us to produce a more complete and reliable set of findings and understandings at realistic reservoir conditions. During CWI under reservoir conditions, an "in-situ WAG-type" three-phase flow would be generated with more effective sweep efficiency and pore-scale advantages.

We have conducted a miscible CO 2 flood using carbonate cores and 31° API west Texas oil under four injection modes: simultaneous water and CO 2 (SWACO 2 ), water alternating CO 2 (WACO 2 ), continuous gas injection (CGI), and waterflood (WF). Then, a pseudo-miscible black oil simulator was used to match the experimental results. The matched simulation model was extended to conduct a sensitivity study on permeability variation in the core, WACO 2 ratio and slug size, and SWACO 2 ratio. Three permeability values were chosen to represent a flow barrier, average matrix permeability, and high permeability streak. These values were arranged to represent a layered reservoir and then aligned in series to represent a sequenced reservoir. The four injection modes were conducted in all six permutations of these three values in both the layered and sequenced arrangements. The oil recovery from the coreflood experiments was measured to be 90, 86, 75, and 54 % of OIIP for SWACO 2 , WACO 2 , CGI, and WF, respectively. The simulation results may be summarized as follows: for all injection modes during the layered permeability arrangements, the best oil recovery was obtained when the flow barrier is in the middle of the core. Conversely, lower recoveries were obtained when the barrier was not in the middle and the high permeability was located at the top with significant decrease in oil recovery (up to 40%). In sequenced reservoirs, each injection mode showed different preference to the permeability arrangements. For example, CGI showed higher recovery (5% increase) when the low permeability is near the outlet which allowed for more controlled displacement but with high differential pressure across the core. The WACO 2 ratio study in the homogenous (base) case showed that a 1:2 ratio had the highest oil recovery but the optimum ratio was 1:1 based on the amount of injected CO 2 . In layered reservoirs, each permeability arrangement had higher recovery at different WACO 2 ratios depending on the location of the flow barrier. However, in most cases 1:1 ratio was the optimum except for two cases, where the high permeability was at top, the 3:1 (increasing water ratio) was the optimum WACO 2 ratio.