Investigation of Shale Wettability Alteration upon Exposure to Surfactants
Abstract: The development of unconventional resources such as shales has gained great popularity in the past decade. The objective of this study is to investigate the effect of surfactants on the wettability of shale rocks. In particular, we examine the influence of different concentrations of CTAB and SDBS surfactants on Eagle Ford, Wolf Camp and Mancos shale samples to determine their wettability alteration potential at the macro-scale. In this work, macro-scale contact angle (CA) measurements of the th… Show more
Search citation statements
Paper Sections
Citation Types
Year Published
Publication Types
Relationship
Authors
Journals
Cited by 3 publications
References 44 publications
Novel Impressions of Hybrid Low Salinity Polymer (LSP) Injection: A Geochemical Modeling Study
The hybrid Enhanced Oil Recovery (EOR) method of Low Salinity Polymer (LSP) injection is an advanced synergetic coalescence with remarkable additional oil recovery capability. Several studies have reported that the LSP process significantly enhances polymer rheology and viscoelasticity, along with improving the injectivity and displacement efficiency. However, to accurately simulate and capture the complex geochemistry of the Polymer-Brine-Rock (PBR) system during LSP-injection, sophisticated mechanistic predictive models are required, which the literature rarely discusses. Therefore, we modeled the PBR-system interactions in this study, using our coupled numerical simulator, in order to acquire new understandings of the LSP-injection process. Our coupled numerical simulator integrates the MATLAB-Reservoir-Simulation Toolbox (MRST) with the geochemical-software IPhreeqc. This study investigates the effects of variations in water chemistry (salinity and hardness), permeability, and polymer hydrolysis on polymer viscosity and adsorption through mechanistic modeling of the LSP process using the MRST-IPhreeqc coupled simulator. In this sensitivity analysis, the various injected water salinity and hardness models were generated by spiking and diluting both the salinity and the hardness of the baseline model by 3-, 5-, and 15-times each, and subsequently investigating their impact on polymer viscosity and adsorption. Furthermore, to evaluate the effect of various degrees of hydrolysis on polymer viscosity, we investigated the polymer hydrolysis degree of 30% (base-case), and then 15% and 80% polymer hydrolysis degrees. Next, the impact of different permeabilities on polymer adsorption was investigated for the base-case permeability (71 mD), low permeability (50 mD), and high permeability (150 mD) scenarios. A number of mineral dissolutions can occur in the PBR-system causing the calcium (Ca2+) and magnesium (Mg2+) ions to release, which then form polymer complexes to massively reduce the polymer-viscosity. Also, mechanical entrapment can lead to high polymer adsorption during LSP flooding. Based on the sensitivity analysis, the results of the investigation regarding the effect of salinity on polymer viscosity indicated that the scenario of 15-times spiked salinity (9345 ppm) is more beneficial than those of 5-times (3115 ppm) and 3-times (1869 ppm) spiked salinities, based on their corresponding polymer-viscosity losses of 8%, 10%, and 19%. The same effect was observed for the increase in hardness (Ca2+ + Mg2+) scenario where 15-times spiked hardness (165 ppm) is superior to the 5-times (55 ppm) and 3-times spiked (33 ppm) scenarios, based on their corresponding polymer-viscosity losses of 25%, 47%, and 52%. Similarly, examining the impact of polymer hydrolysis on polymer viscosity indicated that the viscosity of the polymer decreases as the degree of hydrolysis increases to 80% or decreases to 15%. Regarding the effect of salinity and hardness variations on polymer adsorption, the results showed that as the salinity and hardness increase, polymer adsorption increases too. Contrariwise, the diluted salinity and hardness solutions resulted in lower adsorption levels. In terms of the impact of permeability on polymer adsorption, mechanical entrapment causes the polymer adsorption to rise at a low permeability of 50 mD, and conversely, the adsorption starts to decline at high permeability of 150 mD. Finally, according to the CR calculations, if CR > 1, this implies low viscosity loss in the LSP-solution, which equates to the cation threshold concentration of 130 ppm. At CR < 0.5, the LSP-solution will likely have a significant decrease in viscosity. When 0.5 < CR < 1, additional assessment for risk of viscosity loss is needed. Therefore, the novel findings resulting from this study can help design more effective LSP-injection strategies at field-scale.
