Polyhalite compositions and methods for enhancing oil recovery

Abstract

Provided herein is a liquid solution for recovering petroleum from a carbonate reservoir, comprising a solid chemical composition comprising: polyhalite in the range of 70 to 99.5% by weight; NaCl in the range of 5 to 30% by weight; SiO2 in the range of 0.1 to 5% by weight; and injection water selected from the group consisting of seawater, diluted seawater, desalinated seawater, produced water, aquifer water, river water, surface water, fresh water, distilled water, or a combination thereof; wherein the solid chemical composition is dissolved in the injection water in an amount of 1-10 grams of the solid chemical composition per liter of the injection water.

Description

Technical Field

[0001] The present invention relates to the field of enhanced oil recovery (abbreviated EOR). Background Art

[0002] Enhanced oil recovery (EOR), also known as tertiary oil recovery, is the process of extracting crude oil from an oil field that would otherwise be inaccessible. EOR can extract 30% to 60% or more of the oil in a reservoir, compared to 20% to 40% using primary and secondary recovery. According to the U.S. Department of Energy, carbon dioxide and water are injected together using one of three EOR techniques: heat injection, gas injection, and chemical injection.

[0003] The production of crude oil from a reservoir can include up to three different phases: primary, secondary, and tertiary (EOR). The tertiary phase can be the extraction of crude oil by using chemicals in a brine injection into the oil reservoir.

[0004] Carbonate reservoirs are characterized by a neutral to oil-wet system. Modifying the surface of carbonate reservoirs to make them water-wet is important to increase oil recovery.

[0005] The enhanced oil recovery system consists of: oil-water-solids. The composition of the injected brine is crucial to the wettability of the carbonate rock surface.

[0006] Carbonate reservoirs hold approximately 50% of the world's oil and gas reserves, of which over 60% are oil reserves and 40% are natural gas reserves. Despite their vast reserves, oil recovered from these reservoirs is typically less than 30% of the oil in place (OOIP), making the potential for enhanced oil recovery (EOR) from carbonates very attractive.

[0007] Carbonate reservoirs are known to be challenging environments for oil production. Reservoir and production engineers encounter difficulties due to low matrix permeability, coupled with natural fractures, and poor wettability, which typically ranges from neutral to oil-wet. This limits capillary forces and reduces the likelihood of water imbibition into the rock matrix during water injection. All of these conditions can lead to water fingering, premature water breakthrough, and poor oil recovery.

[0008] The wettability of carbonate rocks is highly influenced by the presence of polar organic components (POCs) in crude oil, with acidic components being more important than alkaline components. POC composition is quantified using acid number (AN) and base number (BN). When initially very water-wet carbonate cores are exposed to crude oils with increasing acid number (AN), a decrease in water wettability is observed. The influence of AN on carbonate wettability has been confirmed by other researchers. It is also important to note that the pH of the brines in carbonate rocks is buffered to slightly alkaline conditions. Therefore, the species driving rock surface wettability are dissociated carboxylic acids and deprotonated bases.

[0009] Incipient wetting of carbonate reservoirs occurs when negatively charged carboxylates adsorb onto positively charged carbonate pore surfaces. This occurs during the migration of oil into the reservoir. Because decarboxylation occurs at high temperatures, reservoir temperature can affect crude oil chemistry. These processes reduce the oil's anodic acidity (AN). Therefore, higher water-wetting observed in carbonate reservoirs may be associated with crude oils with low AN or high-temperature reservoirs.

[0010] In heterogeneous reservoirs, water-based EOR methods are crucial because they can promote a more water-wet state despite altered wettability. Increased capillary forces promote spontaneous brine imbibition from fractures into the matrix, mobilizing trapped oil. Delaying water breakthrough by exploiting reservoir heterogeneity is highly valuable for increasing oil production in carbonate reservoirs. According to some embodiments, smart water is a method that meets all of these requirements, produced simply by altering the ionic composition of the injected water.

[0011] The well-known smart water EOR effect has been observed in naturally fractured chalk oil fields in the North Sea by injecting seawater. The wettability is altered by the presence of specific ions in seawater, calcium ions (Ca 2+ ), magnesium ions (Mg 2+ ) and sulfate ions (SO4 2- ). The wettability change is induced by specific ions present in seawater: calcium, magnesium, and sulfate. The catalyst for this process has been identified as sulfate ions present in the seawater, and calcium ions also appear to be an important ion, co-adsorbed on the chalk surface and promoting the wettability change process. Magnesium ions appear to be relevant at high temperatures, where they can exchange with calcium ions on the chalk surface, making more calcium ions available in the bulk fluid, which subsequently has a positive impact on the EOR effect. BRIEF DESCRIPTION OF THE DRAWINGS

[0012] Figure 1According to some embodiments, SEM images of a polyhalite sample at different magnifications are shown, (a) 200X, (b) 1000X, (c) 5000X, and (d) 10000X.

[0013] Figure 2 Shown are EDS spectra of four samples according to some embodiments.

[0014] Figure 3 are photographs of polyhalite solutions in distilled water and seawater, according to some demonstrative embodiments.

[0015] Figure 4 Depicted are SEM images of residues according to some embodiments at 1000X, (a) distilled water (DW) residue, (b) seawater (SW) residue.

[0016] Figure 5 Graphs depicting chromatographic separations between sulfate and lithium on a chalk core from the Stewins-Clint outcrop, (a) performed at 25°C and (b) performed at 90°C, according to some demonstrative embodiments.

[0017] Figure 6 are graphical representations of spontaneous imbibition experiments on chalk, according to some illustrative embodiments, (a) the graph shows the test at 100°C, which demonstrates the EOR effect on the Steywins-Clint chalk core by increasing sulfate concentration, (b) the graph shows the EOR effect on the chalk core by increasing calcium concentration at 70°C.

[0018] Figure 7 is a graphical representation of spontaneous imbibition experiments on chalk, according to some illustrative embodiments, and the EOR effect on chalk cores at 90°C by VB (formation water), SW, and two modified SW brines (SWONaCl and SWONaCl-4SO4).

[0019] Figure 8 This is a schematic diagram of the smart water mechanism in carbonate rocks. The active ion is SO4 2- and Ca 2+ At high temperatures, Mg 2+ Becomes more active, affecting the Ca in the solution 2+ concentration.

[0020] Figure 9 It is depicted in the changing SO4 2- , Ca 2+ and Mg 2+ Graph of spontaneous imbibition of SW on chalk cores as a function of concentration and temperature.

[0021] Figure 10is a schematic diagram of a nanofiltration process using seawater (SW) as a primary feed, according to some demonstrative embodiments.

