Day 1 Mon, April 25, 2022最新文献

{"title":"Polymer Selection for Sandstone Reservoirs Using Heterogeneous Micromodels, Field Flow Fractionation and Corefloods","authors":"Ante Borovina, R. E. H. Reina, T. Clemens, E. Hoffmann, J. Wegner, J. Steindl","doi":"10.2118/209352-ms","DOIUrl":"https://doi.org/10.2118/209352-ms","url":null,"abstract":"\u0000 Incremental oil recovery due to polymer flooding results from acceleration of oil production along flow paths and improving sweep efficiency. To achieve favorable economics, polymers should have a high viscosifying power and low adsorption. However, in addition, incremental oil production from various rock qualities needs to be maximized. We developed a workflow using a layered micromodel, corefloods and Field-Flow Fractionation (FFF) to determine the Molecular Weight Distribution (MWD) for the selection of polymers addressing heterogeneous reservoirs.\u0000 We have designed micromodels consisting of two layers with different permeabilities, one four times larger than the other. The micromodel structure is based on the characteristics of a real sandstone core, with the dimensions 6 cm × 2 cm. These micromodels were used as preliminary screening of the polymers incorporating heterogeneity effects. Subsequently, single- and two-phase core experiments were performed to determine injectivity effects and displacement efficiency of the selected polymers. In addition, FFF was used to measure the molecular weight distribution, gyration radii and conformance of the polymers. Based on the workflow a polymer was selected.\u0000 All polymers were tested at target viscosity at 7 1/s shear rate. Micromodel experiments showed that tested polymers are leading to improved sweep efficiency of heterogeneous structure. The displacement efficiency within the higher permeable layer was similar for the investigated polymers whereas the oil recovery from the lower permeable layer showed differences. FFF revealed that the MWD's of the tested polymers were different. The MWD of one of the polymers showed a large number of larger molecules compared with the other polymers. This polymer did not lead to the highest oil recovery in the micromodel. Injectivity and propagation of the higher MW polymer in both single- and two-phase core-floods was falling behind the other polymers. Measurements of the MWD of the core effluent showed that for all tested polymers the larger molecules are initially retained more than the smaller molecules. The polymer with the smallest molecules and narrow MWD showed the best propagation characteristics in the core.\u0000 Owing to the good performance of this polymer in terms of sweep efficiency improvement, injectivity, and propagation, this polymer was selected for a field application. Therefore, the novelty presented here can be summarised as follow:\u0000 Heterogeneous micromodels were used to screen polymers for one-dimensional displacement efficiency and sweep efficiency effects Single- and two-phase core floods in combination with Field-Flow Fractionation revealed the impact of the molecular weight distribution (MWD) on polymer injectivity, propagation and retention Selection of polymers need to include MWD to find the most effective polymer Polymer selection needs to take near-wellbore and reservoir effects (micro- and sweep efficiency in heterogeneous reser","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80426879","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Oil Recovery Prediction for Polymer Flood Field Test of Heavy Oil on Alaska North Slope Via Machine Assisted Reservoir Simulation","authors":"C. Keith, Xindan Wang, Yin Zhang, A. Dandekar, S. Ning, Dongmei Wang","doi":"10.2118/209443-ms","DOIUrl":"https://doi.org/10.2118/209443-ms","url":null,"abstract":"\u0000 The first ever polymer flood field pilot to enhance the recovery of heavy oils on the Alaska North Slope is ongoing. This study constructs and calibrates a reservoir simulation model to predict the oil recovery performance of the pilot through machine-assisted reservoir simulation techniques. To replicate the early water breakthrough observed during waterflooding, transmissibility contrasts are introduced into the simulation model, forcing viscous fingering effects. In the ensuing polymer flood, these transmissibility contrasts are reduced to replicate the restoration of injection conformance during polymer flooding, as indicated by a significant decrease in water cut. Later, transmissibility contrasts are reinstated to replicate a water surge event observed in one of the producing wells during polymer flooding. This event may represent decreased injection conformance from fracture overextension; its anticipated occurrence in the other production well is included in the final forecast. The