Browsing by Subject "Wettability alteration"
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Item Development and application of a 3D equation-of-state compositional fluid-flow simulator in cylindrical coordinates for near-wellbore phenomena(2011-12) Abdollah Pour, Roohollah; Torres-Verdín, Carlos; Sepehrnoori, Kamy, 1951-; Delshad, Mojdeh; Demkowicz, Leszek; Johns, Russell T.Well logs and formation testers are routinely used for detection and quantification of hydrocarbon reserves. Overbalanced drilling causes invasion of mud filtrate into permeable rocks, hence radial displacement of in-situ saturating fluids away from the wellbore. The spatial distribution of fluids in the near-wellbore region remains affected by a multitude of petrophysical and fluid factors originating from the process of mud-filtrate invasion. Consequently, depending on the type of drilling mud (e.g. water- and oil-base muds) and the influence of mud filtrate, well logs and formation-tester measurements are sensitive to a combination of in-situ (original) fluids and mud filtrate in addition to petrophysical properties of the invaded formations. This behavior can often impair the reliable assessment of hydrocarbon saturation and formation storage/mobility. The effect of mud-filtrate invasion on well logs and formation-tester measurements acquired in vertical wells has been extensively documented in the past. Much work is still needed to understand and quantify the influence of mud-filtrate invasion on well logs acquired in horizontal and deviated wells, where the spatial distribution of fluids in the near-wellbore region is not axial-symmetric in general, and can be appreciably affected by gravity segregation, permeability anisotropy, capillary pressure, and flow barriers. This dissertation develops a general algorithm to simulate the process of mud-filtrate invasion in vertical and deviated wells for drilling conditions that involve water- and oil-base mud. The algorithm is formulated in cylindrical coordinates to take advantage of the geometrical embedding imposed by the wellbore in the spatial distribution of fluids within invaded formations. In addition, the algorithm reproduces the formation of mudcake due to invasion in permeable formations and allows the simulation of pressure and fractional flow-rate measurements acquired with dual-packer and point-probe formation testers after the onset of invasion. An equation-of-state (EOS) formulation is invoked to simulate invasion with both water- and oil-base muds into rock formations saturated with water, oil, gas, or stable combinations of the three fluids. The algorithm also allows the simulation of physical dispersion, fluid miscibility, and wettability alteration. Discretized fluid flow equations are solved with an implicit pressure and explicit concentration (IMPEC) scheme. Thermodynamic equilibrium and mass balance, together with volume constraint equations govern the time-space evolution of molar and fluid-phase concentrations. Calculations of pressure-volume-temperature (PVT) properties of the hydrocarbon phase are performed with Peng-Robinson's equation of state. A full-tensor permeability formulation is implemented with mass balance equations to accurately model fluid flow behavior in horizontal and deviated wells. The simulator is rigorously and successfully verified with both analytical solutions and commercial simulators. Numerical simulations performed over a wide range of fluid and petrophysical conditions confirm the strong influence that well deviation angle can have on the spatial distribution of fluid saturation resulting from invasion, especially in the vicinity of flow barriers. Analysis on the effect of physical dispersion on the radial distribution of salt concentration shows that electrical resistivity logs could be greatly affected by salt dispersivity when the invading fluid has lower salinity than in-situ water. The effect of emulsifiers and oil-wetting agents present in oil-base mud was studied to quantify wettability alteration and changes in residual water saturation. It was found that wettability alteration releases a fraction of otherwise irreducible water during invasion and this causes electrical resistivity logs to exhibit an abnormal trend from shallow- to deep-sensing apparent resistivity. Simulation of formation-tester measurements acquired in deviated wells indicates that (i) invasion increases the pressure drop during both drawdown and buildup regimes, (ii) bed-boundary effects increase as the wellbore deviation angle increases, and (iii) a probe facing upward around the perimeter of the wellbore achieves the fastest fluid clean-up when the density of invading fluid is larger than that of in-situ fluid.Item Development of a non-isothermal compositional reservoir simulator to model asphaltene precipitation, flocculation, and deposition and remediation(2014-05) Darabi, Hamed; Sepehrnoori, Kamy, 1951-Asphaltene precipitation, flocculation, and deposition in the reservoir and producing wells cause serious damages to the production equipment and possible failure to develop the reservoirs. From the field production prospective, predicting asphaltene precipitation, flocculation, and deposition in the reservoir