Compositional Modeling of Dissolution-Induced Injectivity Alteration During CO2 Flooding in Carbonate Reservoirs

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 0809-0826 ◽  
Author(s):  
C.. Qiao ◽  
L.. Li ◽  
R. T. Johns ◽  
J.. Xu
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Reactive Transport ◽  
Co2 Flooding ◽  
Formation Water ◽  
Compositional Modeling ◽  
Well Integrity ◽  
Water Alternating Gas ◽  
Geochemical Reactions ◽  
Porosity And Permeability

Summary Geochemical reactions between fluids and carbonate rocks can change porosity and permeability during carbon dioxide (CO2) flooding, which may significantly affect well injectivity, well integrity, and oil recovery. Reactions can cause significant scaling in and around injection and production wells, leading to high operating costs. Dissolution-induced well-integrity issues and seabed subsidence are also reported as a substantial problem at the Ekofisk field. Furthermore, mineral reactions can create fractures and vugs that can cause injection-conformance issues, as observed in experiments and pressure transients in field tests. Although these issues are well-known, there are differing opinions in the literature regarding the overall impacts of geochemical reactions on permeability and injectivity for CO2 flooding. In this research, we develop a new model that fully couples reactive transport and compositional modeling to understand the interplay between multiphase flow, phase behavior, and geochemical reactions under reservoir and injection conditions relevant in the field. Simulations were carried out with a new in-house compositional simulator on the basis of an implicit-pressure/explicit-composition and finite-volume formulation that is coupled with a reactive transport solver. The compositional and geochemical models were validated separately with CMG-GEM (CMG 2012) and CrunchFlow (Steefel 2009). Phase-and-chemical equilibrium constraints are solved simultaneously to account for the interaction between phase splits and chemical speciation. The Søreide and Whitson (1992) modified Peng-Robinson equation of state is used to model component concentrations present in the aqueous and hydrocarbon phases. The mineral-dissolution reactions are modeled with kinetic-rate laws that depend on the rock/brine contact area and the brine geochemistry, including pH and water composition. Injectivity changes caused by rock dissolution and formation scaling are investigated for a five-spot pattern by use of several common field-injection conditions. The results show that the type of injection scheme and water used (fresh water, formation water, and seawater) has a significant impact on porosity and permeability changes for the same total volume of CO2 and water injected. For continuous CO2 injection, very small porosity changes are observed as a result of evaporation of water near the injection well. For water-alternating-gas (WAG) injection, however, the injectivity increases from near zero to 50%, depending on the CO2 slug size, number of cycles, and the total amount of injected water. Simultaneous water-alternating-gas injection (SWAG) shows significantly greater injectivity increases than WAG, primarily because of greater exposure time of the carbonate surface to CO2-saturated brine coupled with continued displacement of calcite-saturated brine. For SWAG, carbonate dissolution occurs primarily near the injection well, extending to larger distances only when the specific surface area is small. Formation water and seawater lead to similar injectivity increases. Carbonated waterflooding (a special case of SWAG) shows even greater porosity increases than SWAG because more water is injected in this case, which continuously sweeps out calcite-saturated brine. The minerals have a larger solubility in brine than in fresh water because of the formation of aqueous complexes, leading to more dissolution instead of precipitation. Overall, this research points to the importance of considering the complex process coupling among multiphase flow, transport, phase behavior, and geochemical reactions in understanding and designing schemes for CO2 flooding as well as enhanced oil recovery at large.

A Numerical Investigation of Low Salinity Polymer Flooding Effects from a Geochemical Perspective

2021 ◽  
Author(s):  
Omar Chaabi ◽  
Emad W. Al-Shalabi ◽  
Waleed Alameri
Keyword(s):  
Aqueous Phase ◽  
Oil Recovery ◽  
Reactive Transport ◽  
History Matching ◽  
Solution Chemistry ◽  
Related Effect ◽  
Exchange Reactions ◽  
Two Phase ◽  
Low Salinity ◽  
Geochemical Reactions