definition of polymer retention in the simulator incorporates the tailing effect reported in laboratory studies; this tailing effect is useful to the simultaneous history match of producing water cut and produced polymer concentration. The top 24 best-matched simulation models produced at each stage of the history matching process are used to forecast oil recovery. The final forecast clearly demonstrates that polymer flooding significantly increases the heavy oil production for this field pilot compared to waterflooding alone. This exercise displays that a simulation model is only valid for prediction if flow behavior in the reservoir remains consistent with that observed during the history matched period. Critically, this means that a simulation model calibrated for waterflooding may not fully capture the benefits of an enhanced oil recovery process such as polymer flooding. Therefore, caution is recommended in using basic waterflood simulation models to scope potential enhanced oil recovery projects.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82701481","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Use of Horizontal Injectors for Improving Injectivity and Conformance in Polymer Floods","authors":"Jongsoo Hwang, Shuang Zheng, M. Sharma, Maria-Magdalena Chiotoroiu, T. Clemens","doi":"10.2118/209373-ms","DOIUrl":"https://doi.org/10.2118/209373-ms","url":null,"abstract":"\u0000 Several field cases have demonstrated polymer injection in a horizontal well increases oil recovery. It is important to maintain high injectivity while preventing injection-induced fractures to ensure good reservoir sweep. Our primary goal in this paper is to better understand polymer injection data from horizontal injectors in the Matzen field using a fully integrated reservoir, geomechanics, and fracturing model.\u0000 By simulating polymer injection history, we present several advantages of horizontal injectors over the vertical wells. Horizontal injectors delay fracture initiation and provide better tolerance to polymer plugging on the wellbore surface. Simulations explain the measured PLT data of fluid distributions influenced by accumulated polymer deposition in multiple zones. We show that gradual injectivity decline is attributed to both polymer filter cake buildup and high-viscosity, shear-thickening zones created around the wellbore. The field case simulation also clarifies the flow distribution in different sands and how polymer rheology affects this. This distribution is found to be different than for water injection.\u0000 Results from periodic acid treatments clearly show that free-flowing particles in the polymer solution are responsible for formation damage. Polymer plugging and the viscous pressure drop in the shear-thickening zone are the primary factor affecting the measured injection pressure. Based on the strong near-wellbore viscosity impact, geomechanical simulations identify reservoir zones prone to fracture growth during long-term injection, and we suggest strategies to avoid injection induced fractures that can lead to poor conformance.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"73 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73489331","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Selective Crystallization - En Route to In-Situ Deep Conformance Control","authors":"Ali Binabdi, Subash Ayirala, Ahmed Gmira, T. Sølling","doi":"10.2118/209405-ms","DOIUrl":"https://doi.org/10.2118/209405-ms","url":null,"abstract":"\u0000 We have investigated the interfacial properties at a brine-hydrocarbon boundary with the prospect of understanding the crystallization process that takes place when certain electrolytes are present in the brine and when certain surfactants are present in the hydrocarbon phase. This was done in an optical force tensiometer setup with a so-called buoyant droplet configuration. It is only specific combinations (that is not all surfactants not all electrolytes) that form crystals and we aim at utilizing this specificity to form crystal plugs in particular sections of an oil reservoir, for example in zones with high flow that can then be reduced by the crystal plugs. The treatment can potentially be tailored based on the predominant acid-type in a mixture. The current study reveals several (at least three) different modes of crystal formation. The electrolyte-surfactant combination that gives rise to the most clear-cut formation of crystals directly at the interface is involving Zn2+ or Cu2+ and dodecanoic acid (C11H23COOH). Several of the systems under study appears to be forming crystals within the hydrocarbon phase and that these crystals more the likely are a result of the surfactant associated diffusive transfer of cations into the hydrocarbon phase. The next short-term goal is to induce crystals when the hydrocarbon phase is (potentially spiked) crude oil to tailor the discoveries towards the longer-term goal: In-situ deep conformance control field applications.