An Experimental Investigation of the Effect of Changing the Rock's Wettability on the Performance of Carbonated Water Injection CWI

CWI is affected by multiple factors, including the wettability of the rock. These experiments seek to determine the results that are obtained when CW is injected in a tertiary mode for systems: (1) wetted by water and (2) mixed wettability; to date, no study has used this approach. The same sandstone core was used in all trials, and each test consisted of saturating the core with live crude, followed by the injection of water as a secondary recovery and then the injection of CW as a tertiary recovery. An additional sensitivity test was conducted that consisted of varying the composition of the dissolved gas in the crude. In general, in a water wet system, the recovery associated with the injection of CW is higher (normalized) compared to a mixed wettability system. This does not mean that the results were negative in the mixed system. On the contrary, the results are positive since on the order of an additional 20% was recovered. However, the pressure differential in a mixed system is higher (14%) compared to water wet system. Although it is common knowledge that wettability of the rock affects the production and pressure results in an experiment, these are the first experiments that have been performed exclusively to determine quantitatively the response to CWI while maintaining the other parameters constant.

Low-salinity carbonated water injection in sandstone reservoirs: interplay between oil recovery improvement, salinity and fines migration

Carbonated water injection (CWI) is described as a chemical-enhanced oil recovery method in which CO2-enriched water is injected into oil reservoirs as a displacing fluid. Although confirmed by many that a considerable amount of recovery improvement is attainable through CWI in both lab and field scales, the interaction of salinity on the performance of CWI and its potential fines migration is not very well understood. This study examines the efficiency of oil recovery improvement during low-salinity carbonated water injection (LSCWI) in a sandstone reservoir, while total dissolved salt concentration varies. To this end, a series of coreflooding experiments were performed on homogeneous sandstone cores at 80°C and 2000psi, and the amount of oil recovery was measured. From the experiments, it was observed that CWI could extract more crude oil than conventional water flooding in all salinities. In particular, the highest oil recovery was observed in the lowest salinity (61.2% in CWI and 42% during water flooding), indicating that by carbonating low-salinity water, oil recovery is enhanced by 20%. Moreover, the influence of salinity reduction on recovery enhancement was such that 9% of recovery improvement observed during conventional water flooding when salinity decreased from 40000 to 1000ppm. At the same time, this improvement was around 15% for CWI, suggesting that salinity reduction can be more effective in CWI rather than water flooding in recovery improvement. It was also found out that while recovery improvement and fines migration are both highly affected by water salinity, there is a synergy between the efficiency of CWI and onset of fines migration, which is one of the underlying mechanisms in oil recovery improvement during LSCWI into clay-containing sandstone reservoirs.

Molecular Dynamics Simulation of CO2 Diffusion in a Carbonated Water–Decane System

Carbonated water injection (CWI) is a technology with significant sweep efficiency advantages in enhanced oil recovery (EOR), but the mechanism of the microscopic diffusion of CO2 is still unclear. In this study, the diffusion mechanism of CO2 from the aqueous phase to the oleic phase in a carbonated water (CW)–decane system was investigated by the molecular dynamics simulation method. This investigation also explored the diffusion capacity and interface properties of the CW–decane system. We found that the movement of CO2 from the aqueous phase to the oleic phase can be divided into two processes: the accumulation behavior of CO2 moving from the aqueous phase to the interface, and the dissolution behavior of CO2 moving from the interface to the decane phase. The increase in the temperature and CO2 concentration in carbonated water can improve the decane phase’s diffusion ability and reduce the water–decane interfacial tension. The difference in the interactions between water–CO2 and decane–CO2 provides a driving force for the diffusion of CO2 between aqueous and oleic phase. The temperature increase intensifies the degree of diffusion and improves the diffusion rate of CO2 from the aqueous phase to the oleic phase. The diffusion coefficient results show that CO2 significantly enhances the oleic phase’s diffusion properties. In addition, the affinity of water for CO2 is increased by the hydrogen bond, and it provides a mechanism for the accumulation behavior of CO2. Further, the temperature significantly improves the CO2 diffusion ability at the interface, which promotes CO2 leaving the interface and weakens the accumulation behavior. This work provides useful information for guiding carbonated water injection to improve the recovery mechanism of enhanced oil.

