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This contribution introduces a new hybrid enhanced oil recovery (EOR) method which combines smart water-assisted foam (SWAF) flooding, known as the SWAF process. The concept of applying SWAF flooding in carbonate reservoirs is a novel approach previously unexplored in the literature. The synergy effect of the SWAF technique has the potential to mitigate a number of limitations related to individual (i.e., conventional water injection and foam flooding) methods encountered in carbonates. In general, carbonate rocks are characterized by a mixed-wet to oil-wet wettability state, which contributes to poor oil recovery. Hence, the smart water solution has been designed to produce a dual-improvement effect of altering carbonate rock wettability towards more water-wet, which preconditions the reservoir and augments the stability of the foam lamellae, which has for some conditions more favorable relative permeability behavior. Then the smart water solution is combined with surfactant (surfactant aqueous solution or SAS) and gas injection produces a synergy effect, which leads to more wettability alteration, and interfacial tension (IFT) reduction, and thus improves the oil recovery. Accordingly, to determine the optimal conditions of smart water solution with an optimal SAS, we conducted a series of experimental laboratory studies. The experimental design is divided into three main steps. At first, the screening process is required so that the candidates can be narrowed down for our designed smart water using the contact angle tests that employ calcite plate (i.e., Indiana limestone or ILS) as the first filter. Following this, the optimum smart water solutions candidates are blended with different types of cationic and anionic surfactants to create optimum SAS formulations. Subsequently, a second screening process is performed with the aim to narrow down the SAS candidates with varying types of gases (i.e., carbon dioxide, CO 2 and nitrogen, N 2 ) via the aqueous stability test (AST), foamability test (FT), and foam stability test (FST). We employed the state-of-the-art R5 parameter tests for rapid and accurate results in place of the conventional foam half-life method. The most effective combination of SAS and gas candidates are endorsed for the core-flooding experiments. In this work, two types of crude oils (Type A and B) with different total acid and base numbers (TAN and TBN). Results showed that the greatest wettability changes occurred for SW (MgCl 2 ) solution at 3500 (ppm) for both crude oil types. This demonstrates the efficacy of our designed SW in the wettability alteration of carbonates, which is also supported by the zeta-potential measurements. The concentrations of both SW (MgCl 2 ) and CTAB-based surfactants considerably affect the stability of the SAS (i.e., up to 90% foam stability). However when in the presence of crude oil, for the same SAS solution, the foam stability is reduced from 90% to 80%, which indicates the negative effect of crude oil on foam stability. Moreover, the core floods results showed that the MgCl 2 -foam injection mixture (MgCl 2 + CTAB + AOS + N 2 ) provided the highest residual oil recovery factor of SWAF process of 92% cumulative recovery of original oil in core (OIIC). This showcases the effectiveness of our proposed SWAF technique in oil recovery from carbonate reservoirs. Additionally, changing the large slug of 5 PVs to a small slug of 2 PVs of smart water solution was more effective in producing higher OIIC recovery and in reducing the fluid circulation costs (i.e., thereby, lowering CO 2 footprint), making the SWAF process environmentally benign. Thus, it is expected that under optimum conditions (SW solution and SAS), the novel SWAF process can be a potentially successful hybrid EOR method for carbonate reservoirs, having both economic and environmental benefits. [ABSTRACT FROM AUTHOR]

Most oil fields today are mature, and the majority of the reservoirs in the Middle East are carbonate rocks characterized by high temperature high salinity (HTHS), heterogeneous mineral composition, and natural fractures. Enhanced oil recovery (EOR) methods are used for boosting oil recovery from the aged reservoirs beyond primary and secondary recovery stages. Nevertheless, it can be a challenging task to employ EOR techniques in these aged carbonate reservoirs. This is because carbonate reservoirs have mixed-to-oil-wet wettability with temperatures exceeding 85 °C and salinity of over 100,000 ppm, which renders secondary EOR-methods such as waterflooding ineffective. Therefore, even though carbonate reservoirs contain 60–65% of world's remaining oil, with immense intrinsic economic prospects, the oil recovery process from carbonate reservoirs remains a considerable challenge. Chemical-EOR (cEOR) techniques, like SP based cEOR, have shown marked promise in improved oil recovery, mainly from clastic reservoirs with medium temperature and salinity, unlike carbonate reservoirs. During SP-floodings, the surfactants get adsorbed due to the mineral composition of the carbonate rocks, and polymer degradation occurs due to HTHS conditions. Consequently, new surfactants and polymers have been structurally conformed and tested to improve their robustness and related recovery efficacy. For instance, Guerbet alkoxy-carboxylate surfactants demonstrated good stability at temperatures over 100 °C and salinities up-to 275,000 ppm, yielding tertiary recovery of 94.5% and low adsorption of 0.086 mg/g of rock. The cationic Gemini surfactants, zwitterionic or amphoteric class of surfactants are also suitable for HTHS carbonates. Besides, effective biosurfactants sourced from plant such as, soy, corn, etc., are non-toxic and readily biodegradable. The hydrophobically associating polyacrylamide (HAPAM) and its modified nanocomposite derivative can act as replacement surfactants, due to their wettability altering and robust characteristics. Novel polymers viz., NVP-based, novel smart thermoviscosifying polymers (TVP), soft microgel, and sulfonated polymers, are also relevant to HTHS carbonate applications. Xanthan gum, scleroglucan, and schizophyllan biopolymers have been noted to resist HTHS and low permeability conditions, requiring lower concentration and having low adsorption. Recent surfactant-polymer (SP) formulations also can be applicable for HTHS carbonates with excellent ternary recoveries (93.6%) and minimal retention (0.083 μg/g of rock). Such low retention values suggest low surfactants cost with minimal environmental impact. Moreover, several successful field applications in carbonates were conducted in preceding years; however, the performance of some novel surfactants under HTHS carbonates is yet to be fully understood. Hence, this comprehensive review aims to provide renewed perspectives on surfactant and polymer optimizations for field applications in HTHS carbonates. A list of recommendations is presented as guidelines for efficient SP-flooding designs. This critical literature appraisal furnishes an array of potential manifestations for successful field application of SP-flooding in HTHS carbonates, which holds both economic and environmental feasibility. [Display omitted] [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]