Abstract Low salinity polymer (LSP) flooding is getting more attention due to its potential of enhancing both displacement and sweep efficiencies. Modeling LSP flooding is challenging due to the complicated physical processes and the sensitivity of polymers to brine salinity. In this study, a coupled numerical model has been implemented to allow investigating the polymer-brine-rock geochemical interactions associated with LSP flooding along with the flow dynamics. MRST was coupled with the geochemical software IPhreeqc. The effects of polymer were captured by considering Todd-Longstaff mixing model, inaccessible pore volume, permeability reduction, polymer adsorption as well as salinity and shear rate effects on polymer viscosity. Regarding geochemistry, the presence of polymer in the aqueous phase was considered by adding a new solution specie and related chemical reactions to PHREEQC database files. Thus, allowing for modeling the geochemical interactions related to the presence of polymer. Coupling the two simulators was successfully performed, verified, and validated through several case studies. The coupled MRST-IPhreeqc simulator allows for modeling a wide variety of geochemical reactions including aqueous, mineral precipitation/dissolution, and ion exchange reactions. Capturing these reactions allows for real time tracking of the aqueous phase salinity and its effect on polymer rheological properties. The coupled simulator was verified against PHREEQC for a realistic reactive transport scenario. Furthermore, the coupled simulator was validated through history matching a single-phase LSP coreflood from the literature. This paper provides an insight into the geochemical interactions between partially hydrolyzed polyacrylamide (HPAM) and aqueous solution chemistry (salinity and hardness), and their related effect on polymer viscosity. This work is also considered as a base for future two-phase polymer solution and oil interactions, and their related effect on oil recovery.

Nanopore Compositional Modeling in Unconventional Shale Reservoirs

2016 ◽  
Vol 19 (03) ◽  
pp. 415-428 ◽  
Author(s):  
Najeeb S. Alharthy ◽  
Tadesse W. Teklu ◽  
Thanh N. Nguyen ◽  
Hossein Kazemi ◽  
Ramona M. Graves
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Flow Characteristics ◽  
Gas Production ◽  
Eagle Ford ◽  
Compositional Modeling ◽  
Shale Reservoirs ◽  
Behavior Shift

Summary Understanding the mechanism of multicomponent mass transport in the nanopores of unconventional reservoirs, such as Eagle Ford, Niobrara, Woodford, and Bakken, is of great interest because it influences long-term economic development of such reservoirs. Thus, we began to examine the phase behavior and flow characteristics of multicomponent flow in primary production in nanoporous reservoirs. Besides primary recovery, our long-term objectives included enhanced oil production from such reservoirs. The first step was to evaluate the phase behavior in nanopores on the basis of pore-size distribution. This was motivated because the physical properties of hydrocarbon components are affected by wall proximity in nanopores as a result of van der Waals molecular interactions with the pore walls. For instance, critical pressure and temperature of hydrocarbon components shift to lower values as the nanopore walls become closer. In our research, we applied this kind of critical property shift to the hydrocarbon components of two Eagle Ford fluid samples. Then, we used the shifted phase characteristics in dual-porosity compositional modeling to determine the pore-to-pore flow characteristics, and, eventually, the flow behavior of hydrocarbons to the wells. In the simulation, we assigned three levels of phase behavior in the matrix and fracture pore spaces. In addition, the flow hierarchy included flow from matrix (nano-, meso-, and macropores) to macrofractures, from macrofractures to a hydraulic fracture (HF), and through the HF to the production well. From the simulation study, we determined why hydrocarbon fluids flow so effectively in ultralow-permeability shale reservoirs. The simulation also gave credence to the intuitive notion that favorable phase behavior (phase split) in the nanopores is one of the major reasons for production of commercial quantities of light oil and gas from shale reservoirs. It was determined that the implementation of confined-pore and midconfined-pore phase behavior lowers the bubblepoint pressure, and this, in turn, leads to a slightly higher oil recovery and lesser gas recovery. Also it was determined that the implementation of midconfined-pore and confined-pore phase-behavior shift reduces the retrograde liquid-condensation region, which in turn, leads to lower liquid yield while maintaining the same gas-production quantity. Finally, the important reason that we are able to produce shale reservoirs economically is “rubblizing” the reservoir matrix near HFs, which creates favorable permeability pathways to improve reservoir drainage. This is why multistage hydraulic fracturing is so critical for successful development of shale reservoirs.