[0022] Figure 11 Graph depicting ion rejection at different pressures using nano-SW membranes according to some embodiments.

[0023] Figure 12 Graph depicting (a) pore size distribution of SK chalk by MICP, according to some embodiments.

[0024] Figure 13 is a SEM image of uncleaned Stevens Klint chalk at 10,000x magnification.

[0025] Figure 14 These are photos of SEM images of polyhalite samples, (a) 5000X magnification, (b) 10000X magnification.

[0026] Figure 15 is a schematic diagram of a device for spontaneous imbibition experiments according to some embodiments.

[0027] Figure 16 Depicted are SEM images of PS residues at 5000X magnification after filtration through a 0.22 μm Millipore filter: (a) DW residues, (b) SW residues.

[0028] Figure 17 Depicted are graphs showing the chromatographic separation between sulfate and lithium on chalk core SK9 from the Steywins-Clint outcrop using DW0T followed by DW1T at an injection rate of 0.2 ml / min, (a) at 23°C and (b) at 90°C.

[0029] Figure 18 Depicted are graphs of oil recovery tests at 90°C by spontaneous imbibition of equivalently restored cores with Swi = 10% and exposure to oil core SK1 using FW as the imbibition brine, SK2 with SW, SK3 with DW-PS, and SK4 with SW-PS, according to some illustrative embodiments.

[0030] Figure 19 Depicted are graphs of oil recovery by spontaneous imbibition in a secondary mode at 110°C in similarly restored outcrop cores using FW (core SK5), SW (core SK6), DW-PW (core SK7), and SW-PS (core SK8), according to some illustrative embodiments. Summary of the Invention

[0031] According to some illustrative embodiments, provided herein is a liquid solution for recovering petroleum from a carbonate reservoir, comprising a solid chemical composition comprising: polyhalite in a range of 70 to 99.5 weight percent; NaCl in a range of 5 to 30 weight percent; SiO2 in a range of 0.1 to 5 weight percent; and injection water selected from the group consisting of seawater, diluted seawater, desalinated seawater, produced water, aquifer water, river water, surface water, fresh water, distilled water, or a combination thereof; wherein the solid chemical composition is dissolved in the injection water in an amount of 1-10 grams of the solid chemical composition per 1 liter of the injection water.

[0032] According to some embodiments, the injection water may be low-salinity water selected from the group consisting of surface water, fresh water, distilled water, or combinations thereof.

[0033] According to some embodiments, the low salinity water may include a total dissolved solids (TDS) concentration of 0.4% or less.

[0034] According to some embodiments, the solution of the present invention may include a dissolved chlorine concentration of less than 1500 mg / L and a dissolved sodium concentration of less than 1000 mg / L, preferably, the dissolved chlorine concentration is less than 600 mg / L and the dissolved sodium concentration is less than 300 mg / L.

[0035] According to some embodiments, the solution may further include a divalent salt of magnesium sulfate or calcium sulfate.

[0036] According to some embodiments, provided herein is a method for recovering oil from a carbonate reservoir, comprising dissolving 1-10 grams of a solid chemical composition in 1 liter of low-salinity injection water containing 0.4% or less TDS to obtain a recovery solution; injecting the recovery solution into the reservoir to promote oil recovery; and wherein the solid chemical composition comprises: polyhalite in the range of 70 to 99.5% by weight; NaCl in the range of 5 to 30% by weight; and SiO2 in the range of 0.1 to 5% by weight.

[0037] According to some embodiments, the method may further comprise heating the recovery solution to a temperature between 30-130 degrees before injecting the solution into the reservoir. DETAILED DESCRIPTION

[0038] According to some demonstrative embodiments, provided herein is a solution for recovering oil from a carbonate reservoir, comprising polyhalite and injection water selected from the group consisting of seawater, diluted seawater, desalinated seawater, produced water, aquifer water, river water, or combinations thereof.

[0039] According to some embodiments, the concentration of polyhalite in the injected water may be 0.1 to 100 g / L, preferably between 1 and 10 g / L.

[0040] According to some illustrative embodiments, provided herein is a liquid solution for recovering petroleum from a carbonate reservoir, comprising a solid chemical composition comprising: polyhalite in a range of 70 to 99.5 weight percent; NaCl in a range of 5 to 30 weight percent; SiO2 in a range of 0.1 to 5 weight percent; and injection water selected from the group consisting of seawater, diluted seawater, desalinated seawater, produced water, aquifer water, river water, surface water, fresh water, distilled water, or a combination thereof; wherein the solid chemical composition is dissolved in the injection water in an amount of 1-10 grams of the solid chemical composition per 1 liter of the injection water.

[0041] According to some embodiments, the injection water may be low-salinity water selected from the group consisting of surface water, fresh water, distilled water, or combinations thereof.

[0042] According to some embodiments, the low salinity water may include a total dissolved solids (TDS) concentration of 0.4% or less.

[0043] According to some embodiments, the unique combination of polyhalite and low-salinity water provides a beneficial impact on oil recovery.

[0044] According to some embodiments, adding polyhalite to water (especially low salinity water) to recover oil is counterintuitive because polyhalite dissolution is believed to be low and precipitation may occur, blocking pores and preventing effective oil recovery.

[0045] According to some embodiments, the specific challenges of pore-closing precipitation can be prevented when the solution of the present invention comprises a dissolved chlorine concentration of less than 1500 mg / L and a dissolved sodium concentration of less than 1000 mg / L, preferably, a dissolved chlorine concentration of less than 600 mg / L and a dissolved sodium concentration of less than 300 mg / L.

[0046] According to some embodiments, the solution may further include a divalent salt of magnesium sulfate or calcium sulfate.

[0047] According to some embodiments, provided herein is a method for recovering oil from a carbonate reservoir, comprising dissolving 1-10 grams of a solid chemical composition in 1 liter of low-salinity injection water containing 0.4% or less TDS to obtain a recovery solution; injecting the recovery solution into the reservoir to promote oil recovery; and wherein the solid chemical composition comprises: polyhalite in the range of 70 to 99.5% by weight; NaCl in the range of 5 to 30% by weight; and SiO2 in the range of 0.1 to 5% by weight.

[0048] According to some embodiments, the method may further comprise heating the recovery solution to a temperature between 30-130 degrees before injecting the solution into the reservoir, preferably 80-120 degrees, most preferably 90-110 degrees.

[0049] According to some demonstrative embodiments, the injection water may be enriched with surface materials having added divalent salts.

[0050] According to some demonstrative embodiments, the solution may further include divalent salts of magnesium sulfate and / or calcium sulfate.