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"16 6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78469411","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Nanoparticle Stabilized Strong Foam for EOR in High Salinity Fractured Carbonate Reservoirs","authors":"Wang Xuezhen, Mohanty K Kishore","doi":"10.2118/209435-ms","DOIUrl":"https://doi.org/10.2118/209435-ms","url":null,"abstract":"\u0000 Foam flooding can minimize bypassing in gas floods in fractured reservoirs. Finding a good foam formulation to apply in high salinity reservoirs is challenging, especially with divalent cations, e.g., API brine (8% NaCl with 2% CaCl2). When formulating with nanoparticles, the colloidal dispersion stability is difficult due to the dramatic reduction of the Debye length at high salinity. The aim of this work was to develop a strong foam in API brine, using nonionic surfactant (SF) and ethyl cellulose nanoparticles (ECNP), for gas flooding in fractured carbonate reservoirs. ECNP particles were synthesized and dispersed in API brine using a nonionic surfactant (SF). SF and SF/ECNP foams were created and their stability was studied at atmospheric pressure and 950 psi. Foam mobility was measured in a sand pack at the high pressure. Foam flood experiments were conducted in oil saturated fractured carbonate cores. The nonionic surfactant was proven to be a good dispersion agent for ECNP in API brine. Moreover, the SF-ECNP stabilized foam in API brine, even in the presence of oil. The foam was found to be shear-thinning during flow through sand packs. Core floods showed that SF/ECNP foam recovered 81.6% of the oil from the matrix, 13.8% more oil than the surfactant only foam, indicating the synergy between ECNP and surfactant. ECNP accumulates in the foam lamella and induces larger pressure gradients in the fracture to divert more gas into the matrix for oil displacement.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81689974","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Bioremediation by Indigenous Microbes: A Green Approach to Degrade Polymer Residue","authors":"Songyuan Liu, Bo Lu, Chao-yu Sie, Yifan Li","doi":"10.2118/209422-ms","DOIUrl":"https://doi.org/10.2118/209422-ms","url":null,"abstract":"\u0000 Polyacrylamide-based friction reducer is commonly used in well completion for unconventional reservoirs. However, residual polymer trapped in the near well-bore region could create unintended flow restrictions and could negatively impact oil production. An eco-friendly approach to regain conductivity was developed by stimulating indigenous bacteria for residual polymer biodegradation.\u0000 In this work, a series of laboratory experiments were conducted using produced water and oil from Permian Basin, polyacrylamide-based polymer, and a modified nutrient recipe that contained 100 to 300 ppm of inorganic salts. The sealed sample vials containing water, oil, and polymer were prepared in a sterilized anaerobic chamber and then kept in a 160° F incubator to simulate the reservoir condition. Feasibility tests of bacteria growth and biodegradation evaluation of polymer were conducted using an optical laser microscopic system with bacteria tagged with fluorescent dye. Size regression was calculated and applied to a mathematical model based on actual fracture aperture distribution data from shale formation.\u0000 The indigenous bacteria were successfully stimulated with and without the existence of the friction reducer. It was observed that the size of polymer particles decreased from over 300 µm to less than 20 µm after 15 days. Under the condition of produced water injection, 140° F reservoir temperature, and anaerobic environment, about 30% of the natural fractures in shale were calculated to be damaged and remediated within 15 days.\u0000 This work is a pioneer research on microbial EOR application in unconventional reservoirs with only indigenous bacteria involved. In field applications, only an extremely low amount of nutrient is required in this process which provides great economic potential. Additionally, the nutrients introduced into the reservoirs will be fully consumed by bacteria during treatment, and the bacteria will be decomposed into organic molecules soon after the treatment. Thus, this technique is environmental- and economical- friendly for the purpose of polymer damage remediation to maximize the recoverable.