Despite developing enhanced oil recovery methods, waterflooding in oil reservoirs is still used to maintain reservoir pressure and transfer oil to production wells due to its simplicity and low cost ^[1]. Studies have shown that the salinity and composition of injected water significantly affect oil recovery. McGuire et al. ^[2] stated that injecting low salinity water (LSW) increases oil recovery in carbonate and sandstone reservoirs. Salinity reduction or decreased total dissolved solids (TDS) of the injected water changes rock wettability and reduces the surface tension and capillary pressure ^[3]. Therefore, LSW produces more oil than SW due to low salt concentration ^[4-5]. Tang and Morrow ^[6] performed different experiments on sandstone samples and reported three necessary conditions for increasing oil recovery using LSW: the presence of clay, initial water saturation and crude oil containing polar compounds. Al-Otaibi et al. ^[7] performed different wettability studies on limestone cores and showed that synthetic aquifer water made the carbonate rock water- wet, but SW and formation water (FW) changed the rock wettability to more oil-wet. Al-Otaibi et al. ^[8-9] stated that as the brine salinity decreases, the negative surface charges and the electric double layer thickness increase. Nasrallah et al. ^[10] attributed enhanced oil recovery to wettability alteration of carbonate cores from less water-wet to more water-wet. LSW injection is a good technique to increase oil recovery due to economic and environmental considerations. However, despite the positive aspects of LSW, this technique can cause damage in some cases, such as scale precipitation and fine migration in carbonate and sandstone reservoirs^[11-12]. SW treatment is also expensive to overcome precipitation problems, and SW dilution is unavailable in many countries. All these factors affect the selection of LSW as an enhanced oil recovery fluid ^[13]. Kumar et al. ^[14] stated that by increasing NaCl concentration and decreasing CaCl₂ concentration in solution, the solubility of CaSO₄•2H₂O increases. LSW means reducing salts concentration such as NaCl in SW, which is responsible for keeping CaSO₄ in solution.

Kumar and Calberg ^[14-15] reported that adding chelating agents to SW keeps Na⁺ concentration constant, but chelates Ca²⁺ in the fluid and prevents the CaSO₄ precipitation. In order to investigate the effects of ions on various parameters, the authors have conducted several studies. Sultani et al. ^[16] showed that the presence or absence of SO₄²⁻ in injected water would not significantly affect the ultimate oil recovery. However, compared to deionized water (DIW), adding Mg²⁺ to injected water would increase oil recovery by 10% to 15%. Rashid et al. ^[17] concluded that SO₄²⁻ plays a significant role in rock wettability alteration and act as catalysts. However, they reported that the presence of SO₄²⁻ is not critical to change the rock wettability. Karimi et al. ^[18] stated that during spontaneous imbibition tests, enrichment of LSW with Mg²⁺ leads to a decrease in ultimate oil recovery. Ali et al. ^[19] prepared different smart water solutions by adding 2500, 5000 and 1000 mg/L of monovalent and divalent salts within DIW. They also reported that by adding nanocomposite (TiO₂/SiO₂/poly(acrylamide)) to these smart solutions, the IFT decreased by 65%, and the performance of wettability alteration was influenced by 32%.

Chelating agents can be used as chemical enhanced oil recovery fluids and reduce the salinity of injected water by capturing and chelating metal ions such as Ca²⁺, Mg²⁺ and Fe²⁺ from fluid and rock and behave like LSW ^{[13,20⇓⇓ -23]}. Chelating agents such as EDTA are stable at high temperatures up to 200 °C ^[24]. They are not absorbed on the rock surface and do not damage the pores and also prevent precipitation by chelating different metal ions from rock and fluid ^{[25⇓⇓-28]}. Fredd and Fogler ^[29] were the first to use EDTA chelating agent as stimulation fluid in oil and gas fields, and Attia et al. ^[13] also used EDTA chelating agent for the first time to enhance oil recovery. Chelating agents are compatible with sandstones and carbonate rocks and are available in different pH values. Previous studies have shown that using chelating agents at high pH increases oil recovery and improves the performance of chelating agents ^{[13,20,30⇓ -32]}. Injecting chelating agents at high pH can disturb the initial equilibrium between crude oil and rock and increase oil recovery ^[13,20]. Chelating agents can also be mixed with untreated SW, which is an effective way to reduce the costs of enhanced oil recovery and flooding projects ^[13,30]. SW contains high concentrations of sulfate ions, while FW contains divalent ions such as Ba²⁺, Ca²⁺ and Sr²⁺. By mixing FW with SW, an unstable solution is formed and precipitates CaSO₄, SrSO₄, BaSO₄ in the reservoir ^[12,33]. Chelating agents capture metal ions and prevent them from reacting with other ions. Capturing metal ions from the solution prevents some problems, such as corrosion, precipitation and permeability reduction. Therefore, chelating agents in undiluted SW can behave the same as LSW and affect the rock dissolution and enhanced oil recovery process^[34⇓-36]. However, unlike LSW, chelating agents prevent precipitation and do not cause any formation damage. For these reasons, chelating agents have been proposed as an alternative to LSW flooding ^[13,35]. The dependence of the chelating agent on a metal ion is defined by the stability constant. High stability constant means high dependence of chelating agent on metal ions. For example, for all chelating agents, the stability constant with Fe²⁺ is high, which means chelating agent first separates Fe²⁺ from rock or solution and then separates other ions, such as Ca²⁺ and Mg^{2+ [21]}. DTPA has the highest stability constant among all chelating agents, which means it takes ions from the solution more strongly and prevents ions precipitation ^[32]. Also, compared to other chelating agents, DTPA has the most carboxylic groups in its structure ^{[37⇓⇓⇓-41]}. The additional carboxylic group in DTPA solubilizes more oil and decreases the IFT. Because of these reasons, in this study, we used DTPA chelating agent to perform different experiments. Wettability is one of the essential parameters in reservoirs that controls the location, distribution and fluid flow in the porous media^[42]. Wettability affects almost all parameters required for reservoir management, including relative permeability, electrical properties, saturation distribution and capillary pressure ^[43]. Various methods are used to determine rock wettability alteration, including spontaneous imbibition tests, contact angle measurement, Zeta potential measurement, capillary pressure diagrams, relative permeability diagrams, and nuclear magnetic resonance. Ali ^[44] reduced the rock/oil contact angle from 134° to 22° by mixing 1000 mg/L Fe₃O₄-mineral-soil nanocomposites within SW. Wettability alteration is the first oil recovery mechanism proposed using chelating agents as enhanced oil recovery fluids ^[11]. Chelating agents at high pH separate various metal ions from solution, so the rock surface must release cations from its surface to achieve equilibrium. This dissolution process changes the rock wettability to more water-wet and with the release of ions from the rock surface, more oil will be recovered ^{[11,22⇓ -24,31,45 -46]}. Mahmoud et al. ^[47] found that rock dissolution, IFT reduction and wettability alteration are possible mechanisms to improve oil recovery using HEDTA chelating agent. They also stated that EDTA of mass fraction 5% (5% EDTA for short) flooding in limestone core and 5% HEDTA flooding in sandstone core recovered more than 20% of OOIP. Hassan et al. ^[48] performed sequential flooding of EDTA chelating agent in carbonate rocks. The CT scan and pressure drop results showed that high concentrations of chelating agent led to rock dissolution and wormhole creation. They recommended using EDTA chelating agent at a mass fraction of less than 10%. Zeta potential measurements also showed that increasing the concentration of chelating agent leads to more negative charges on limestone surface. Hassan et al. ^[49] investigated the performance of EDTA in enhanced oil recovery from carbonate samples. They considered 3% of EDTA chelating agent as the optimum concentration, which resulted in maximizing oil recovery without causing severe rock dissolution. Mahmoud et al. ^[20,23] investigated the performance of EDTA in chelating Fe²⁺ from iron-rich minerals and used EDTA chelating agent to enhance oil recovery from sandstone samples. They were able to increase oil recovery up to 19% of OOIP using 10% EDTA solution without any formation damage. Hassan and Al-Hashim ^[50] showed that carbonate core flooding using EDTA solution altered wettability towards more water-wet. Also, ICP analysis confirmed that Ca²⁺ were chelated from the rock during EDTA flooding and their concentration increased in flooding effluent.