and wellbore may avoid high expenditures associated with the reservoir remediation, well intervention techniques, and field production interruption. Since asphaltene precipitation, flocculation, and deposition strongly depend on the pressure, temperature, and composition variations (e.g. phase instability due to CO2 injection), it is important to have a model that can track the asphaltene behavior during the entire production system from the injection well to the production well, which is absent in the literature. Due to economic concerns for asphaltene related problems, companies spend a lot of money to design their own asphaltene inhibition and remediation procedures. However, due to the complexity and the lack of knowledge on the asphaltene problems, these asphaltene inhibition and remediation programs are not always successful. Near-wellbore asphaltene inhibition and remediation techniques can be divided into two categories: changing operating conditions, and chemical treatment of the reservoir. Although, the field applications of these procedures are discussed in the literature, a dynamic model that can handle asphaltene inhibition and remediation in the reservoir is missing. In this dissertation, a comprehensive non-isothermal compositional reservoir simulator with the capability of modeling near-wellbore asphaltene inhibition and remediation is developed to address the effect of asphaltene deposition on the reservoir performance. This simulator has many additional features compared to the available asphaltene reservoir simulators. We are able to model asphaltene behavior during primary, secondary, and EOR stages. A new approach is presented to model asphaltene precipitation and flocculation. Adsorption, entrainment, and pore-throat plugging are considered as the main mechanisms of the asphaltene deposition. Moreover, we consider porosity, absolute permeability, and oil viscosity reductions due to asphaltene. It is well known that the asphaltene deposition on the rock surface changes the wettability of the rock towards oil-wet condition. Although many experiments in the literature have been conducted to understand the physics underlying wettability alteration due to asphaltene deposition, a comprehensive mathematical model describing this phenomenon is absent. Based on the available experimental data, a wettability alteration model due to asphaltene deposition is proposed and implemented into the simulator. Furthermore, the reservoir simulator is coupled to a wellbore simulator to model asphaltene deposition in the entire production system, from the injection well to the production well. The coupled reservoir/wellbore model can be used to track asphaltene deposition, to diagnose the potential of asphaltene problems in the wellbore and reservoir, and to find the optimum operating conditions of the well that minimizes asphaltene problems. In addition, the simulator is capable of modeling near-wellbore asphaltene remediation using chemical treatment. Based on the mechanisms of the asphaltene-dispersant interactions, a dynamic modeling approach for the near-wellbore asphaltene chemical treatments is proposed and implemented in the simulator. Using the dynamic asphaltene remediation model, we can optimize the asphaltene treatment plan to reduce asphaltene related problems in a field. The results of our simulations show that asphaltene precipitation, flocculation, and deposition in the reservoir and wellbore are dynamic processes. Many parameters, such as oil velocity, wettability alteration, pressure, temperature, and composition variations influence the trend of these processes. In the simulation test cases, we observe that asphaltene precipitation, flocculation, and deposition can occur in primary production, secondary production, or EOR stages. In addition, our results show that the wettability alteration has the major effect on the performance of the reservoir, comparing to the permeability reduction. During CO2 flooding, asphaltene precipitation occurs mostly at the front, and asphaltene deposition is at its maximum close to the reservoir boundaries where the front velocity is at its minimum. In addition, the results of the coupled reservoir/wellbore simulator show that the behavior of asphaltene in the wellbore and reservoir are fully coupled with each other. Therefore, a standalone reservoir or wellbore simulator is not able to predict the asphaltene behavior properly in the entire system. Finally, we show that the efficiency of an asphaltene chemical treatment plan depends on the type of dispersant, amount of dispersant, soaking time, number of treatment jobs, and the time period between two treatment jobs.Item Enhanced oil recovery in fractured vuggy carbonates(2014-05) Chen, Peila; Mohanty, Kishore Kumar; Pope, Gary A.; Balhoff, Matthew T.; Delshad, Mojdeh; Arbogast, Todd J.Naturally fractured carbonates contribute substantially to global oil reserves. Waterflood and gas-oil gravity drainage (GOGD) recover oil from the fractured oil-wet carbonates, with limited success due to poor sweep and very low recovery factors. Surfactant flooding has shown a great potential to enhance oil recovery in the oil-wet carbonates by reducing interfacial tension and/or altering