CO₂ flow in porous media is vital for both enhanced oil recovery and underground carbon storage. For improving CO₂ mobility control and thus improved reservoir sweep efficiency, Water-Alternating-Gas (WAG) injection has often been applied. The effectiveness of WAG diminishes, however, due to the presence of micro-scale reservoir heterogeneity which results in an early breakthrough of gas. We propose Polymer-assisted WAG (PA-WAG) as an alternative method to reduce gas mobility, while also reducing the mobility of the aqueous phase, and consequently improving the performance of WAG. In this method, high molecular weight water-soluble polymers are added to the water slug. The goal of this work was to investigate the feasibility of PA-WAG and study the transport processes in porous media. An ATBS-based polymer (SAV 10 XV) was chosen as polymer and CO₂ at immiscible conditions as gas. The objective of the experiments was to compare the performance of CO₂, WAG, and PA-WAG injection schemes by conducting a series of X-ray computed tomography (CT)-aided core-flood experiments in Bentheimer cores. Core-flood results clearly demonstrated the beneficial effects of PA-WAG over WAG and continuous CO₂ injection. Continuous injection of CO₂ led to the recovery factor (RF) of only 39.0 ± 0.5% of the original oil in place (OOIP). In-situ visualization of CO₂ displacement showed strong gravity segregation and viscous fingering because of the contrast in the viscosities and densities of CO₂ and oil. The injection of WAG almost doubled the oil recovery (i.e., RF=76.0 ± 0.5%); however, the water and gas breakthroughs still occurred in the early stage of the injection (0.22 PV for water and 0.27 PV for CO₂). The addition of the polymer to the aqueous phase delayed both the water and CO₂ breakthrough (0.51 PV for water and 0.35 PV for CO₂). This resulted in an additional 10% in the recovery factor. Using a single injection method, polymer adsorption was found to be 79.0 ± 0.5 μg polymer/g rock. The polymer adsorption can reduce the micro-scale permeability and as a result, mitigates the gas channeling. This in turn leads to the delay in CO₂ breakthrough during PA-WAG injection as was evident from in-situ visualization. This experimental study demonstrated a positive response of PA-WAG compared to WAG and paves the way for its implementation in field applications.

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This paper introduces new oil recovery mechanisms for oil recovery by polymer injection in heavy oil reservoirs with strong bottom aquifers. Due to unfavorable mobility ratio between aquifer water and oil and the development of the sharp cones significant amount of oil remains unswept. To overcome these issues, for the case demonstrated in this paper, a polymer injection pilot was executed with three horizontal injectors, located a few meters above the oil/water contact. The injectivity issues resulted in frequent shutdowns of the injectors. Interestingly, the water cut reversal and oil gain continued during the shut-in periods. This observation has led to the development of a new cyclic polymer injection strategy, in which the injection of polymer is alternated with intentional well shut-ins. The strategy is referred to as Nothing-Alternating-Polymer (NAP). It was found that during polymer injection, the oil is recovered by conventional mobility and sweep enhancement mechanisms ahead of the polymer front. Additionally, during this stage the injected polymer squeezes the existing cones and creates a barrier between the aquifer and the oil column, suppressing the aquifer flux and hence the negative effect of the cones or water channels (blanketing mechanism). Moreover, injection of polymer pushes the oil to the depleted water cones, which is then produced by the water coming from the aquifer during shut-in period (recharge mechanism). During the shut-in or NAP period, the aquifer water also pushes the existing polymer bank and hence leads to extra oil production. The resistance caused by polymer adsorption reduces the extent of fingering of water into polymer bank. The NAP strategy reduces polymer loss into aquifer and improves the polymer utilization factor expressed in kg-polymer/bbl of oil, resulting in a favorable economic outcome.