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89339181","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Evaluation of Carbon Footprint for a Hydrocarbon Foam EOR Field Pilot","authors":"Orlando Castellanos Diaz, Amit Katiyar, A. Hassanzadeh, Matthew S Crosley, Troy Knight, P. Rozowski","doi":"10.2118/209366-ms","DOIUrl":"https://doi.org/10.2118/209366-ms","url":null,"abstract":"\u0000 EOR intervention methods, such as surfactant injection for in-situ foam as a conformance improvement, help increase energy efficiency of the EOR process. However, it is very important to have a calculation framework that identifies actual values to these energy efficiency benefits and contrast them with the energy requirements of making the EOR intervention methods work in the field. Such a calculation framework was introduced in this work with a life cycle thinking approach. To showcase the calculation methodology, a foam assisted gas-EOR process trial was used as an example of a successful EOR intervention technology, specifically a field pilot from a trial between Dow Chemical and MD America Energy (SPE 201199). Injection and production data, together with industry averages on electricity generation, gas compression, and water treatment, were utilized to calculate energy input into the process prior, during, and post-trial. Energy differences due to the foam technology deployment were translated into carbon footprint equivalence and contrasted with the carbon footprint of manufacturing and transporting the surfactant. A benefit-to-burden carbon footprint ratio of 21 was obtained, which means that for every carbon units emitted while producing the foaming agent 21 carbon units would be saved when implementing the technology as opposed to not implementing it. On a per barrel basis, the carbon footprint of the technology is reduced by more than 50% when using the foam additive than the baseline, even including the carbon footprint of making the material. The calculations also showed that the gas compression and separation steps dominate the energy inputs of the EOR intervention method.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90023501","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Comprehensive Evaluation of a Novel Recrosslinkable Hyper Branched Preformed Particle Gels for the Conformance Control of High Temperature Reservoirs","authors":"T. Song, Mohamed Ahdaya, Shuda Zhao, Yang Zhao, T. Schuman, B. Bai","doi":"10.2118/209451-ms","DOIUrl":"https://doi.org/10.2118/209451-ms","url":null,"abstract":"\u0000 The existence of high conductivity features such as fractures, karst zones, and void space conduits can severely restrict the sweep efficiency of water or polymer flooding. Preformed particle gel (PPG), as a cost-effective technology, has been applied to control excessive water production. However, conventional PPG has limited plugging efficiency in high-temperature reservoirs with large fractures or void space conduits. After water breakthrough, gel particles can easily be washed out from the fractures due to the lack of particle-particle association and particle-rock adhesion. This paper presents a comprehensive laboratory evaluation of a novel water-swellable high-temperature resistant hyper-branched re-crosslinkable preformed particle gel (HT-BRPPG) designed for North Sea high-temperature reservoirs (130 °C), which can re-crosslink to form a rubber-like bulk gel to plug such high conductivity features. This paper systematically evaluated the swelling kinetics, long-term thermal stability and plugging performance of the HT-BRPPG. Bottle tests were employed to test the swelling kinetic and re-crosslinking behavior. High-pressure resistant glass tubes were used to test the long-term thermal stability of the HT-BRPPG at different temperatures, and the testing lasted for over one year. The plugging efficiency was evaluated by using a fractured model. Results showed that this novel HT-BRPPG could re-crosslink and form a rubber-like bulky gel with temperature ranges from 80 to 130 °C. The elastic modulus of the re-crosslinked gel can reach up to 830 Pa with a swelling ratio of 10. In addition, the HT-BRPPG with a swelling ratio of 10 has been stable for over 15 months at 130 °C so far. The core flooding test proved that the HT-BRPPG could efficiently plug the open fractures, and the breakthrough pressure is 387.9 psi/ft. Therefore, this novel BRPPG could provide a solution to improve the conformance of high-temperature reservoirs with large fractures or void space conduits.