Sequential Coupling of Geochemical Reactions With Reservoir Simulations for Waterflood and EOR Studies

SPE Journal ◽  
2012 ◽  
Vol 17 (02) ◽  
pp. 469-484 ◽  
Author(s):  
Lingli Wei
Keyword(s):  
Water Chemistry ◽  
Oil Recovery ◽  
Reactive Transport ◽  
Produced Water ◽  
Mineral Dissolution ◽  
Individual Species ◽  
Chemical Changes ◽  
Injection Water ◽  
Geochemical Reactions ◽  
The Impact

Summary Many waterflood projects now experience significant amounts of water cut, with more water than hydrocarbon flowing between the injectors and producers. In addition to the impact on water viscosity and density that results from using different injection-water sources during a field's life, water chemistry itself may impact oil recovery, as demonstrated by recent research on low-salinity water-injection schemes. It is also known that water chemistry has a profound impact on various chemical enhanced-oil-recovery (EOR) processes. Moreover, the effectiveness and viability of such EOR schemes is strongly dependent on reservoir-brine and injection-water compositions. In particular, the presence of divalent cations such as Ca+2 and Mg+2 has a significantly adverse effect for chemical EORs. Using new developments in reservoir simulation, this paper outlines a method to couple geochemical reactions in a reservoir simulator in black-oil and compositional modes suitable for large-scale reservoir models for waterflood and EOR studies. The new multicomponent reactive-transport modeling capability considers chemical reactions triggered by injection water and/or injected reactive gases such as CO2 and H2S, including mineral dissolution and precipitation, cation exchange, and surface complexation. For waterflood-performance assessment, the new modeling capability makes possible a more-optimum evaluation of petrophysical logs for well intervals where injection-water invasion is suspected. By modeling transport of individual species in the aqueous phase from injectors to producers, reservoir characterization can also be improved through the use of these natural tracers, provided that the compositions of the actual produced water are used in the history matching. The simulated water compositions in producers can also be used by production chemists to assess scaling and corrosion risks. For CO2 EOR studies, we illustrate chemical changes inside a reservoir and in the produced water before and after CO2 breakthrough, and discuss geochemical monitoring as a potential surveillance tool. Alkaline-flood-induced water chemical changes and calcite precipitation are also presented to illustrate applicability for chemical EOR with the new simulation capability.

scholarly journals Simulation of Immiscible Water-Alternating-CO2 Flooding in the Liuhua Oilfield Offshore Guangdong, China

Energies ◽  
2020 ◽  
Vol 13 (9) ◽  
pp. 2130 ◽  
Author(s):  
Gang Hu ◽  
Pengchun Li ◽  
Linzi Yi ◽  
Zhongxian Zhao ◽  
Xuanhua Tian ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Carbon Capture ◽  
Co2 Storage ◽  
Simulation Models ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Full Field ◽  
Water Alternating Gas ◽  
Production History ◽  
And Storage

In this paper, the immiscible water-alternating-CO2 flooding process at the LH11-1 oilfield, offshore Guangdong Province, was firstly evaluated using full-field reservoir simulation models. Based on a 3D geological model and oil production history, 16 scenarios of water-alternating-CO2 injection operations with different water alternating gas (WAG) ratios and slug sizes, as well as continuous CO2 injection (Con-CO2) and primary depletion production (No-CO2) scenarios, have been simulated spanning 20 years. The results represent a significant improvement in oil recovery by CO2 WAG over both Con-CO2 and No-CO2 scenarios. The WAG ratio and slug size of water affect the efficiency of oil recovery and CO2 injection. The optimum operations are those with WAG ratios lower than 1:2, which have the higher ultimate oil recovery factor of 24%. Although WAG reduced the CO2 injection volume, the CO2 storage efficiency is still high, more than 84% of the injected CO2 was sequestered in the reservoir. Results indicate that the immiscible water-alternating-CO2 processes can be optimized to improve significantly the performance of pressure maintenance and oil recovery in offshore reef heavy-oil reservoirs significantly. The simulation results suggest that the LH11-1 field is a good candidate site for immiscible CO2 enhanced oil recovery and storage for the Guangdong carbon capture, utilization and storage (GDCCUS) project.

scholarly journals Experimental and simulation studies for optimization of water–alternating-gas (CO2) flooding for enhanced oil recovery