An Experimental Investigation of the Effect of Rock Wettability on the Performance of Carbonated Water Injection (CWI)

Wettability is often considered one of the most relevant variables in any conventional water injection process as it dominates the microscopic distribution of fluids in the porous medium, determines the amount of residual oil, and defines the ability with which a phase can flow. On the other hand, carbonated water injection is an enhanced oil recovery technique, where basically water saturated with CO2 is injected along the reservoir with the benefits of water displacement together with the benefits of CO2 injection, without the great disadvantages of poor sweeping causing low areal efficiency. In addition, it has been proven that the transfer of CO2 from the aqueous phase to the oil phase, in one way, promotes the generation of what has been called a new gas phase, which is the main responsible for the incremental oil production, and which mainly attacks the residual oil saturation. Numerous experiments performed in the past on micro models, and plugs have shown that the injection of carbonated water plays an important role in the wettability of the rock. The injection has been demonstrated a change in the wettability to a water-wet because there is a reduction in the pH of the aqueous phase, and this is expected to modify the charges on the oil/water, and water/rock interfaces, and hence the wettability of the system. The dissolution of CO2, into the oil phase, and the destabilization of the polar components of the oil also may shift the wettability more towards water-wet, which favours a later water breakthrough, and a higher oil recovery factor. However, none of these experiments, as far as the author is informed, have been performed on whole cores, nor have these experiments used live crude oil with multi-component gases in solution, which would be closer to reality. This research seeks to close this gap by performing a new series of core floods to understand, from an engineering point of view, what effect the injection of carbonated water has on wettability in circumstances more realistic. From these analyses it was concluded that rock wettability plays an important role on the differential pressure behaviour for both waterflooding, and carbonated water injection. A mix/oil-wet rock causes a greater differential pressure response. A much higher differential pressure is obtained when carbonated water injection is started. This is assumed to be due to the formation of the new gas phase. A greater oil recovery factor is obtained in a water-wet system when both secondary waterflooding, and tertiary CWI oil recovery are summed. However, when only tertiary injection of carbonated water is analysed, a higher oil recovery is obtained in mix/oil-wet systems. The new gas phase formation is facilitated in mix/oil-wet systems. The methane content dissolved in live oil plays the main role for oil recovery, and differential pressure behaviour in a carbonated water injection process. It is inversely related to the pressure behaviour, and oil recovery. This occurs because a low methane content allows a higher formation of the new gas phase, and therefore a higher production of oil; however, the differential pressure increases at the same time. Viscosity reduction due to CO2 mass transfer has a smaller effect in oil recovery, and differential pressure than the effect caused by the formation of a new gas phase. In the experiments that were conducted, the author calculated a novel linear relationship between new gas phase saturation, and tertiary oil recovery. This relationship is almost constant irrespective of the oil, and gas compositions and the wettability of the rock. This approach would allow the calculation of the additional tertiary oil recovery potential by the injection of carbonated water, based only on the saturation behaviour of the new gas phase; therefore the new objective of this recovery method would be to maximise the formation of this new phase. Although at laboratory scale there are different methods to determine the wettability of a rock, sometimes it is not possible to perform such measurements. Therefore, the author proposes a novel method that identifies trends in wettability, or better, compares trends based on Darcy's equation. This method was applied to the experiments conducted in this research, and its results were corroborated by other approaches available in the industry. Based on the results, it is possible to infer that by using a whole core the wettability change effect associated with the injection of carbonated water is not so preponderant, on the contrary, it could be more affected by the methane content in the system. The experiments conducted prior to this research had been focused on micro-models, and 1 to 2 inch diameter core evaluations, where the analysis was restricted to pore level or small scale behaviour, systems in which the impact of pore level wettability change is much greater.