Study of surface complexation modeling on a novel hybrid enhanced oil recovery (EOR) method; smart-water assisted foam-flooding

Hassan, Anas M.; Ayoub, Mohammed Abdalla; Eissa, Mysara; Bruining, Hans; Zitha, Pacelli L.J.

doi:10.1016/j.petrol.2020.107563

Cited by 28 publications

(20 citation statements)

References 38 publications

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“…In the case of polymer interactions with an oil-wet rock, better theoretical approaches (e.g., theories related to disjoining press such as DLVO, double layer expansion, surface complexation, and induced polarity) are required for wettability alteration and polymer adsorption studies. ,,− …”

Section: Postadsorption Mechanismsmentioning

confidence: 99%

Rock/Fluid/Polymer Interaction Mechanisms: Implications for Water Shut-off Treatment

et al. 2021

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Several disproportionate permeability reduction (DPR) mechanisms have been proposed in the literature for water shutoff treatment using polymer relative permeability modifiers (RPM). However, none appear to be universally accepted. The lack of agreement may be because no single factor determines the success of DPR treatment. Moreover, there is still a lack of understanding of DPR mechanisms and the order of how these mechanisms work together. This paper provides a comprehensive review of the mechanisms behind the RPMs. We identify that sufficient polymer adsorption onto the rock surface is a primary condition for water shutoff treatment, while rock surface initial wettability and fluid−polymer−rock interaction/attraction plays a significant role in polymer adsorption. Furthermore, polymer concentration, polymer molecular weight, aging time, polymer injection volume, polymer injection rate, and reservoir temperature are also vital for polymer adsorption. After polymer adsorption, the mechanisms such as fluid segregation and wall effect help accomplish the required DPR. We also find that there is a more consistent agreement among the published studies on the order of DPR mechanisms e.g. initial rock wettability effect comes first, followed by initial segregation, adsorption wall effect (i.e., steric, lubrication, wettability alteration, and swelling/shrinkage), and then the final segregation. Depending on the RPM implementation, which depends on pore size, the polymer layer thickness can be adjusted after the placement permanently or temporarily by controlling swelling/shrinkage. The subject matter investigated in this review helps us understand the factors responsible for optimal performance of polymer solutions in controlling excess water production from hydrocarbon reservoirsthus assisting in more efficient oil/gas production.

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Section: Postadsorption Mechanismsmentioning

confidence: 99%

Rock/Fluid/Polymer Interaction Mechanisms: Implications for Water Shut-off Treatment

et al. 2021

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“…Secondary recovery involves the injection of water and gas whose purpose of maintaining reservoir pressure. Tertiary recovery, is any technique applied after secondary displacements, such as gas-EOR flooding, water-based EOR injection (i.e., low salinity), chemical flooding (i.e., polymer, surfactant, and alkaline surfactant polymer or ASP [ 9 , 11 ]), and hybrid-EOR (e.g., low salinity polymer flooding [ 12 ] and smart-water assisted foam flooding or SWAF Technology [ 13 , 14 , 15 , 16 , 17 , 18 ]).…”

Section: Introductionmentioning

confidence: 99%

Updated Perceptions on Polymer-Based Enhanced Oil Recovery toward High-Temperature High-Salinity Tolerance for Successful Field Applications in Carbonate Reservoirs