[0051] According to some demonstrative embodiments, provided herein is a method for recovering oil from a carbonate reservoir, comprising adding polyhalite to injection water; injecting the injection water to enhance oil recovery; and wherein the injection water is selected from the group consisting of seawater, diluted seawater, desalinated seawater, produced water, aquifer water, river water, or combinations thereof.

[0052] According to some embodiments, the solutions of the present invention contain divalent ions, such as sulfate ions, magnesium ions, and calcium ions, at various concentrations to increase oil recovery, wherein the source of the divalent ions can be polyhalite, for example.

[0053] Polyhalite is an evaporite mineral that is a hydrated sulfate of potassium, calcium, and magnesium with the formula: K2Ca2Mg(SO4)42H2O. Polyhalite is often used as a fertilizer because it contains four important nutrients and is low in chloride:

[0054] 48% SO3 in the form of sulfate

[0055] 14% K2O

[0056] 6% MgO

[0057] 17% CaO

[0058] According to some demonstrative embodiments, the use of polyhalite in injection water may enhance oil recovery from a reservoir.

[0059] According to some embodiments, the injection water may preferably be seawater.

[0060] According to some embodiments, other sulfate minerals may be added to the injection water, either in place of or in addition to polyhalite. According to some embodiments, the sulfate mineral may be selected from the group consisting of anhydrite, gypsum, kieserite, epsomite, glauberite, blodite, langbeinite, kainite, and schonite.

[0061] According to some embodiments, the use of polyhalite in the injection water allows for the release of divalent ions, which aids in the wettability of the carbonate reservoir.

[0062] According to some embodiments, the carbonate rock surface has a positive charge and chloride ions attached to the surface. Reducing the sodium chloride concentration or increasing the sulfate ion concentration may have an impact on oil recovery.

[0063] According to some embodiments, sulfate anions can neutralize the positive charge on the carbonate rock surface and allow calcium cations to escape from the crude oil through the pores of the well wall.

[0064] According to some embodiments, magnesium ions can also enhance oil recovery by increasing the wettability properties of the oil-carbonate surface.

[0065] According to some embodiments, the solutions of the present invention may also contain additional substances that can further enhance oil recovery, including, for example, bases, surfactants, and / or polymers.

[0066] According to some embodiments, provided herein is a liquid composition for use in oil recovery (also referred to as "smart water"), wherein the composition comprises a polyhalite brine.

[0067] According to some embodiments, the liquid composition may preferably be a solution.

[0068] According to some embodiments, wettability modification may be achieved using polyhalite-based brines.

[0069] According to some embodiments, provided herein is a use of a liquid composition comprising polyhalite brine for oil recovery, wherein the use comprises using the composition at elevated temperature, preferably between 25 and 150 degrees, most preferably between 40-120 degrees.

[0070] According to some embodiments, the use of a particular polyhalite salt is preferred due to its high and different solubility in seawater (SW), distilled water (DW), e.g. at a concentration of 5 g / L, more than 95% of the used salt is completely dissolved.

[0071] According to some embodiments, the solution of the present invention comprises at least three ions Mg 2+ , Ca 2+ and SO4 2- , which are obtained by mixing polyhalite salts with DW or SW.

[0072] According to some embodiments, the method of the present invention can be used to inject any water or brine (such as surface (fresh water), seawater, aquifer water, formation water and produced reservoir water) spiked with polyhalite / polyhalite into a petroleum-bearing formation for the purpose of recovering petroleum, primarily from carbonate reservoirs, but not excluding sandstone or other petroleum reservoirs.

[0073] One of the advantages of the present invention, according to some embodiments, is that polyhalite can be easily added to water sources on a large scale and used for water injection.

[0074] Example

[0075] Example 1

[0076] At high temperatures, seawater (SW) behaves as smart water in chalk reservoirs. The efficiency of SW as smart water can be further improved by modifying the SW composition. Parametric studies confirm that Ca 2+ Ions and SO4 2- Symbiotic interactions between ions promote wettability changes. The reactivity of these ions on the mineral surface can be further enhanced by removing Na+ and Cl- ions and reducing the salinity of SW.

[0077] This example evaluates the feasibility of using polyhalite minerals as additives to fresh / seawater to produce smart water, which contains sufficient Ca in solution. 2+ and SO4 2- .

[0078] Phase 1 trial description

[0079] The solubility of various polyhalite samples in distilled water and seawater was tested, and the important potential determinant ions required for the wettability modification process were identified. 2+ and SO4 2- The resulting concentration.

[0080] The surface reactivity of these ions on CaCO3-chalk surfaces was then tested, and their potential for wettability modification was determined. These test results, designated Phase 1, will enable additional testing regimes involving oil recovery testing in the Phase 2 project.

[0081] Results Summary

[0082] The results obtained are divided by type of analysis and test and are presented below.

[0083] SEM EDAX analysis

[0084] The polyhalite sample consisted of 4 bags of powdered material. The sample was dried and coated with palladium to improve image resolution before SEM and EDAX analysis.

[0085] EDAX analysis provides an estimate of the elemental composition of the salt.

[0086] Based on the results of SEM EDAX analysis, the composition, particle size and texture of the salts appear similar. The different samples were processed into homogeneous samples. SEM images at different magnifications are depicted in Figure 1 middle.

[0087] from Figure 1 SEM images of the polyhalite sample at different magnifications can be seen, (a) 200X, (b) 1000X, (c) 5000X, and (d) 10000X.

[0088] The EDS spectra obtained for the four samples are shown in Figure 2 middle.

[0089] from Figure 2 It can be seen that the EDS spectra are as follows: (a) sample 1, (b) sample 2, (c) sample 3, and (d) sample 4.

[0090] Elemental analysis was performed on cations and anions. The results for samples 1-4 are presented in Tables 1-4 below. The samples primarily contained calcium, potassium, and magnesium cations. Regarding anions, sulfate was the major component detected in all samples.

[0091] Table 1. Elemental analysis of cations and anions of Sample 1.

[0092]

[0093] Table 2. Elemental analysis of cations and anions of Sample 2.

[0094]

[0095]

[0096] Table 3. Elemental analysis of cations and anions of Sample 3.

[0097]

[0098] Table 4. Elemental analysis of cations and anions of Sample 4.

[0099]

[0100] Dissolution testing

[0101] For dissolution testing, salts were dissolved in distilled water (DW) and seawater (SW). The brine was prepared using reagent-grade chemicals and deionized water (DI) and filtered through a 0.22 μm filter. The brine properties are shown in Table 5. Note that the pH was measured after equilibrium with the polyhalite mineral.