2020 ◽  
Vol 5 (3) ◽  
pp. 227-234
Author(s):  
Swapnil Pancholi ◽  
Gudendra Singh Negi ◽  
Jatin R. Agarwal ◽  
Achinta Bera ◽  
Maunish Shah
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Simulation Studies ◽  
Co2 Flooding ◽  
Water Alternating Gas

An Investigation of Phase Behavior-Macroscopic Bypassing Interaction in CO2 Flooding

1984 ◽  
Vol 24 (05) ◽  
pp. 508-520 ◽  
Author(s):  
J.W. Gardner ◽  
J.G.J. Ypma
Keyword(s):  
High Resolution ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Viscous Fingering ◽  
General Nature ◽  
Valuable Insight ◽  
Co2 Flooding ◽  
Mobile Water ◽  
First Contact ◽  
Theoretical Results

Abstract CO2-crude coreflood experiments and high-resolution 2-D CO2-crude displacement simulations in which viscous fingering is represented explicitly suggest that there is a synergistic interaction between multiple-contact CO2-crude phase behavior and macroscopic bypassing that causes the "ultimate" oil recovery (when the system has been swept) to be lower in the unstable case than in the stable case. Assuming this effect is present in field applications of CO2 flooding, then corefloods in which fingering is absent, for whatever reason, should not be used as direct indicators of field-scale displacement efficiency since they will yield optimistic predictions, all other factors being equal between the laboratory and the field. Introduction This paper presents results from one phase of a systematic Shell investigation aimed towards understanding mechanisms of viscous-dominated displacements of waterflood-residual, light, undersaturated crude oils by CO2 flooding (Fig. 1). A previous paper by Gardner, Orr, and Patel dealt with stable, paper by Gardner, Orr, and Patel dealt with stable, secondary (no mobile water) displacements of recombined Wasson crude. The present paper is concerned with unstable, secondary displacements of that same oil. In the previous study, potentially significant factors investigated were CO2-crude oil phase behavior, longitudinal dispersion, and relative permeability (as it turned out, relative permeability was of negligible importance). Bypassing was excluded. With the present work, we bring that factor into the picture. In particular, the added impact of macroscopic bypassing in the form of viscous fingering is examined. It should be noted, as indicated in Fig. 1, that neither the previous nor the present study addresses the effect of mobile water, examined on a separate branch of our overall program. The fact that gravity is neglected has already been implied by use of the term "viscous-dominated". Also excluded are the effects of severe heterogeneity Finally, the present investigation deals specifically only with what happens at a single pressure above the critical point on a pressure-CO2 concentration diagram. This in turn means above the so-called "minimum miscibility pressure", which cannot be greater than the pressure at the critical point. Nonetheless, we feel the results documented here provide valuable insight of a general nature into provide valuable insight of a general nature into the role of viscous instabilities in vaporizing gas drive type processes. They also bring up some important considerations involving finite lateral boundaries that should be borne in mind when designing and/or interpreting CO2 coreflood experiments. Both experimental and theoretical results are documented in this paper. The experimental results come from CO2-crude and first-contact miscible CO2-Soltrol TM corefloods. (Soltrol TM, or more specifically Soltrol TM 130, is a bottoms product of an alkylation unit and is manufactured by Phillips Petroleum Company. It has a normal boiling point range equivalent to that of C11-C14, and is composed of 99.9% t-butyl groups.) The major theoretical results reported in the paper are from high resolution, two-dimensional simulations of unstable CO2-crude and first-contact miscible displacements in which viscous fingering is represented explicitly. These simulations play a key role in interpreting the experiments. EXPERIMENTAL BASIS OF INVESTIGATION Secondary CO2-Wasson Crude and CO2-Soltrol TM Displacements in Berea Sandstone, Plus 1-D CO2-Wasson Crude Simulation; Phase Behavior-Bypassing Synergism Three sets of experimental data from the basis of the investigation documented here. First, data from CO2-Wasson crude and CO2-Soltrol TM secondary, viscous-dominated corefloods carried out at Shell, in conjunction with 1-D CO2-Wasson crude simulation results, suggest that the combination of multiple-contact CO2-crude phase behavior and macroscopic bypassing reduces not only the rate of oil recovery with throughput, but also the "ultimate" recovery. Evidence of this type is shown in Fig. 2. P. 163