wettability. Carbonates are characterized by the wide pore-size distributions. Surfactant EOR cannot be successfully implemented in a fractured, oil-wet, carbonate reservoir unless the reservoir is fully characterized and all of the mechanisms involved in oil recovery are fully understood. NMR T₂ measurement, mercury injection capillary pressure test (MICP), thin-section imaging, and computerized tomography (CT) scanning were conducted in the characterization of vuggy dolomite cores from the field. Both thin section and CT images reveal that the touching vugs and separate vugs co-exist in the core samples. Although the vuggy porosity is estimated to be 85%, the matrix controls the permeability of the core because of poor vug connectivity. MICP and NMR T₂ measurements show multimodal pore-throat and pore-body size distributions. Reconstructed 3D CT porosity maps indicate that the vugs in the field dolomite are large and randomly distributed, while the vugs in the Silurian dolomite are small and densely populated. A single-phase tracer test performed under CT scanner reveals a large porosity variation and the preferential flow paths within the field dolomite core. The mercury withdrawal test and NMR T₂ measurement have indicated that snap-off retains oil in the vugs due to the large aspect ratio pores and the large length-scale of the oil blobs. The imbibition oil recovery from the initially oil-wet field dolomite core is 20% lower (in OOIP) than that from the Silurian dolomite core, mainly because of an unfavorable pore structure in the field dolomite core. A few surfactants were selected as promising candidates for wettability alteration because they possess aqueous stability in hard brine at elevated temperatures and reduce contact angles. The divalent cations in the hard brine significantly suppress the anionic surfactant-mediated wettability alteration. The removal of Ca²⁺, and then Mg²⁺ from the hard brine progressively promotes anionic surfactant-assisted wettability alteration, evidenced by decreasing contact angles. The addition of sufficient amount of divalent ion scavengers, including chelating agents (e.g. EDTA.4Na) and scale inhibitors (e.g. Sodium Polyacrylate) in the hard brine, rescues the anionic surfactant-mediated wettability alteration. We propose that the scavenger reduces the concentration of free divalent cations, and promotes the release of the surfactant monomers, which favors wettability alteration through the surfactant adsorption mechanism. The scavenger- triggered mineral dissolution only weakly contributes to the imbibition oil recovery. Experiments and simulation studies consistently showed the synergy between wettability alteration and IFT reduction in a surfactant-assisted gravity-driven process. The residual oil saturation after gravity drainage is approximately 10~20% higher than that by gravity-driven imbibition if the two processes have the same trapping number N[subscript T], which implies that wettability alteration contributes to oil recovery from the oil-wet carbonates. A critical capillary number was found in the capillary desaturation curve plotted for the spontaneous imbibition tests, not for gravity drainage tests. In a UTCHEM model, wettability alteration is represented by the changes in P[subscript c], k[subscript r] and CDC. The simulation successfully history-matched and also predicted the incremental oil recovery by the surfactant formulations. The sensitivity study carried out in UTCHEM simulation shows the strong effects of fluid density, capillary pressure and vuggy pore structures on oil recovery. Three current available oil recovery prediction models (Hagoort, 1980; Aronofsky, 1958; Gupta and Civan, 1994) were tested against imbibition experiments. Two new analytical models were developed in this work, which significantly improved the quality of matching with experimental oil recovery. The matrix-fracture transfer functions, derived from the analytical oil recovery models, can be implemented in a dual-porosity simulator, providing more accurate numerical simulations of oil production in the fractured reservoirs. Lastly, we investigated the feasibility of using single well tracer test (SWTT) in the fractured reservoirs to determine the ROS or connate water saturation. The fractures studied are mainly small-scale fractures. The effects of fracture and its orientation on SWTTs were studied in four Berea cores with a single fracture in each core, orientated as 90°, 60°, 30°, and 0° against dominant flow direction. A simple Cartesian grid without dual porosity in UTCHEM simulator is adequate to interpret the experimental data. A synthetic field-scale SWTT is not sensitive to the presence of moderate degrees of small-scale fractures. The sensitivity study of fluid drift, representing flow irreversibility in a fractured reservoir, reveals the existence of a critical drift velocity, below which the tracer breakthrough curves (BTCs) are interpretable.Item Enhancing the productivity of volatile oil reservoirs using fluorinated chemical treatments(2011-08) Torres López, David Enrique; Sharma, Mukul M.; Pope, Gary A.; Rochelle, Gary T.; Bonnecaze, Roger T.; Freeman, Benny D.Many producing volatile oil reservoirs experience a