Novel Impressions of Hybrid Low Salinity Polymer (LSP) Injection: A Geochemical Modeling Study
The hybrid Enhanced Oil Recovery (EOR) method of Low Salinity Polymer (LSP) injection is an advanced synergetic coalescence with remarkable additional oil recovery capability. Several studies have reported that the LSP process significantly enhances polymer rheology and viscoelasticity, along with improving the injectivity and displacement efficiency. However, to accurately simulate and capture the complex geochemistry of the Polymer-Brine-Rock (PBR) system during LSP-injection, sophisticated mechanistic predictive models are required, which the literature rarely discusses. Therefore, we modeled the PBR-system interactions in this study, using our coupled numerical simulator, in order to acquire new understandings of the LSP-injection process. Our coupled numerical simulator integrates the MATLAB-Reservoir-Simulation Toolbox (MRST) with the geochemical-software IPhreeqc. This study investigates the effects of variations in water chemistry (salinity and hardness), permeability, and polymer hydrolysis on polymer viscosity and adsorption through mechanistic modeling of the LSP process using the MRST-IPhreeqc coupled simulator. In this sensitivity analysis, the various injected water salinity and hardness models were generated by spiking and diluting both the salinity and the hardness of the baseline model by 3-, 5-, and 15-times each, and subsequently investigating their impact on polymer viscosity and adsorption. Furthermore, to evaluate the effect of various degrees of hydrolysis on polymer viscosity, we investigated the polymer hydrolysis degree of 30% (base-case), and then 15% and 80% polymer hydrolysis degrees. Next, the impact of different permeabilities on polymer adsorption was investigated for the base-case permeability (71 mD), low permeability (50 mD), and high permeability (150 mD) scenarios. A number of mineral dissolutions can occur in the PBR-system causing the calcium (Ca2+) and magnesium (Mg2+) ions to release, which then form polymer complexes to massively reduce the polymer-viscosity. Also, mechanical entrapment can lead to high polymer adsorption during LSP flooding. Based on the sensitivity analysis, the results of the investigation regarding the effect of salinity on polymer viscosity indicated that the scenario of 15-times spiked salinity (9345 ppm) is more beneficial than those of 5-times (3115 ppm) and 3-times (1869 ppm) spiked salinities, based on their corresponding polymer-viscosity losses of 8%, 10%, and 19%. The same effect was observed for the increase in hardness (Ca2+ + Mg2+) scenario where 15-times spiked hardness (165 ppm) is superior to the 5-times (55 ppm) and 3-times spiked (33 ppm) scenarios, based on their corresponding polymer-viscosity losses of 25%, 47%, and 52%. Similarly, examining the impact of polymer hydrolysis on polymer viscosity indicated that the viscosity of the polymer decreases as the degree of hydrolysis increases to 80% or decreases to 15%. Regarding the effect of salinity and hardness variations on polymer adsorption, the results showed that as the salinity and hardness increase, polymer adsorption increases too. Contrariwise, the diluted salinity and hardness solutions resulted in lower adsorption levels. In terms of the impact of permeability on polymer adsorption, mechanical entrapment causes the polymer adsorption to rise at a low permeability of 50 mD, and conversely, the adsorption starts to decline at high permeability of 150 mD. Finally, according to the CR calculations, if CR > 1, this implies low viscosity loss in the LSP-solution, which equates to the cation threshold concentration of 130 ppm. At CR < 0.5, the LSP-solution will likely have a significant decrease in viscosity. When 0.5 < CR < 1, additional assessment for risk of viscosity loss is needed. Therefore, the novel findings resulting from this study can help design more effective LSP-injection strategies at field-scale.