[0102] Table 5. Brine properties

[0103] Ion (mM) DW SW <![CDATA[[K + ]]]> 0.4 10 <![CDATA[[Ca 2+ ]]]> 0.3 13 <![CDATA[[Mg 2+ ]]]> 0.1 45 <![CDATA[[Na + ]]]> 1.9 581 <![CDATA[[Cl - ]]]> 12.5 525 <![CDATA[[HCO3]]]> - 2.0 <![CDATA[[SO4] 2- ]]> 1.2 24 pH 7.5 8.0 TDS (mg / L=ppm) - 33390 <![CDATA[Density (g / cm 3 )]]> 0.999 1.0226

[0104] Initial tests were performed at a concentration of 100 g / L to investigate the general dissolution behavior of the samples. The values ​​reported in Table 6 are the average of 5 sample measurements. The DW and SW stock solutions (STD) used in the mixture were also analyzed.

[0105] Table 6. Ionic concentration of dissolved salts at 100 g / L, average of 5 sample measurements.

[0106]

[0107]

[0108] The standard deviations of the measurements are presented in Table 7 below.

[0109] Table 7. Standard deviation of sample measurement results

[0110]

[0111] Since the undissolved residue in the 100 g / L solution accounted for more than 50% of the added sample, testing was started at a lower concentration. To minimize the residue and maximize the dissolution of the salt, 5 g of solid was added to 1 L of water, then the concentration was 5 g / L. The solution was stirred for 48 hours, and at the end of the mixing period, the color of the solution was opaque, see Figure 3 Therefore, before analysis, samples were filtered through a 0.22 μm filter, then centrifuged in a high-speed centrifuge, after which they were filtered again through another 0.22 μm filter and finally diluted, after which the ionic composition was determined using ion chromatography.

[0112] Figure 3 Are photographs of the solutions after 48 hours of mixing, (left) 5 g / L polyhalite in DW and (right) 5 g / L polyhalite in SW.

[0113] The final ion concentrations in the aqueous phase are shown below in Table 8. Also included are the average concentrations of DW-100 g / L and SW-100 g / L from the analytical results presented in Table 6.

[0114] Table 8. Summary of ion concentrations from dissolution testing in 100 g / L and 5 g / L DW and SW at 25°C.

[0115]

[0116] The concentration values ​​of DW-5 g / L and SW-5 g / L are the average values ​​of the measurement results of 4 samples, and the standard deviations are presented in Table 9.

[0117] Table 9. Standard deviation of sample measurement results at a concentration of 5 g / L

[0118]

[0119] The undissolved residue in the 5 g / L solution was 4.1% of the 5 grams of solid material added to the DW solution and 1.8% of the solid material added to the SW.

[0120] Residue analysis

[0121] The materials retained in the 0.22 μm filter by distilled water solution and seawater solution were analyzed by SEM images and EDAX chemical composition. Figure 4 middle.

[0122] Figure 4 Depicted are SEM images of the residues at 1000X, (a) distilled water (DW) residues, (b) seawater (SW) residues.

[0123] The particle size of the DW residue varied from 1 to 70 μm, but particles close to 10 μm were predominant. Elongated structures approximately 40 μm in size were observed in the sample. EDAX indicated that the residue was primarily composed of calcium sulfate, with a silicon content of only 5.1 atomic %. The chemical composition of the residue is presented in Table 10.

[0124] Table 10. Cationic and anionic elemental analysis of DW residues.

[0125]

[0126] The residue from the SW sample clearly contained more particles estimated to be 5 μm in size, making it smaller than the particles from the previous DW residue sample. Again, elongated structures approximately 40 μm in size were observed. EDAX indicated that the residue was primarily calcium sulfate, but at a concentration significantly lower than that observed with the DW sample. Furthermore, this sample had higher magnesium and chloride ion contents, making it significantly different from the previous sample. The chemical composition is presented in Table 11 below.

[0127] Table 11. Cationic and anionic elemental analysis of SW residues.

[0128]

[0129] The results showed that the dissolution of polyhalite minerals was higher in SW compared with DW. The total solution salinity of SW-polyhalite solution was higher than that of DW-polyhalite solution.

[0130] Therefore, the EOR performance of each solution must be experimentally tested to properly quantify their respective wettability potential. This can be investigated in a Phase 2 project, including oil and fluid recovery techniques such as spontaneous imbibition and forced displacement (waterflooding).

[0131] Temperature scan

[0132] For the dissolution tests at different temperatures, DW and SW solutions were used at a concentration of 5 g / L. After 24 hours of thermal equilibrium, the samples were centrifuged, filtered through a 0.22 μm filter and diluted before ion chromatography analysis.

[0133] After increasing the temperature to 130°C, all samples turned white, which may be attributed to the precipitation of CaSO4, as its solubility decreases with increasing temperature. The resulting solution ion concentrations as a function of temperature scan are presented in Table 12 below for the DW-solutions and in Table 13 for the SW-solutions.

[0134] Table 12. Average concentrations of 4 sample measurements at 5 g / L in DW.

[0135]

[0136] Table 13. Average concentrations of 4 samples at 5 g / L in SW.

[0137]

[0138] The results showed that temperature had a relatively small effect on ion concentrations in both DW and SW. The resulting solution contained smart water ions: sufficient concentrations of calcium, sulfate, and magnesium, which contributed to the solution's stability. Low NaCl dissolution from the minerals was positive for the overall salinity of the solution. The solution represents a potential smart water brine, and the polyhalite mineral proved to be a promising additive.

[0139] Surface reactivity testing

[0140] A chromatographic wettability test was developed to assess the wettability of carbonate rock surfaces and their reactivity with potential determinants, such as sulfate, calcium, and magnesium. The test uses a core flooding setup. The principle behind this test is the chromatographic separation of ions with different affinities for water-wetted areas of the chalk surface. The component without affinity is the tracer, lithium being used in this project, and the adsorbed ion at the water-wet sites is sulfate. Chromatographic analysis of the effluent will determine tracer and sulfate concentrations. The amount of water-wetted area will be determined by the delay in sulfate elution compared to tracer elution.

[0141] The surface reactivity of DW solutions was tested using 5 g / L polyhalite, and this solution was spiked with lithium as a tracer. Prior to injection of DW-polyhalite, the core was conditioned by injecting brine free of sulfate and tracer. Chromatographic separations of tracer and sulfate for tests conducted at 25°C and 90°C are presented in Figure 5 middle.

[0142] Figure 5 Graphs depicting the chromatographic separation between sulfate and lithium on chalk cores from the Stewins-Clint outcrop, (a) performed at 25°C and (b) performed at 90°C.