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80270496","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Pressure Barrier Applicability to Polymer Flood Design","authors":"Dongmei Wang, S. Namie, R. Seright","doi":"10.2118/209462-ms","DOIUrl":"https://doi.org/10.2118/209462-ms","url":null,"abstract":"\u0000 Effective oil displacement from a reservoir requires adequate and properly directed pressure gradients in areas of high oil saturation. If the polymer bank is too large or too viscous during a polymer flood, the pressure drop from the injection well to the polymer front may act as a pressure barrier by usurping most of the downstream driving force for oil displacement. Polymer injection pressures must be limited. The maximum allowable injection pressure is commonly constrained by caprock integrity, injection equipment, and/or regulations, even though fractures can be beneficial to polymer injectivity (and even sweep efficiency in some cases). This paper examines when the pressure-barrier concept limits the size and viscosity of the polymer bank during a polymer flood.\u0000 Both analytical and numerical methods are used to address this issue. We examine the relevance of the pressure barrier concept for a wide variety of circumstances, including oil viscosities ranging from 10-cp (like at Daqing, China) to 1650-cp (like at Pelican Lake, Alberta), vertical wells (like at Tambaredjo, Suriname) versus horizontal wells (like at Milne Point, Alaska), single versus multiple layered reservoirs, permeability contrast, and with versus with crossflow between layers. We also examine the relation between the pressure-barrier concept and fractures and fracture extension during polymer injection.\u0000 We demonstrate that in reservoirs with single layers, the pressure-barrier concept only limits the optimum viscosity of the injected polymer if the mobility of the polymer bank is less than the mobility of the displaced oil bank. The same is true for multi-zoned reservoirs with no crossflow between layers. Thus, for these cases, the optimum polymer viscosity is likely to be dictated by the mobility of the oil bank, unless other factors (like fracture extension) intervene. For multi-zoned reservoirs with free crossflow between layers, the situation is different. A compromise must be reached between injected polymer viscosity and the efficiency of oil recovery. The relevance of our findings is applied to operations for several existing polymer floods. This work is particularly relevant to viscous-oil reservoirs (like Pelican Lake and others) where the injected polymer viscosities are substantially lower than the oil viscosity","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"69 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78312399","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Fast Screening of LSW Brines Using QCM-D and Crude Oil-Brine Interface Analogs","authors":"M. Yutkin, K. Kaprielova, S. Kamireddy, A. Gmira, S. Ayirala, S. Aramco, C. Radke, Kaust T.W. Patzek","doi":"10.2118/209389-ms","DOIUrl":"https://doi.org/10.2118/209389-ms","url":null,"abstract":"\u0000 This work focuses on a potentially economic incremental oil-recovery process, where a brine amended with inexpensive salts (in contrast to expensive surfactants and other chemicals) is injected into a reservoir to increase oil production. Historically, this process received the name of low salinity waterflooding (LSW) although the salinity is not always low(er). Nevertheless, we keep using this terminology for historical reasons.\u0000 The idea of LSW has been known for three decades, but to the best of our knowledge no specific brine recipes that guarantee success have been presented so far. The reasons hide in the problem's complexity, disagreements in the scientific community, and a race to publish rather than to understand the fundamental principles behind the process.\u0000 In this paper, we present an experimental model system that captures many of the important fundamental features of the natural process of crude oil attachment to mineral surfaces, but at the same time decomposes this complex process into simpler parts that can be more precisely controlled and understood. We systematically investigate the first-order chemical interactions contributing to the well-known strong attachment of crude oil to minerals using SiO2 as a mineral for its surface chemistry simplicity.\u0000 Our preliminary results suggest that magnesium and sulfate ions are potent in detaching amino/ammonium-based linkages of crude oil with a SiO2 surface. However, when used together in the form of MgSO4, they lose part of their activity to the formation of a MgSO4 ion pairs. We also find that sulfate-detachment propensity stems not from the interaction with prototype mineral surface, but rather from the interactions with the crude oil-brine interface analog. We continue the systematic study of the ion effects on crude oil detachment, with and more results following in the future.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"386 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86819891","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}