significant decrease in well deliverability when the bottom-hole pressure of the well falls below the bubble point pressure. This is due to the liberation of a gas phase which resides in the pore space and blocks the flow of the oil phase. This situation is known as "gas blocking". This occurs because the presence of two or three immiscible phases (gas, oil and water) results in a reduction of the oil saturation and a decrease in the oil relative permeability. The main objective of this research was to develop an effective and durable chemical treatment method to improve and/or restore the productivity of volatile oil wells undergoing "gas blocking". The treatment method is based on the use of fluorinated surfactants in tailored solvents to increase the oil relative permeability by changing the wettability of the rock’s surface. High-temperature high-pressure (HTHP) core flood experiments were used to evaluate the uses of fluorinated surfactants under reservoir conditions. Analytical tools such as X-ray photoelectron spectroscopy (XPS), high-performance liquid chromatography (HPLC) and computerized axial tomography (CT Scan) were also used to interpret the experimental results. High-pressure high-temperature (HPHT) coreflood tests showed that the treatments improved the oil and gas relative permeability in both sandstone and limestone cores. This was observed for synthetic volatile oil mixtures with gas-oil ratios (GOR) in the range of 4000 to 13,000 scf/STB at low capillary numbers (Nc) on the order of 1x10-5 to 1x10-6 and for PVT ratios greater than 0.5. The fluorinated chemical treatments were effective in the presence of connate water over the temperature range of 155°F to 275°F. Wettability alteration was measured using contact angle and imbibition rate tests. Results from analytical tools showed that fluorinated surfactants were uniformly adsorbed along the core and the surfactant desorption after treatment was low (10 ppm or less). The gas saturation decreased following treatment and both the oil and gas relative permeability increased. Numerical simulations using the measured relative permeability data were used to estimate the gain in productivity for treated wells. The proposed fluorinated chemical treatments could be used as a preventive treatment or for a damaged well that has already been producing below the bubble point to increase oil production rates and recoverable reserves.Item Modeling conformance control and chemical EOR processes using different reservoir simulators(2015-08) Goudarzi, Ali; Johnston, Keith P., 1955-; Sepehrnoori, Kamy, 1951-; Delshad, Mojdeh; Sharma, Mukul M; Bonnecaze, Roger TSuccessful field waterflood is a crucial prerequisite for improving the performance before EOR methods, such as ASP, SP, and P flooding, are applied in the field. Excess water production is a major problem in mature waterflooded oil fields that leads to early well abandonment and unrecoverable hydrocarbon. Gel treatments at the injection and production wells to preferentially plug the thief zones are cost-effective methods to improve sweep efficiency in reservoirs and reduce excess water production during hydrocarbon recovery. There are extensive experimental studies performed by some researchers in the past to investigate the performance of gels in conformance control and decreasing water production in mature waterflooded reservoirs, but no substantial modeling work has been done to simulate these experiments and predict the results for large field cases. We developed a novel, 3-dimensional chemical compositional and robust general reservoir simulator (UTGEL) to model gel treatment processes. The simulator has the capability to model different types of microgels, such as preformed particle gels (PPG), thermally active polymers (TAP), pH-sensitive microgels, and colloidal dispersion gels (CDG). The simulator has been validated for gel flooding using laboratory and field scale data. The simulator helps to design and optimize the flowing gel injection for conformance control processes in larger field cases. The gel rheology, adsorption, resistance factor and residual resistance factor with salinity effect, gel viscosity, gel kinetics, and swelling ratio were implemented in UTGEL. Several simulation case studies in fractured and heterogeneous reservoirs were performed to illustrate the effect of gel on production behavior and water control. Laboratory results of homogeneous and heterogeneous sandpacks, and Berea sandstone corefloods were used to validate the PPG transport models. Simulations of different heterogeneous field cases were performed and the results showed that PPG can improve the oil recovery by 5-10% OOIP compared to waterflood. For recovery from fractured reservoirs by waterflooding, injected water will flow easily through fractures and most part of reservoir oil will remain in matrix blocks unrecovered. Recovery from these reservoirs depends on matrix permeability, wettability, fracture intensity, temperature, pressure, and fluid properties. Chemical processes such as polymer flooding (P), surfactant/polymer (SP) flooding and alkali/surfactant/polymer (ASP) flooding are being used to enhance reservoir energy and increase the recovery. Chemical flooding