The Impact of Oil Aromaticity on CO2, Flooding

1985 ◽  
Vol 25 (06) ◽  
pp. 865-874 ◽  
Author(s):  
T.G. Monger
Keyword(s):  
Experimental Data ◽  
Phase Equilibrium ◽  
Phase Behavior ◽  
Phase Formation ◽  
Oil Recovery ◽  
Solid Phase ◽  
Co2 Flooding ◽  
Asphaltene Precipitation ◽  
Equilibrium Studies ◽  
Oil Mixtures

Abstract This paper investigates the role of oil aromaticity in miscability development and in the deposition of heavy hydrocarbons during CO2, flooding. The results of phase equilibrium measurements, compositional studies, sandpack displacements, and consolidated corefloods are presented. Reservoir oil from the Brookhaven field and presented. Reservoir oil from the Brookhaven field and synthetic oils that model natural oil phase behavior are examined. Phase compositional analyses Of CO2/synthetic-oil mixtures in static PVT tests demonstrate that increased oil aromaticity correlates with improved hydrocarbon extraction into a CO2-rich phase. The results of tertiary corefloods performed with the synthetic oils show that CO2-flood oil displacement efficiency is also improved for the oil with higher aromatic content. These oil aromaticity influences are favorable. Reservoir oil experiments show that a significant deposition of aromatic hydrocarbon material occurs when CO2, contacts highly asphaltic crude. Solid-phase formation was observed in phase equilibrium and displacement studies and led to severe plugging during linear flow through Berea cores. It is unclear how this solid phase will affect oil recovery on a reservoir scale. Introduction Several reports suggest that oil aromaticity affects the CO2, displacement process of reservoir oil. Henry and Metcalfe noted the absence of multiple-liquid phase generation in displacement tests performed with a crude oil of low aromatic content. Holm and Josendal showed that when a highly paraffinic oil was enriched with aromatics, the slim-tube minimum miscibility pressure (MMP) decreased and oil recovery improved. Qualitative differences in the phase behavior of two crudes with contrasting aromatic contents prompted the suggestion by Monger and Khakoo that increased oil aromaticity correlates with improved hydrocarbon extraction into a CO2-rich phase. Clementz discussed how the adsorption of petroleum heavy ends, like the condensed aromatic ring structures found in asphaltenes, can alter rock properties. Laboratory studies have shown that improved oil properties. Laboratory studies have shown that improved oil recoveries in tertiary CO2 displacements benefited from changes in wetting behavior apparently, induced by asphaltene adsorption. Tuttle noted that CO2, appears to reduce asphaltene solubility and can cause rigid film formation. In these respects, oil aromaticity may also account for phase-behavior/oil-recovery synergism. Asphaltene deposition, though not a problem during primary and secondary recovery operations, was primary and secondary recovery operations, was reported in the Little Creek CO2 -injection pilot in Mississippi. Wettability alteration from asphaltene precipitation appears to have explained the results of low residual oil at high water-alternating-gas ratios in the Little Knife CO2, flood minitest in North Dakota. This paper provides detailed laboratory data from phase equilibrium measurements, compositional studies. sandpack displacements, and consolidated corefloods that illuminate the role of aromatics in miscibility development and in solid-phase formation during CO2 - flooding. The results for synthetic oils that model crude-oil behavior suggest that CO2-flood performance will benefit from increased oil aromaticity. The interpretation of reservoir oil results is more difficult. The precipitation of highly aromatic hydrocarbon material is observed when CO2, contacts Brookhaven crude. One purpose of this paper is to examine the variables that influence asphaltene precipitation. Near the wellbore, solid-phase formation might precipitation. Near the wellbore, solid-phase formation might reduce injectivity or impair production rates. Perhaps in other regions of the reservoir, altered permeability and/or wettability caused by solid-phase deposition might improve the ability of CO2, to contact oil. Additional work is needed to determine which potential benefits of oil aromaticity are significant on the reservoir scale. Advances in computer-implemented equations of state are making the prediction of CO2,/hydrocarbon phase behavior easier and more reliable. When an equation of state with CO2/reservoir-oil mixtures is used, an important consideration is the characterization of the heavy hydrocarbon components. One characterization method that appears to match the experimental data accurately in the critical point region for rich-gas/reservoir-oil mixtures is based on assigning separate paraffinic, aromatic, and naphthenic cuts. An additional aim of this study is to provide experimental data in assisting similar modeling provide experimental data in assisting similar modeling efforts for CO2/reservoir-oil mixtures. Experimental phase equilibrium data for mixtures containing CO2, and phase equilibrium data for mixtures containing CO2, and heavy hydrocarbons, particularly aromatics, are scarce. The behavior of multicomponent CO2,/hydrocarbon systems is not readily deduced from the phase equilibria of binary or ternary systems. Materials and Methods Phase Equilibrium Studies. A schematic diagram of the Phase Equilibrium Studies. A schematic diagram of the apparatus used in the phase-behavior experiments appears in Fig. 1. A detailed description of the equipment, procedures, chemicals, and analytical methods used is given procedures, chemicals, and analytical methods used is given in Ref. 10. SPEJ P. 865