[0143] Results observed at 25°C indicate that the brine, designated DW-5 g / L, containing polyhalite, is reactive toward carbonate surfaces. The separation between the tracer curve and the sulfate curve, quantified by the trapezoidal method, was 0.10, indicating sulfate adsorption at the surface and a positive rock-brine interaction potential for wettability modification in the chalk.

[0144] Observations using a brine called DW-5 g / L containing polyhalite at 90°C showed increased reactivity, with sulfate radicals substantially retarded. The chromatographic separation area increased and was quantified as 0.43. This increase at higher temperatures is attributed to the increased reactivity of sulfate radicals at high temperatures due to dehydration and disruption of hydrogen bonds surrounding the ions in solution.

[0145] The results of this feasibility study on polyhalite for EOR purposes are promising. Phase 1 experiments demonstrated the feasibility of using polyhalite mineral as an additive to create smart water brines that can be used in carbonate oil fields to enhance production.

[0146] Polyhalite has good solubility in distilled water (DW) and seawater (SW), and the final solution concentrations of sulfate, calcium, and magnesium are suitable for preparing smart water brines. However, further refinement of the experimental procedure is needed to further reduce and minimize the residual content (4% in DW and 2% in SW when 5g of solid is added to 1L of water).

[0147] In surface reactivity tests at 25°C and 90°C, polyhalite solutions showed reactivity towards chalk. Chromatographic separation between sulfate and the tracer was confirmed at both temperatures, demonstrating significant potential for wettability modification in carbonate oil reservoirs.

[0148] To confirm and quantify the EOR potential in chalk / carbonate rocks, oil recovery tests of crude oil must be performed, including spontaneous imbibition tests and core water injection tests as well as chromatographic wettability tests at various reservoir temperatures.

[0149] Divalent anion sulfate SO4 present in polyhalite smart water 2- Compete with carboxylic acids in crude oil that are attached to the rock surface. This behavior of ions causes acidic groups to detach from the carbonate surface, thereby changing the rock wettability. In addition, the addition of divalent cations (such as calcium Ca) at elevated temperatures can 2+ and magnesium Mg 2+ ) and SO4 2- Causes wettability changes and improves oil recovery.

[0150] Example 2

[0151] Seawater injection is a successful EOR in North Sea carbonate reservoirs because wettability changes to a more water-wet state, triggered by the compositional differences between the injected and formation waters. "Smart water" with optimized ionic composition can be readily prepared in the laboratory to enhance oil recovery over seawater; however, its preparation in the oil field may require specialized water treatment processes such as desalination, nanofiltration, or the addition of specialized salts.

[0152] To overcome these challenges, polyhalites (also referred to herein as "polysulfates" or "(PS)") can be used as additives in solutions used for oil recovery, ie, to produce smart water.

[0153] According to some embodiments, this experiment investigated the potential and efficiency of polyhalite brines to alter chalk wettability using outcrop chalk from Stewins-Clint (composed of 98% biogenic CaCO). The solubility of polyhalite in seawater and deionized water, as well as the brine stability at high temperatures, were measured. Energy-dispersive X-ray and ion chromatography were used to determine the composition of polyhalite salts and EOR solutions, and sulfate adsorption (a catalyst for wettability modification) on the chalk surface was evaluated. Spontaneous imbibition of polyhalite brines into mixed wet chalk (to evaluate wettability modification) was conducted at 90°C and 110°C and compared to the recovery performance of formation water and seawater.

[0154] Solubility tests showed that the salt was readily soluble in deionized water and seawater, with less than 5% solid residue. The deionized polyhalite brine contained sulfate and calcium concentrations of 31.5 millimolar (mM) and 15.2 mM, respectively, and a total salinity of 4.9 g / L. This brine composition is promising for triggering wettability changes in chalk. The seawater polyhalite brine contained 29.6 mM calcium and 55.9 mM sulfate, with a total salinity of 38.1 g / L. Compared to normal seawater, this brine has the potential to improve wettability changes in chalk due to its increased sulfate content.

[0155] Ion chromatography revealed sulfate adsorption when polyhalite brine was injected through the core, indicating that wettability changes may have occurred during brine injection. Reactivity was also enhanced by increasing the temperature from 25°C to 90°C. Finally, oil recovery tests using spontaneous imbibition demonstrated that polyhalite brine can induce wettability changes, enhancing oil recovery beyond that achieved through formation water injection. Due to the inherently favorable composition of seawater, the difference in oil recovery between normal seawater and polyhalite-injected seawater was minimal.

[0156] Polyhalite brines exhibit significant wettability modification potential in carbonate rocks and have been validated as potential EOR additives for the easy, on-site preparation of smart water brines for carbonate reservoirs. Polyhalite salts added to EOR solutions provide the necessary ions for the wettability modification process, but further optimization is needed to characterize the optimal mixing ratio, ion composition, and temperature range over which EOR effects can be achieved.

[0157] Carbonate reservoirs hold approximately 50% of the world's oil and gas reserves, of which over 60% are oil reserves and 40% are natural gas reserves. Despite their vast reserves, oil recovered from these reservoirs is typically less than 30% of the oil in place (OOIP), making the potential for enhanced oil recovery (EOR) from carbonates very attractive.

[0158] Carbonate reservoirs are known to be challenging environments for oil production. Reservoir and production engineers encounter difficulties due to low matrix permeability, coupled with natural fractures, and poor wettability, which typically falls within the neutral to oil-wet range. This limits capillary forces and reduces the likelihood of water imbibition into the rock matrix during injection. All of these conditions can lead to fingering, premature water breakthrough, and poor oil recovery.

[0159] The wettability of carbonate rocks is highly influenced by the presence of polar organic components (POCs) in crude oil, with acidic components being more important than alkaline components. POC composition is quantified using acid number (AN) and base number (BN). When initially very water-wet carbonate cores are exposed to crude oils with increasing acid number (AN), a decrease in water wettability is observed. The influence of AN on carbonate wettability has been confirmed by other researchers. It is also important to note that the pH of the brines in carbonate rocks is buffered to slightly alkaline conditions. Therefore, the species driving rock surface wettability are dissociated carboxylic acids and deprotonated bases.

[0160] Incipient wetting of carbonate reservoirs occurs when negatively charged carboxylates adsorb onto positively charged carbonate pore surfaces. This occurs during the migration of oil into the reservoir. Because decarboxylation occurs at high temperatures, reservoir temperature can affect crude oil chemistry. These processes reduce the oil's anodic acidity (AN). Therefore, higher water-wetting observed in carbonate reservoirs may be associated with crude oils with low AN or high-temperature reservoirs.