2022

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The aging of the existing reservoirs makes the hydrocarbon extraction shift toward newer reserves, and harsh conditioned carbonates, which possess high temperature and high salinity (HTHS). Conventional polymer-flooding fails in these HTHS carbonates, due to precipitation, viscosity loss, and polymer adsorption. Therefore, to counteract these challenges, novel polymer-based cEOR alternatives employ optimized polymers, polymer–surfactant, and alkali–surfactant–polymer solutions along with hybrid methods, which have shown a potential to target the residual or remaining oils in carbonates. Consequently, we investigate novel polymers, viz., ATBS, Scleroglucan, NVP-based polymers, and hydrophobic associative polymers, along with bio-polymers. These selected polymers have shown low shear sensitivity, low adsorption, and robust thermal/salinity tolerance. Additionally, adding an alkali-surfactant to polymer solution produces a synergy effect of improved mobility control, wettability alteration, and interfacial-tension reduction. Thus, enhancing the displacement and sweep efficiencies. Moreover, low-salinity water can precondition high-salinity reservoirs before polymer flooding (hybrid method), to decrease polymer adsorption and viscosity loss. Thus, this paper is a reference for novel polymers, and their hybrid techniques, to improve polymer-based cEOR field applications under HTHS conditions in carbonates. Additionally, the recommendations can assist in project designs with reasonable costs and minimal environmental impact. The implication of this work will aid in supplementing the oil and gas energy sector growth, making a positive contribution to the Middle Eastern economy.

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“…The first effect is improvement in the rock-fluid interaction through surface charge alteration at the rock-fluid interface, causing the change of reservoir rock wettability towards a further water-wet state. The second enhancement effect of the smart water is the modification of fluid-fluid interaction via abating the shielding effect of the electrical double layer (EDL), which improves foam film stability [29][30][31]. These changes in surface charges at both rock-fluid and fluid-fluid interfaces cause the rock-water interface and the water-oil interface to become of the same sign (i.e., negative or positive charge), creating stable water and foam film, augmenting better EOR (i.e., improved recovery factor or RF) [29][30][31][32].…”

Section: Introductionmentioning

confidence: 99%

“…The second enhancement effect of the smart water is the modification of fluid-fluid interaction via abating the shielding effect of the electrical double layer (EDL), which improves foam film stability [29][30][31]. These changes in surface charges at both rock-fluid and fluid-fluid interfaces cause the rock-water interface and the water-oil interface to become of the same sign (i.e., negative or positive charge), creating stable water and foam film, augmenting better EOR (i.e., improved recovery factor or RF) [29][30][31][32]. Moreover, a synergy effect is generated when the smart water solution is combined with foam flooding via alternating (SAS) and gas (i.e., SAG) injection.…”

Section: Introductionmentioning

confidence: 99%

“…Finally, it is also to be noted that this experimental study is a progression of the previous works, viz., [29][30][31] on an innovative hybrid EOR technique termed smart waterassisted foam (SWAF) flooding for application in carbonate reservoirs. Whereas these preceding studies (SPE-196407-MS) [29][30][31] mainly focused on the theoretical and modeling aspects (i.e., DLVO theory and surface complexation modeling or SCM). In this study, our focus has been on laboratory experimental facets of the SWAF process in carbonate rocks [20,42].…”

Section: Introductionmentioning

confidence: 99%

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Increasing Reservoir Recovery Efficiency through Laboratory-Proven Hybrid Smart Water-Assisted Foam (SWAF) Flooding in Carbonate Reservoirs

et al. 2022

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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, CO2 and nitrogen, N2) 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 (MgCl2) 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 (MgCl2) 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 MgCl2-foam injection mixture (MgCl2 + CTAB + AOS + N2) 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 CO2 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.

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Study of surface complexation modeling on a novel hybrid enhanced oil recovery (EOR) method; smart-water assisted foam-flooding

Cited by 28 publications

References 38 publications

Rock/Fluid/Polymer Interaction Mechanisms: Implications for Water Shut-off Treatment

Rock/Fluid/Polymer Interaction Mechanisms: Implications for Water Shut-off Treatment

Updated Perceptions on Polymer-Based Enhanced Oil Recovery toward High-Temperature High-Salinity Tolerance for Successful Field Applications in Carbonate Reservoirs

Increasing Reservoir Recovery Efficiency through Laboratory-Proven Hybrid Smart Water-Assisted Foam (SWAF) Flooding in Carbonate Reservoirs

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