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Substantial amount of crude oil remains in the reservoir after primary and secondary production. Chemical flooding is one of the enhanced oil recovery (EOR) methods; however, chemicals (i.e., Surfactant) used are sensitive to the harsh environment characterizing the local reservoirs. The current study aimed at investigating the utilization of ionic liquids (ILs), known as environment friendly salt with good solubility, thermal stability and effective surface activity, as an alternative to conventional organic surfactants in enhanced oil recovery process. In this work, screening tests of nine ILs were performed. These ILs were diluted in different brine solutions of different salt compositions at 10 % (w/w) salinity and their solubility, thermal stability and surface activity in presence of Saudi medium crude oil were tested. Tetra alkyl ammonium sulfate known as Ammoeng 102 was found to be the ionic liquid of choice. Further investigations on Ammoeng 102 solutions at 10 and 20 % (w/w) salinity were conducted and IFT measurements indicate enhanced surface activity of Ammoeng 102 with increasing solution salinity. Effects of pressure and temperature on interfacial tension (IFT) were also tested and the results indicate minor effects. Adsorption test indicates high Ammoeng 102 adsorption tendency with more adsorption for higher salinity solution. Different flooding scenarios were conducted in sandstone rock samples to investigate the effectiveness of Ammoeng 102 IL as an EOR chemical. The findings indicate promising results for ionic solution flooding in secondary mode at irreducible water saturation (S wirr ). Ultimate recovery obtained is higher than that obtained with combined secondary brine flooding followed by tertiary ionic solution flooding at residual oil saturation (S or ). Injection of slug of ionic solution in secondary mode provides lower recovery compared to that recovered with continuous ionic solution injection in the same mode. Rock water content affects recovery efficiency indicating higher oil recovery for secondary brine and tertiary ionic solution flooding at low S wirr . Contact angle and relative permeability measurements demonstrate the role of wettability alteration behind the extra oil recovery which is very much affected by ionic liquid concentration that can be altered by dilution with formation and injected brines.

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Oil recovery from heavy oil resources has always been a challenging task. This work is aimed at investigating the recovery efficiency of polymer-augmented low salinity waterflooding in heavy oil reservoirs. The main recovery mechanism behind low salinity waterflooding is wettability alteration to more water-wet state. On the other hand, polymer flooding is performed to control fluids mobility and hence improve displacement efficiency. Combining both recovery methods is expected to add to recovery efficiency obtained by individual methods, and the aim of this work is to explore this experimentally. In this study, several laboratory experiments were conducted using Berea and Bentheimer sandstone cores starting with base runs of continuous secondary seawater and tertiary twice and 10 times diluted seawaterflooding (low salinity). Significant incremental oil recovery was obtained when flooded with low salinity water, and 10 times diluted seawater was determined to be used as low salinity water. Contact angle and Zeta potential measurements indicate wettability alteration due to clay detachment as the main recovery mechanism. Synergy of water secondary flooding and polymer tertiary flooding at different water salinity levels proved the efficiency of hybrid low salinity polymer flooding process in Berea sandstone. Low water salinity during secondary injection mode played a major role on ultimate recovery with less contribution to tertiary polymer slug injection. High salinity waterflooding provided lower secondary recovery leaving more residual oil for polymer slug to act on at that cycle. Smaller polymer slug of 0.1 pore volume was found to be sufficient in tertiary flooding with low salinity water but with slightly slower recovery rate. Bentheimer sandstones known for its low clay content were subjected to polymer-augmented waterflooding at high and low salinity levels. Close secondary and tertiary recoveries were obtained for the two salinity levels with slower recovery rate for low salinity run. Minute clay content and water-wet characteristic as determined by contact angle measurements may explain the lack of water salinity effect on recovery. The lack of salinity role and the two shock fronts with connate water bank in between known to exist during low salinity flooding may explain the slower recovery rate encountered. Comparison of both sandstones indicates that less ultimate recovery from Berea rocks, and this can be attributed to their initial intermediate wet state in contrast to the water-wet Bentheimer sandstone rocks.