Investigation of Smart Waterflooding in Sandstone Reservoirs: Experimental and Simulation Study Part 2

SPE Journal ◽  
2020 ◽  
Vol 25 (04) ◽  
pp. 1670-1680
Author(s):  
Hasan N. Al-Saedi ◽  
Ralph E. Flori ◽  
Mortadha Alsaba
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Reactive Transport ◽  
Transport Model ◽  
Divalent Cations ◽  
Surface Reactivity ◽  
Quartz Surface ◽  
Formation Water ◽  
Smart Water ◽  
Original Oil In Place

Summary In a previous work (Al-Saedi et al. 2018c), we studied the effect of mineral composition of cores (using synthetic columns with varying mineralogy) on low-salinity (LS) waterflooding, and we presented a reactive-transport model (RTM) for the water/rock interactions. The results showed that kaolinite has the strongest effect and then quartz because of the high kaolinite surface area, and the most effective complexes were >SiOH (hydroxylated Si), >AlO– (aluminum oxide complex on quartz surface), and >SiO– (silicon mono oxide complex on quartz surface). In this paper, we use the same Bartlesville Sandstone cores (constant mineralogy) for all cases to investigate the effect of water chemistry on water/rock interactions during seawater and smart waterflooding of reservoir sandstone cores containing heavy oil. Oil recovery, surface-reactivity tests, and multicomponent reactive-transport simulation using CrunchFlow (Steefel 2009) were conducted to better understand smart waterflooding. Bartlesville Sandstone cores were saturated with heavy oil and connate formation water. Secondary waterflooding of these cores with formation water (FW) at 25°C resulted in an ultimate oil recovery of approximately 50% original oil in place (OOIP) for all reservoir cores in this study. FW salinity was 104,550 ppm. FW was diluted twice to obtain Smart Water 1 (SMW1). SMW2 was similar to SMW1 but depleted in divalent cations (Ca2+ and Mg2+). SMW3 was also similar to SMW1 but depleted in Mg2+ and SO42−, whereas SMW4 was the same as SMW1 but Ca2+ was diluted 100 times. Seawater (SW) salinity was 48,300 ppm, which is close to the SMW salinity (52,275 ppm). No oil recovery was observed during SMW1 flooding, whereas softening SMW1 (SMW2) resulted in a significant additional oil recovery of OOIP. Depleting Mg2+ and SO42− resulted in additional oil recovery but less than in SMW2. Diluting Ca2+ 100 times was the second-best scenario, after depleted Ca2+ in SMW2. The results of this study showed that the more diluted Ca2+ is in the injected brine, the more additional oil recovery that can be obtained, although the other divalent/monovalent cations/anions were increased or decreased or even depleted. Additional reservoir cores were allocated for surface-reactivity tests. The absence of an oil phase allows us to isolate the important water/rock reactions. The Ca2+, Mg2+, and SO42− effluents for all cores were matched using CrunchFlow, and then further investigations of the water/rock interactions were conducted. The RTM showed that decreasing the Mg2+ concentration will decrease the number of the most effective kaolinite edges Si-O− and Al-O−, but was not as pronounced as that in the presence of Ca2+, which explains why lowering the Mg2+ concentration gives lower additional oil recovery and why lowering the Ca2+ concentration gives higher additional oil recovery.

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