has much broader range of applicability than in the past. These include high temperature reservoirs, formations with extreme salinity and hardness, naturally fractured carbonates, and sandstone reservoirs with heavy and viscous crude oils. The recovery from fractured carbonate reservoirs is frequently considered to be dominated by spontaneous imbibition. Therefore, any chemical process which can enhance the rate of imbibition has to be studied carefully. Wettability alteration using chemicals such as surfactant and alkali has been studied by many researchers in the past years and is recognized as one of the most effective recovery methods in fractured carbonate reservoirs. Injected surfactant will alter the wettability of matrix blocks from oil-wet to water-wet and also reduce the interfacial tension to ultra-low values and consequently more oil will be recovered by spontaneous co-current or counter-current imbibition depending on the dominant recovery mechanism. Accurate and reliable up-scaling of chemical enhanced oil recovery processes (CEOR) are among the most important issues in reservoir simulation. The important challenges in up-scaling CEOR processes are predictability of developed dimensionless numbers and also considering all the required mechanisms including wettability alteration and interfacial tension reduction. Thus, developing new dimensionless numbers with improved predictability at larger scales is of utmost importance in CEOR processes. There are some scaling groups developed in the past for either imbibition or coreflood experiments but none of them were predictive because all the physics related to chemical EOR processes (interfacial tension reduction and wettability alteration) were not included. Furthermore, most of commercial reservoir simulators do not have the capability to model imbibition tests due to lack of some physics, such as surfactant molecular diffusion. The modeling of imbibition cell tests can aid to understand the mechanisms behind wettability alteration and consequently aid in up-scaling the process. Also, modeling coreflood experiments for fractured vuggy carbonates is challenging. Different approaches of random permeability distribution and explicit fractures were used to model the experiments which demonstrate the validity and ranges of applicability of upscaled procedures, and also indicate the importance of viscous and capillary forces in larger scales. The simulation models were then used to predict the recovery response times for larger cores.Item Modeling wettability alteration in naturally fractured carbonate reservoirs(2011-12) Goudarzi, Ali; Sepehrnoori, Kamy, 1951-; Delshad, MojdehThe demand for energy and new oil reservoirs around the world has increased rapidly while oil recovery from depleted reservoirs has become more difficult. Oil production from fractured carbonate reservoirs by water flooding is often inefficient due to the commonly oil-wet nature of matrix rocks. Chemical enhanced oil recovery (EOR) processes such as surfactant-induced wettability alteration and interfacial tension reduction are required to decrease the residual oil saturation in matrix blocks, leading to incremental oil recovery. However, improvement in recovery will depend on the degree of wettability alteration and interfacial tension (IFT) reduction, which in turn are functions of matrix permeability, fracture intensity, temperature, pressure, and fluid properties. The oil recovery from fractured carbonate reservoirs is frequently considered to be dominated by the spontaneous imbibition mechanism which is a combination of viscous, capillary, and gravity forces. The primary purpose of this study is to model wettability alteration in the lab scale for both coreflood and imbibition cell tests using the chemical flooding reservoir simulator. The experimental recovery data for fractured carbonate rocks with different petrophysical properties were history-matched with UTCHEM, The University of Texas in-house compositional chemical flooding simulator, using a highly heterogeneous permeability distribution. Extensive simulation work demonstrates the validity and ranges of applicability of upscaled procedures, and also indicates the importance of viscous and capillary forces in larger fields. The results of this work will be useful for designing field-scale chemical EOR processes.Item Surfactant-enhanced spontaneous imbibition process in highly fractured carbonate reservoirs(2011-05) Chen, Peila; Mohanty, Kishore Kumar; Pope, Gary A.Highly fractured carbonate reservoirs are a class of reservoirs characterized by high conductivity fractures surrounding low permeability matrix blocks. In these reservoirs, wettability alteration is a key method for recovering oil. Water imbibes into the matrix blocks upon water flooding if the reservoir rock is water-wet. However, many carbonate reservoirs are oil-wet. Surfactant solution was used to enhance spontaneous imbibition between the fractures and the matrix by both wettability alteration and ultra-low interfacial tensions. The first part of this study was devoted to determining the wettability of reservoir rocks using Amott-Harvey Index method, and also evaluating the performance of surfactants on wettability