In this study, we used DTPA chelating agent as a new enhanced oil recovery fluid that can be used as an alternative to LSW. While previous studies used one of the quantitative or qualitative methods to investigate the rock surface charge, we considered both qualitative and quantitative techniques to determine rock surface charge and wettability alteration. Therefore, in order to investigate rock wettability alteration caused by using DTPA chelating agent, we used the set of Zeta potential, rock/oil contact angle, and imbibition measurements. Unlike previous studies which they considered light oil in their studies, we used heavy oil in this study to perform different tests. The effects of mass fraction, brine salinity, and for the first time, the impact of potential determining ions (Ca²⁺, Mg²⁺ and SO₄²⁻) and their concentrations on the performance of DTPA were also evaluated. Moreover, spontaneous imbibition experiments were conducted and the effect of capillary and gravity forces on oil recovery was discussed. Finally, using the results of different experiments, the optimum mass fraction of DTPA chelating agent was determined.

Due to some problems such as precipitation, clay swelling, and cost of dilution that existed in LSW injection, we used DTPA chelating agent as an alternative to LSW. DTPA chelating agents capture metal ions from rock and solution, dissolve rock, and change the rock wettability toward water-wet without any formation damage. In order to investigate the impact of DTPA on the rock surface and oil recovery, experiments of rock wettability, Zeta potential, and imbibition were performed. Preparing 5% DTPA chelating agent in seawater changed the rock-oil contact angle from 143° to 23° and decreased the Zeta potential from −2.29 mV to −13.06 mV. In comparison with LSW, 5% DTPA made the rock more water-wet. The presence or absence of PDIs such as Ca²⁺, Mg²⁺ and SO₄²⁻ in the solution could not affect the performance of DTPA in changing wettability. However, the performance of 5% DTPA-SW in wettability alteration was impaired by tripling these ions concentrations. By increasing DTPA mass fraction and decreasing the salinity of the solution, the absolute Zeta potential increases, and the rock wettability changed to water-wet. Imbibition experiments showed that the oil recovery factor increases with the increasing DTPA mass fraction. 5% and 7% DTPA-SW solutions recovered 39.6% of OOIP and 40.1% of OOIP. Therefore, 5% DTPA was suggested as an optimum mass fraction.

C_i—molar concentration of species i, mol/L;

e—electrical charge, C;

i—ion SN;

I—ionic strength, mol/L;

k—boltzmann constant, J/K；

n—number of ionic species I;

n₀—ion concentration, m⁻³;

t—time, h;

T—temperature, K;

W—wettability alteration index;

z—ion valence of the species;

ε—water dielectric constant;

ε₀—permittivity of free space, F/m;

ε_r—relative permittivity of the fluid;

${{\kappa }^{-1}}$—double layer thickness, m；

ζ—Zeta potential, V;

η—viscosity of the fluid, Pa·s;

θ_f—final rock-oil contact angle after placing thin section in the designed solutions, (°);

θ_i—initial rock-oil contact angle before aging thin section in oil, (°);

θ₀—rock-oil contact angle after aging thin section in oil, (°);

μ—electrophoretic mobility, m²/(V·s);

σ_e—electrokinetic charge density, C/m².