In hydraulic fracturing, fracturing fluids are used to create fractures in a hydrocarbon reservoir throughout transported proppant into the fractures. The application of many fields proves that conventional fracturing fluid has the disadvantages of residue(s), which causes serious clogging of the reservoir’s formations and, thus, leads to reduce the permeability in these hydrocarbon reservoirs. The development of clean (and cost-effective) fracturing fluid is a main driver of the hydraulic fracturing process. Presently, viscoelastic surfactant (VES)-fluid is one of the most widely used fracturing fluids in the hydraulic fracturing development of unconventional reservoirs, due to its non-residue(s) characteristics. However, conventional single-chain VES-fluid has a low temperature and shear resistance. In this study, two modified VES-fluid are developed as new thickening fracturing fluids, which consist of more single-chain coupled by hydrotropes (i.e., ionic organic salts) through non-covalent interaction. This new development is achieved by the formulation of mixing long chain cationic surfactant cetyltrimethylammonium bromide (CTAB) with organic acids, which are citric acid (CA) and maleic acid (MA) at a molar ratio of (3:1) and (2:1), respectively. As an innovative approach CTAB and CA are combined to obtain a solution (i.e., CTAB-based VES-fluid) with optimal properties for fracturing and this behaviour of the CTAB-based VES-fluid is experimentally corroborated. A rheometer was used to evaluate the visco-elasticity and shear rate & temperature resistance, while sand-carrying suspension capability was investigated by measuring the settling velocity of the transported proppant in the fluid. Moreover, the gel breaking capability was investigated by determining the viscosity of broken VES-fluid after mixing with ethanol, and the degree of core damage (i.e., permeability performance) caused by VES-fluid was evaluated while using core-flooding test. The experimental results show that, at pH-value ( 6.17 ), 30 (mM) VES-fluid (i.e., CTAB-CA) possesses the highest visco-elasticity as the apparent viscosity at zero shear-rate reached nearly to 10 6 (mPa·s). Moreover, the apparent viscosity of the 30 (mM) CTAB-CA VES-fluid remains 60 (mPa·s) at (90 ∘ C) and 170 (s − 1 ) after shearing for 2-h, indicating that CTAB-CA fluid has excellent temperature and shear resistance. Furthermore, excellent sand suspension and gel breaking ability of 30 (mM) CTAB-CA VES-fluid at 90 ( ∘ C) was shown; as the sand suspension velocity is 1.67 (mm/s) and complete gel breaking was achieved within 2 h after mixing with the ethanol at the ratio of 10:1. The core flooding experiments indicate that the core damage rate caused by the CTAB-CA VES-fluid is ( 7.99 % ), which indicate that it does not cause much damage. Based on the experimental results, it is expected that CTAB-CA VES-fluid under high-temperature will make the proposed new VES-fluid an attractive thickening fracturing fluid.

This paper probes the transport of CO 2 soluble surfactant for foaming in porous media. We numerically investigate the effect of surfactant partitioning between the aqueous phase and the gaseous phase on foam transport for subsurface applications when the surfactant is injected in the CO 2 phase. A 2-D reservoir simulation is developed to quantify the effect of surfactant partition coefficient on the displacement conformance and CO 2 sweep efficiency. A texture-implicit local-equilibrium foam model is embedded to describe how the partitioning of surfactant between water and CO 2 affects the CO 2 foam mobility control when surfactant is injected in the CO 2 phase. We conclude that when surfactant has approximately equal affinity to both the CO 2 and the water, the transport of surfactant is in line with the gas propagation and therefore the sweep efficiency is maximized. Too high affinity to water (small partition coefficient) results in surfactant retardation whereas too high affinity to CO 2 (large partition coefficient) leads to weak foam and insufficient mobility reduction. This work sheds light upon the design of water-alternating-gas-plus-surfactant-in-gas (WAG + S) process to improve the conventional foam process with surfactant-alternating-gas (SAG) injection mode during which significant amount of surfactant could possibly drain down by gravity before CO 2 slugs catch up to generate foam in situ the reservoir.

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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.

Combinatory flooding techniques evolved over the years to mitigate various limitations associated with unitary flooding techniques and to enhance their performance as well. This study investigates the potential of a combination of 1-hexadecyl-3-methyl imidazolium bromide (C16mimBr) and monoethanolamine (ETA) as an alkali–surfactant (AS) formulation for enhanced oil recovery. The study is conducted comparative to a conventional combination of cetyltrimethylammonium bromide (CTAB) and sodium metaborate (NaBO2). The study confirmed that C16mimBr and CTAB have similar aggregation behaviors and surface activities. The ETA–C16mimBr system proved to be compatible with brine containing an appreciable concentration of divalent cations. Studies on interfacial properties showed that the ETA–C16mimBr system exhibited an improved IFT reduction capability better than the NaBO2–CTAB system, attaining an ultra-low IFT of 7.6 × 10−3 mN/m. The IFT reduction performance of the ETA–C16mimBr system was improved in the presence of salt, attaining an ultra-low IFT of 2.3 × 10−3 mN/m. The system also maintained an ultra-low IFT even in high salinity conditions of 15 wt% NaCl concentration. Synergism was evident for the ETA–C16mimBr system also in altering the carbonate rock surface, while the wetting power of CTAB was not improved by the addition of NaBO2. Both the ETA–C16mimBr and NaBO2–CTAB systems proved to form stable emulsions even at elevated temperatures. This study, therefore, reveals that a combination of surface-active ionic liquid and organic alkali has excellent potential in enhancing the oil recovery in carbonate reservoirs at high salinity, high-temperature conditions in carbonate formations.

Oil compressibility (co) plays a vital role in vast aspects ranging from upstream to downstream. For reservoir with pressure below bubble point, the effect of co to the fluid flow is insignificant as it is overshadowed by the presence of large gas compressibility (cg). This study aims to increase the range of applicability and accuracy of the formula used for estimating the co by eliminating the limitations of other existing correlations. A new formula for the estimation of oil compressibility below bubble point pressure is devised using Group Method Data Handling (GMDH). The approach is a combination of neural networks and some high-level statistical methods which rely on generating simple relations among the input parameters and the dependent parameter. The relations then result in eliminating some parameters with low impact on the output. A series of consecutive layers with the link is generated, and polynomial terms are created. A total number of 322 data points were collected from different sources from literature. Systematic trend analysis has been conducted to verify that the proposed GMDH model honours the exact physical behaviour. The new proposed model found to follow the correct trend, which implies its soundness. Besides, a comparative study was carried out using the best available correlations to confirm the significance of the results of the oil compressibility prediction using GMDH. Different statistical analyses have been conducted to verify the robustness of the newly developed model. The statistical analyses showed a positive outcome whereby the proposed model obtained the lowest average absolute percentage relative error of 5.17% and the highest correlation coefficient of 96.8%. The best model tested among the other models has five input parameters and an average absolute percentage relative error of 10.955% and a correlation coefficient of 95.6%. The new approach managed to reduce the curse of dimensionality as four input parameters have found to have a strong dependency on co (solution gas-oil ratio, oil density, reservoir temperature, and reservoir pressure). The new proposed model overcome the limitations described by the locality of some correlations as they depend on data from specific locations.