[0161] Water-based EOR methods are crucial in heterogeneous reservoirs, as they can promote a more water-wet state despite altered wettability. Increased capillary forces promote spontaneous brine imbibition from fractures into the matrix, mobilizing trapped oil. Delaying water breakthrough by exploiting reservoir heterogeneity is highly valuable for increasing oil production in carbonate reservoirs. According to some embodiments, smart water is a method that meets all of these requirements, produced simply by modifying the ionic composition of the injected water.

[0162] The well-known smart water EOR effect has been observed in naturally fractured chalk oil fields in the North Sea by injecting seawater. The wettability is altered by the presence of specific ions in seawater, calcium ions (Ca 2+ ), magnesium ions (Mg 2+ ) and sulfate ions (SO4 2- ). The wettability change is caused by specific ions present in seawater: calcium, magnesium and sulfate. The catalyst for this process was identified as sulfate ions present in SW, and calcium ions also appear to be an important ion that can co-adsorb on the chalk surface, promoting the wettability change process. Magnesium ions appear to be relevant at high temperatures, where they can exchange with calcium ions on the chalk surface, making more calcium ions available in the bulk fluid, which subsequently has a positive impact on the EOR effect. Figure 6 The effects of increasing sulfate and calcium concentrations on saline imbibition were observed in ab.

[0163] Further modification of the SW composition could improve the oil recovery factor in carbonate rocks. For example, a reduction in the NaCl concentration in the SW or an increase in the catalyst (sulfate) concentration in the brine could be a way to increase the oil recovery factor beyond the wettability modification potential of the SW ( Figure 7 ).

[0164] The wettability modification process in carbonate rocks is also temperature-dependent, and it appears that the enhanced oil recovery effect is enhanced at higher temperatures. The reason behind this effect is related to the increased reactivity of ions on the carbonate surface.

[0165] As temperature increases, the ions present in water decrease their hydration number; this change translates into fewer water molecules surrounding them, allowing for more interactions between the ions and increasing their chemical reactivity. Temperature effects can affect both established initial wetting processes and wettability modification processes.

[0166] In the smart water EOR mechanism of carbonate rocks, SO4 2- The adsorption of ions to the rock surface will reduce the positive surface charge and promote the 2+ (which is the common ion of CaCO3). Then, Ca 2+ The acidic components adsorbed on the surface (mainly dissociated carboxylic acid (RCOO) - ) as a representative) reacts with each other. Then, Ca 2+ The acidic components adsorbed on the surface (mainly dissociated carboxylic acid (RCOO) - ) will trigger the desorption of organic molecules and change the wettability, such as Figure 8 shown.

[0167] According to some embodiments, Figure 8 This is a schematic diagram of the smart water mechanism in carbonate rocks. The active ion is SO4 2- and Ca 2+ At high temperatures, Mg 2+ Becomes more active, affecting the Ca in the solution 2+ concentration.

[0168] According to some embodiments, temperature may also affect this process. 2+ Ions also become more reactive at high temperatures due to dehydration. Experiments have confirmed that Mg 2+ Can interact with the calcite surface and release more Ca into the surrounding environment 2+ ions, accelerating the process of wettability change. At high temperatures, Mg 2+ Ions also react with SO4 2- Ion complexation reduces CaSO4 precipitation, which will reduce the amount of Ca required for wettability change. 2+ and SO42- concentration.

[0169] In the comparative study conducted, the effects of different SO4 2- , Ca 2+ and Mg 2+ Several SI tests were performed at different concentrations. It was found that the effect of calcium was highly relevant but required the presence of sulfate ( Figure 9 ).

[0170] According to some embodiments, Figure 9 The graph in the figure shows that the SO4 2- , Ca 2+ and Mg 2+ Spontaneous imbibition of SW on chalk cores, concentrations and temperatures.

[0171] Producing smart water for carbonate oilfield applications is a challenge. Efforts have been made to improve seawater using a combination of reverse osmosis (RO) and nanofiltration. However, these methods are highly energy-intensive and require significant investment, increasing both capital expenditures (CAPEX) and operating expenditures (OPEX). Therefore, there is a need to produce smart water at a low cost, thereby reducing the OPEX and CAPEX impact of oil production activities.

[0172] Previous attempts have used SW nanofiltration to produce a retentate rich in divalent ions and a permeate free of divalent ions. By obtaining these two solutions, they can be used as the main stock solution for preparing new smart water brines. The process requires a pressure of 9 to 18 bars to force the seawater flow through a semipermeable membrane, such as Figure 10 1 , which shows a nanofiltration process using seawater (SW) as a primary feed, according to some demonstrative embodiments.

[0173] The results show that nanofiltration using seawater as the primary feed cannot effectively produce smart water that is enriched in divalent ions and has reduced salinity (monovalent ions). We quantified the ion retention at different pressures and present it in Figure 11 middle.

[0174] One price Na + and Cl - The rejection of ions is 15-35%. When the pressure increases from 9 to 18 bar, the rejection of calcium increases from 55% to 70%. Although the concentration of monovalent and divalent ions in the permeate can be varied, typically only 5-20% of the feed is allocated to the permeate, resulting in an ion concentration in the retentate close to that of seawater.

[0175] According to some embodiments, polyhalite salts have been shown to be effective as additives for smart water preparation for EOR. The dissolution of polyhalite in water / brine provides potential determinant ions required for the carbonate wettability modification process.

[0176] Example 3

[0177] The performance of polyhalite as an additive can be evaluated based on dissolution tests, chemical reactivity tests and spontaneous imbibition on recovered mixed wet chalk cores.

[0178] Experimental work

[0179] Material

[0180] rock samples

[0181] The experiments used chalk collected from outcrops at the Steyvens-Klint (SK) quarry near Copenhagen, Denmark, and known to be a good analog of North Sea chalk oil reservoirs. SK chalk consists of 98% pure CaCO3 of biogenic origin, with coccoliths and fragments forming the building blocks of the material. The characteristic permeability is between 1 and 10 md, and the porosity is relatively high (45-50%). The pore size distribution typically ranges from 0.1 to 1 μm, as shown in Figure 1. Figure 12 shown.

[0182] Under a scanning electron microscope (SEM), the porous media structure of the material can be seen in detail, with its spherical rings and fragments shown in Figure 13 (which depicts an SEM image of uncleaned chalk from the Steywins-Clint outcrop at 10,000x magnification.) Upon increasing the magnification of the microscope, the heterogeneity of the chalk surface is more clearly observed.