An Experimental Investigation of Surface Chemistry of Rocks in the Presence of Surfactants
Surfactant flooding is a well-known chemical enhanced oil recovery (cEOR) technique. However, surfactant surface chemistry and the associated interactions with rock surfaces are complex and have not been fully investigated. Here, we experimentally investigate the surface chemistry of 15 rock surfaces (10 carbonate and 5 sandstones) upon interaction with different types of surfactants, including cationic, anionic, non-ionic, and zwitterionic surfactants at different concentrations (before, at, and after the critical micelle concentration, CMC). The rock samples were examined using Scanning Electron Microscopy (SEM) to investigate their structure and surface morphology. To understand the interactions at the surfactant-mineral interface and surfactant behavior, the zeta potential measurements of surfactant-brine-rock emulsions were performed, while surface chemical functional groups were identified by Fourier-transform infrared (FTIR) spectroscopy. The zeta potential results show that both anionic (SDS) and cationic (CTAB) surfactants depict better stability, in carbonates and sandstones, compared to the non-ionic (Triton X-100) and zwitterionic (3- (N, N-Dimethylmyristylammonio) surfactants, which is due to the nature of the charge of each surfactant. Also, the FITR results indicate the existence of different chemical bonds and functional groups at different concentrations for each surfactant type, and the magnitude of these bonds differs as a function of rock type and mineralogy. For instance, the rock samples treated with CTAB cationic surfactant reveal the presence of C-O, Mg-C, and Ca-C groups at all concentrations. However, despite being present at all concentrations, these responses show different magnitudes at different surfactant concentrations. The results of this study provide valuable data set to understand the surfactant surface chemistry interactions with different carbonate and sandstone rock surfaces and thus have direct implications for chemical enhanced oil recovery.
Modeling of Low Salinity Polymer (LSP) Interactions in Carbonates from Geochemical and Surface Chemistry Perspectives
Low Salinity Polymer (LSP) injection is a hybrid synergistic enhanced oil recovery (EOR) technique that improves displacement and sweep efficiencies by combining the advantages of both low salinity and polymer flooding methods. Nevertheless, proper design of LSP flooding at field-scale requires a predictive mechanistic model that captures polymer-brine-rock (PBR) interactions. Therefore, this study investigates the impact of water chemistry on polymer behavior in porous media in order to gain a better understanding of the PBR-system. In particular, we examine the effect of salinity and hardness on polymer viscosity and adsorption in dolomite formations during LSP flooding employing our in-house coupled MRST-IPhreeqc simulator. Furthermore, to capture the geochemistry of the LSP process, the MRST-IPhreeqc simulator incorporates surface complexation reactions as well as aqueous, mineral dissolution and/or precipitation reactions. The findings of this study suggest that the 5-times spiked salinity and hardness scenarios are more favorable than those of 10-times spiked salinity and hardness, which were supported by their respective polymer viscosity losses of 75% and 82% for salinity spiking, and 58% and 63% for hardness spiking. Also, the effects of 10-times spiked Ca2+, 10-times spiked Mg2+, and 2-times spiked SO42-on polymer viscosity were studied with estimated viscosity losses of 61%, 61%, and 46%, respectively. The latter signifies the importance of sulfate spiking for reducing polymer viscosity loss while avoiding exceeding sulfate limit for scale formation and reservoir souring. For the effect of salinity on polymer adsorption, it was observed that the increase in salinity from the base case scenario (623 ppm) to 5- and 10-times spiked salinity, results in an increase in the dynamic polymer adsorption from 53 μg/g-rock to 59 and 68 μg/g-rock, respectively. Additionally, comparing the 10-times spiked Mg2+, 10-times spiked Ca2+, and the 2-times spiked SO42- scenarios, the 10-times spiked Mg2+ case resulted in the maximum polymer adsorption (87 μg/g-rock). This is due to the surface complexation reactions of magnesium surface species at dolomite rock surface with polymer molecules forming Mg-polymer surface complexes. In contrast, the calcium and sulfate do not form surface complexes through reactions with the polymer. This indicated that the divalent cation's design might impact the viscosity of the LSP solution, and therefore, it is crucial to carefully consider it when optimizing the LSP process in carbonates. Thus, proper design of LSP flooding at field-scale requires a predictive mechanistic model that captures PBR interactions which is covered in this work.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
Contact Info
customersupport@researchsolutions.com
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Product
Resources
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.