alteration, based on the contact angle measurement and spontaneous imbibition rate and ultimate oil recovery on oil-wet reservoir cores. The reservoir rocks have been found to be slightly oil-wet. One cationic surfactant BTC8358, one anionic surfactant and one ultra-low IFT surfactant formulation AKL-207 are all found to alter the wettability towards more water-wet and promote oil recovery through spontaneous imbibition. The second part of the study focused on the parameters that affect wettability alteration by surfactants. Some factors such as core dimension, permeability and heterogeneity of porous medium are evaluated in the spontaneous imbibition tests. Higher permeability leads to higher imbibition rate and higher ultimate oil recovery. Heterogeneity of core samples slows down the imbibition process if other properties are similar. Core dimension is critical in upscaling from laboratory conditions to field matrix blocks. The imbibition rate is slower in larger dimension of core. Further, we investigated the effects of EDTA in surfactant-mediated spontaneous imbibition. Since high concentration of cationic divalent ions in the aqueous solution markedly suppresses the surfactant-mediated wettability alteration, EDTA improved the performance of surfactant in the spontaneous imbibition tests. It is proposed in the thesis that surfactant/EDTA-enhanced imbibition may involve the dissolution mechanism. More experiments should be conducted to verify this mechanism. The benefits of using EDTA in the surfactant solution include but not limited to: altering the surface charge of carbonate to negative, producing the in-situ soap, reducing the brine hardness, decreasing the surfactant adsorption, and creating the water-wet area by dissolving the dolomite mineral.Item Wettability alteration in high temperature and high salinity carbonate reservoirs(2011-08) Sharma, Gaurav, M.S. in Engineering; Mohanty, Kishore Kumar; Pope, Gary A.The goal of this work is to change the wettability of a carbonate rock from oil wet-mixed-wet towards water-wet at high temperature and high salinity. Only simple surfactant systems (single surfactant, dual surfactants) in dilute concentration were tried for this purpose. It was thought that the change in wettability would help to recover more oil during secondary surfactant flood as compared to regular waterflood. Three types of surfactants, anionic, non-ionic and cationic surfactants in dilute concentrations (<0.2 wt%) were used. Initial surfactant screening was done on the basis of aqueous stability at these harsh conditions. Contact angle experiments on aged calcite plates were done to narrow down the list of surfactants and spontaneous imbibition experiments were conducted on field cores for promising surfactants. Secondary waterflooding was conducted in cores with and without the wettability altering surfactants. It was observed that barring a few surfactants, most were aqueous unstable by themselves at these harsh conditions. Dual surfactant systems, a mixture of a non-ionic and a cationic surfactant increased the aqueous stability of the non-ionic surfactants. One of the dual surfactant system, a mixture of Tergitol NP-10 and Dodecyl trimethyl ammonium bromide, proved very effective for wettability alteration and could recover 70-80% of OOIP during spontaneous imbibition. Secondary waterflooding with the wettability altering surfactant (without alkali or polymer) increased the oil recovery over the waterflooding without the surfactants (from 29% to 40% OOIP). Surfactant adsorption calculated during the coreflood showed an adsorption of 0.24 mg NP-10/gm of rock and 0.20 mg DTAB/gm of rock. A waterflood done after the surfactant flood revealed change in the relative permeability before and after the surfactant flood suggesting change in wettability towards water-wet.Item Wettability alteration with brine composition in high temperature carbonate reservoirs(2013-08) Chandrasekhar, Sriram; Mohanty, Kishore KumarThe effect of brine ionic composition on oil recovery was studied for a limestone reservoir rock at a high temperature. Contact angle, imbibition, core flood and ion analysis were used to find the brines that improve oil recovery and the associated mechanisms. Contact angle experiments showed that modified seawater containing Mg[superscript 2+] and SO4[superscript 2-] and diluted seawater change aged oil-wet calcite plates to more water-wet conditions. Seawater with Ca[superscript 2+], but without Mg[superscript 2+] or SO₄[superscript 2-] was unsuccessful in changing calcite wettability. Modified seawater containing Mg[superscript 2+] and SO₄[superscript 2-], and diluted seawater spontaneously imbibe into the originally oil-wet limestone cores. Modified seawater containing extra SO₄[superscript 2-] and diluted seawater improve oil recovery from 40% OOIP (for formation brine waterflood) to about 80% OOIP in both secondary and tertiary modes. The residual oil saturation to modified brine injection is approximately 20%. Multi ion exchange and mineral dissolution are responsible for desorption of organic acid groups which lead to more water-wet conditions. Further research is needed for scale-up of these mechanisms from cores to reservoirs.