[0183] All cores were drilled from the same chalk block in the same direction and cut and shaped to the desired diameter of 3.8 cm and the desired length of 7 cm. All cores were visually inspected and no significant fractures or heterogeneity were found. The properties of the cores used in this work are given in Table 14.

[0184] Table 14. Physical properties of SK cores.

[0185]

[0186] The physical properties of the cores were similar to previously published data known in the art.

[0187] polyhalite salt

[0188] The natural polyhalite salt supplied by ICL is mined from a polyhalite rock formation located 1000m below the North Sea off the coast of North Yorkshire, UK. High-resolution images of the polyhalite salt mineral were taken using a scanning electron microscope (SEM), and its composition was analyzed using energy-dispersive X-ray (EDX). SEM images of the polyhalite salt at 5000 (a) and 1000 (b) magnifications are shown in Figure 1. Figure 14 .

[0189] The salt particles in the analyzed samples were of different sizes and were evenly distributed, with the main particle diameters ranging from 5 to 30 μm.

[0190] Elemental analysis of the cations and anions of the polyhalite sample was performed. The results are presented in Table 15 below. The composition of the sample is primarily composed of calcium, potassium, and magnesium cations. In terms of anions, sulfate is the main component detected in the sample.

[0191] Table 15. Elemental composition of cations and anions in polyhalite (in atomic weight %)

[0192]

[0193]

[0194] crude

[0195] A low-asphalt dead oil with an acid number (AN) of 2.90 mg KOH / g and a base number (BN) of 0.95 mg KOH / g was used as the source. The dead oil was diluted with 40% by weight heptane, centrifuged, and filtered through a 5 μm microporous filter. The prepared base crude oil was designated RES40 and had an AN of approximately 2.1 mg KOH / g. No asphalt precipitation was observed during filtration or storage.

[0196] A batch of RES40 oil was treated with silica gel to remove the surface active polar organic components (POC) to obtain an oil with AN = 0.0 mgKOH / g, designated as RES40-0 oil.

[0197] The diluted oil RES40 and the silica treated oil RES40-0 were then mixed in specific proportions to obtain the crude oil used in these experiments (Oil A) with AN=0.58 mg KOH / g and BN=0.30 mg KOH / g. The properties of the oils are reported in Table 16.

[0198] Table 16. Oil properties

[0199]

[0200] The AN and BN of the oil sample were analyzed by potentiometric titration according to the procedure, and the density and viscosity of the prepared oil A were determined to be 0.81 g / cm 3 and 2.4cP.

[0201] brine

[0202] The seawater (SW) and formation water (FW) brines used in this experiment were prepared by mixing distilled water (DW) with reagent-grade salt. The SW composition was based on North Sea seawater. The FW composition was based on formation water from the North Sea chalk reservoir. The SW and FW brines were mixed overnight by magnetic spinning and filtered through a 0.22 μm Millipore filter. The properties of the SW and FW brines are shown in Table 17.

[0203] DW0T and DW1T brines were used for chromatographic wettability testing. The brines were modified to use polyhalite salt as one of the ion sources. The other ion source, adjusted in composition, was reagent-grade salt. The brine compositions are listed in Table 17.

[0204] Dissolution of polyhalite

[0205] Polyhalite brines DW-PS and SW-PS were prepared by mixing distilled water (DW) and seawater (SW) to provide 5.00 g of polyhalite (PS) per liter of solution. The solutions were mixed with a magnetic stirrer for 6 days and then filtered through a 0.22 μm Millipore filter. Very similar amounts of polyhalite salt dissolved regardless of the aqueous solution used (i.e., brine or distilled water). Therefore, the solubility of the salts in the different brines was high, with over 95% of the added salt dissolved during mixing (Table 17).

[0206] Table 17. Properties of brine.

[0207]

[0208] Surface reactivity testing

[0209] The surface reactivity of chalk cores with DW-PS at different temperatures (25°C and 90°C) was investigated using a chromatographic wettability test, developed to evaluate wettability and the reactivity of potential determinants of ions (such as sulfate, calcium, and magnesium) with carbonate surfaces. The test used a core water injection setup. First, the cores were water-injected (5-6 PV) with DWOT (a brine with similar ion concentrations to DW-PS but depleted of sulfate).

[0210] Then use DW1T (with a small amount of Li +The core is water-flooded with DW-PS brine (using a tracer containing sulfate ions). The tracer has no affinity for chalk minerals and follows the displacement front. Sulfate, on the other hand, has an affinity for water-wet minerals and therefore exits later than the tracer. Ion chromatography (IC) analysis of the effluent will determine the concentrations of tracer and sulfate. The relative amount of water-wet area, or the reactivity of sulfate towards water-wet chalk minerals, will be determined by the delay in sulfate elution relative to the tracer elution.

[0211] Core recovery

[0212] Initial water saturation (S wi )

[0213] All cores were initially cleaned by flooding with 5 PV distilled water (DW) at room temperature to remove readily soluble salts, especially sulfates. The cores were then dried at 90°C to constant weight. Initial formation water saturation (S wi ) was determined to be 10% by using a dessicator technique and stored in a sealed container for 3 days to allow for uniform ion distribution within the core.

[0214] Oil exposure and aging

[0215] S wi = 10% of the core was vacuum saturated with Oil A, followed by water injection at 1.5 PV in each direction at 50° C. Finally, the core was wrapped in Teflon tape to avoid unrepresentative wetting on the outer surface and aged in the same oil at 90° C. for 2 weeks to achieve more homogeneous core wetting.

[0216] Oil recovery by spontaneous imbibition

[0217] Spontaneous imbibition (SI) experiments were performed on the recovered cores to evaluate the initial core wettability and the performance of different brines as EOR fluids. The imbibition experiments were conducted at 90°C and 110°C at 10 bar back pressure using FW, SW, DW-PS, and SW-PS as imbibition brines. The volume of oil produced was calculated as the percentage of original oil in place (%OOIP) relative to time. The experimental setup is depicted in Figure 15 middle.

[0218] Results and discussion

[0219] Dissolution of polyhalite salts in DW and SW.

[0220] The solubility of polyhalite mineral in distilled water (DW) was tested. Exactly 5.00 grams of polyhalite (PS) salt was added to 1 liter of DW or SW. The DW-PS and SW-PS solutions were mixed on a magnetic stirrer at 23°C for 6 days.

[0221] The brine was then filtered through a 0.22 μm filter. The ionic composition of the filtered brine was analyzed by IC. The filter, along with the insoluble particles in the salt, was dried and quantified by weight. The particles were also analyzed using SEM and EDX. The compositions of the DW-PS and SW-PS brine after 6 days of mixing are shown in Table 17.