Foamability and foam stability are of main concerns in foam displacement for enhanced oil recovery. This work presents the output of systematic laboratory screening of foamability and foam Stability of several surfactants. The surfactants examined were Brij 700, Triton X-100, Triton X-405, Zonyl FSO,. Foam was generated by sparging Carbon Dioxide gas at a fixed flow rate through surfactants solutions and R5 parameter as suggested by Lunkenheimera and Malysa (2003) were used for foam stability testing. The results indicate the foamability of all surfactants except for Triton X-405. Zonyl FSO and Hitenol H-10 were superior in term of foam stability with more stability as surfactants concentration increases. Equivalent optimum foam volumes were obtained for both surfactants but at higher concentrations of Hitenol H-10. Foam stability and oil displacement efficiency were tested with different concentrations of Zonyl FSO and Hitenol H-10 solutions. The presence of oil at the volume fraction implemented, affect the stability of the foam columns. The effect depends on the surfactant-type and surfactants concentrations where stability decreases at low Zonyl FSO concentration range and at all concentrations range tested of Hitenol H-10. In case of Zonyl FSO observations indicate that oil stayed in the lamellas skeleton and plateau boarders with no drain out. To the contrary, Hitenol H-10 was able to lift good portion of the oil column but oil was drained out of the foam structure within a short period of time. Flooding tests on Berea cores proved the ability of Zonyl FSO and Hitenol H-10 in controlling gas mobility and improving the displacement efficiency. Hitenol H-10 was more efficient as indicated by the incremental oil recovery obtained and the higher pressure drop encountered. Hitenol H-10 Foam injection on tertiary gas flooded reservoirs improves residual oil recovery indicating the potential of the process even at late stages of gas injection.

Given the increasing demand for energy globally and depleting oil and gas resources, it is crucial to increase the production from existing reservoirs by introducing new technologies for Improved/Enhanced Oil Recovery (IOR/EOR). This contribution presents a novel hybrid IOR/EOR method, which combines smart water (SW) and foam flooding, known as Smart Water Assisted Foam (SWAF) flooding. The optimal conditions of the SWAF technology will be interpreted using experimental laboratory design (i.e., experimental data). The experimental design was divided into three main steps. The first step is obtaining rock wettability measurements using contact angle measurements. This step aims to select the optimum SW composition that changes the carbonate rock's wettability from oil-wet towards more water-wet and faster oil recoveries. The water-wet condition leads to high residual oil saturations and low end-point permeabilities. This is conductive to favourable mobility ratios and efficient water-oil displacement. However, high residual oil saturations are unfavourable to the high ultimate oil recovery as much oil stays behind. Secondly, the chemical screening follows, where two tests were performed, viz., (i) an Aqueous Stability Test (AST), (ii) and a Foamability and Foam Stability Tests (FT/FST). This step aims to generate a stable foam (i.e., surfactant aqueous solution + gas) in the absence and presence of crude oil with different TAN (Total Acid Number) and TBN (Total Base Number), viz., crude oils Type-A and Type-B. Favourable mobility ratio is achieved by the presence of foam, which leads to excellent displacement efficiency. Thirdly, core flooding tests are performed. This step aims to select the best formulations through SWAF core flooding tests to obtain the ultimate recovery factor under different injection scenarios. The optimal SWAF condition combines high ultimate recovery with the best displacement efficiency. It is shown that the enormous changes in wettability were seen for SW (MgCl2) solution at 3500 (ppm) for both crude oils Type-A and Type-B. It has been shown that the use of a cationic surfactant CTAB (i.e., cetyltrimethylammonium-bromide) in the positively charged carbonates (with an isoelectric point of pH = 9) is more effective than the use of anionic surfactant, e.g., Alpha Olefin Sulfonate (AOS). The aim is to create an optimum surfactant aqueous solution (SAS). The SAS stability is considerably affected by the concentration of both the SW (MgCl2) and surfactant (CTAB). In the absence of oil, the strength of foam (SAS and Gas) is highly dependent on the concentration and composition of the SW in the SAS. In the presence of oil, foam generation and stability are better when the crude oil has a low TAN and high TBN. From the core flooding tests for crude oils Type-A and Type-B, the ultimate residual oil recovery was achieved by the MgCl2 - foam injection combination (i.e., incremental oil recovery of 42%, which is equivalent to a cumulative oil recovery of 92%). In summary, SWAF under the optimum conditions is a promising method to increase the oil recovery from carbonate reservoirs.

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