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Water injection into the subsurface, inherent in improved hydrocarbon recovery and extraction of geothermal energy, often suffers from injectivity decline, even when water carries only nano-sized particles at low concentrations. This study investigates the propagation of such nano-sized particles experimentally and by modelling. Water with dispersed silica nanoparticles of about 140 nm diameter was used as a proxy to ultra-filtered water. Dispersion of the nanoparticles in brine is investigated by varying their concentration, the brine composition, salinity, pH and the presence of iron ions. The measured apparent hydrodynamic size and zeta potential indicate that nanoparticles remain dispersed with the expected size only for salinity below 3000 ppm with pH ranges 6.5 to 8.5. For higher salinity or pH outside that range or presence of iron ions, agglomeration becomes strong. Core flood experiments are conducted on high permeability Bentheimer sandstone, and the transport and retention of nanoparticles in the cores was analysed using multiple pressures measured along the core and by influent/effluent analysis. Core flood results show that stable injectivity can be reached with a good propagation of the nanoparticles through the permeable core with no external filter cake formation, provided the pH and salinity of the injected fluid are kept within the dispersion range and free of iron ions. However, injectivity decline still occurs in three characteristic stages well captured by our mechanistic model used to match the data. This study will contribute to better understanding of the transport dynamics of nanoparticles in the subsurface and to better modelling prediction and assessment of technologies where transport of nanoparticles is key.

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It has been proposed that increased oil recovery in carbonates by modification of ionic composition or altering salinity occurs mainly at a temperature exceeding 70-80 °C. The argument was that elevated temperatures enhance adsorption of the potential determining ions which then modifies wettability to a less-oil-wetting state. According to this rationale, it becomes questionable if diluted brines or brines without these ions can be still applicable. Therefore, the aim of this paper is to investigate if the wettability alteration truly depends on temperature and if so how the trend with temperature can be explained. We followed a combined experimental and theoretical modeling approach. The effect of brine composition and temperature on carbonate wettability was probed by monitoring contact angle change of sessile oil droplets upon switching from high salinity to lower salinity brines. IFT measurements as a function of salinity and temperature along with extensive Ζ-potential measurements as a function of salinity, pH, temperature, and rock type were conducted. Interaction potentials between oil and carbonate surfaces were estimated based on DLVO theory, and its consistency with oil-droplet data was checked to draw conclusions on plausible mechanisms. Three carbonate rocks (two limestones and one dolomite) were used along with two reservoir crude oils, high salinity formation water (FW), seawater (SW), and 25 times diluted seawater (25dSW) as low salinity (LS) brine. It was observed that (i) wettability alteration to a less-oil-wetting state can occur at ambient temperature for specific rock types and brines, and (ii) there is no univocal increase in response to SW and LS brine at elevated temperature. The largest improvement in wettability was observed for dolomite, while, among the limestones, only one rock type showed noticeable wettability improvement at elevated temperature with SW. The difference in behavior between limestones and dolomite indicates that the response to brine composition change depends on rock type and mineralogy of the sample. These observations are consistent with the Ζ-potential trends with salinity at a given temperature. Dolomite generally shows more positive Ζ-potential than limestones. However, even the two limestones react differently to lowering salinity and exhibit different magnitude of Ζ-potential. Moreover, it is observed that, at a specific salinity, an increase in temperature leads to reduction of Ζ-potential magnitude on both rock/brine and oil/brine interfaces toward zero potential. This can affect positively or negatively the degree of wettability alteration (to a less-oil-wetting state) at elevated temperature depending on the sign of oil/brine and rock/brine Ζ-potential in SW/LS. The observed trends are reflected in the DLVO calculations which show consistency with contact angle trends with temperature and salinity. According to the DLVO calculation, the lack of response to SW/LS in some of the systems above can be explained by stronger electrostatic attractive forces under SW/LS than HS. This study concludes that a combined surface-charge change and double-layer expansion is a plausible mechanism for the wettability alteration in carbonate rocks.

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We have successfully validated the Asphaltene Option in ECLIPSE, using an experimental data set from the literature. We compare our results with a previous Deep Bed Filtration simulation model of the same data. We find that the experimental data can be reproduced by using the surface deposition parameter α only. This provides an important simplification of the Asphaltene Option in ECLIPSE. Moreover, the values of α can be predicted from a pore scale colloid dynamics simulation model using the Stochastic Rotation Dynamics (SRD) technique. It turns out that the values for α obtained in the literature (Wang, 2001) and our own ECLIPSE results are consistent with the predictions from the SRD simulation model. This may give an advantage over other asphaltene deposition models available in the literature.@en