[0222] We observed minimal variations in the ionic composition between batches. To avoid concentration variations, 20 L of stock solutions of DW-PS and SW-PS were prepared to obtain a homogeneous composition throughout the planned experimental work.

[0223] Polyhalite in distilled water (DW-PS)

[0224] The ionic composition after diluting 5.00 g to 1 liter with DW showed a sulfate concentration of 31.5 mM, slightly higher than the concentration in SW (24 mM). The calcium concentration was 15.2 mM and the magnesium concentration was 5.8 mM. The largest difference was observed for magnesium compared to SW, which was 44.5 mM in SW. The polyhalite salts also contained a large amount of potassium, with a concentration of 14.4 mM. The total salinity of DW-PS was 4885 ppm, with relatively low concentrations of sodium (6.3 mM) and chloride ions (9.2 mM). The insoluble portion of PS after filtration was 0.115 g, which means that the solid residue only accounted for 2.3% of the total PS salts added to DW.

[0225] Polyhalite in Seawater (SW-PS)

[0226] After diluting 5.00 g of PS salt to 1 liter with seawater (SW), the sulfate concentration in the SW-PS was 55.9 mM. This represents an increase of 31.9 mM compared to SW (24.0 mM). The calcium concentration was 29.6 mM, representing an increase of 16.6 mM compared to SW (13.0 mM). The magnesium concentration was 47.9 mM, confirming an increase of 3.4 mM after PS exposure. The potassium concentration increased from 10.1 mM in SW to 28.2 mM in SW-PS, representing an increase of 18.1 mM. The total salinity of the SW-PS brine was 38,140 ppm, an increase of 4,760 ppm. The solid residue after filtration was only 0.200 g, representing 4.0% of the PS added to the SW.

[0227] It appears that the concentrations of calcium, sulfate, and magnesium ions in both DW-PS and SW-PS brines are sufficient to trigger the smart water effect. However, since these ions are already present in seawater, their concentrations are greater in the SW-PS solution.

[0228] It was observed that similar amounts of polyhalite salt dissolved regardless of the aqueous solution used (i.e., brine or distilled water). More than 95% of the salt dissolved during mixing. This may be attributed to the elemental composition of the salt, Table 15.

[0229] Residue analysis

[0230] After filtration with a 0.22 μm millipore filter, the residue was dried and analyzed by SEM and EDAX. SEM images of the DW and SW residues are presented in Figure 16 middle.

[0231] Figure 16 Depicted are SEM images of PS residues at 5000X magnification after filtration through a 0.22 μm Millipore filter: (a) DW residues, (b) SW residues.

[0232] The particle size of the residue ranged from 0.2 μm to 30 μm. Different particle shapes were observed under the microscope. Irregular particles were the most common in both samples, but elongated crystals also appeared to be part of the residue. However, in the presence of SW, smaller particles were more common, and the particle surfaces appeared to be more abraded.

[0233] The elemental analysis of the residues of these two samples was carried out, Table 18.

[0234] Table 18. Cation analysis of DW and SW residues after filtration.

[0235]

[0236] The insoluble residue was primarily composed of calcium, potassium, and magnesium cations. Regarding anions, sulfate was the main component detected. The DW residue contained more calcium and sulfur than the SW residue. On the other hand, the SW residue had more silica and aluminum. These indicators suggest that SW dissolution may be more efficient.

[0237] Surface reactivity testing

[0238] To evaluate whether the ions present in DW after PS exposure interact with the CaCO3 surface in the porous rock system and promote the wettability required for smart water, a surface reactivity test was designed using Stewins-Clint chalk based on the test conducted by Strand et al. (2006). The chromatographic brine prepared was a 5 g / L DW-PS brine spiked with lithium as a tracer. This brine was designated DW1T, and its composition is shown in Table 17. In the laboratory, DW0T brine was prepared using reagent salts (excluding sulfate and lithium ions) based on the SW1T composition.

[0239] Chromatographic surface reactivity tests were performed using 100% water-saturated SK chalk core SK9 at 23°C and 90°C. The chromatographic separation between the lithium tracer and sulfate is shown in Figure 17 As can be seen, lithium on chalk core SK9 from the Steywins-Clint outcrop, (a) at 23°C and (b) at 90°C, using DW0T followed by DW1T at an injection rate of 0.2 ml / min.

[0240] The results confirmed that sulfate ions obtained from polyhalite interact with chalk and that sulfate reactivity increases with increasing temperature. The first lithium tracer was observed in the effluent after 0.8 PV injection and it reached the injected concentration after 1.4 PV. The increase in sulfate concentration was significantly delayed, especially for the tests performed at 90 °C. At 23 °C, the injected concentration of sulfate was reached after 2.0 PV, while at 90 °C, it was reached after 2.2 PV. The separation area (A) between the lithium tracer and sulfate was determined by the trapezoidal method. cw ) was quantified and found to increase from 0.18 at 23°C to 0.35 at 90°C, confirming that sulfate adsorbs to the CaCO surface and that adsorption is temperature-dependent. The increased reactivity of sulfate ions at high temperatures can be explained by dehydration, which disrupts the hydrogen bonding between water molecules surrounding the sulfate ions in solution. The results of the surface reactivity tests are summarized in Table 19.

[0241] Table 19. Surface activity test data.

[0242] temperature 23℃ 90℃ Chromatographic separation was observed yes yes <![CDATA[Chromatographic separation area (A cw )]]> 0.18 0.35

[0243] In summary, SO4 2- With Li + The chromatographic separation between DW-PS and BP reveals the potential of DW-PS as a potential carbonate wettability modifier. Therefore, it is expected that increased wettability modification and oil mobilization would be observed when using this brine as smart water. The increased chromatographic separation at higher temperatures confirms the higher reactivity at high temperatures, which may also lead to enhanced EOR potential at high reservoir temperatures.

[0244] Effect of polyhalite on oil recovery

[0245] It was previously observed that SW can significantly enhance oil recovery from mixed wet limestone and chalk cores at higher temperatures. The recovery mechanism has been validated in parametric studies confirming that Ca 2+ and SO4 2- The presence of SW favors the change of wettability toward a more water-wet condition and significantly improves oil mobilization in heterogeneous pore systems. By modifying the SW composition, more efficient smart water compositions can be produced. Studies have shown that by increasing the Ca content in SW 2+ and SO42- concentration, or by reducing salinity while maintaining Ca 2+ and SO4 2- The concentration can be made into smart water.

[0246] This section investigates the effect of polyhalite as a water or brine additive to design highly effective smart water brines for mixed wet Steynes-Clint chalk cores. Steynes-Clint chalk is commonly used as an analog for North Sea chalk reservoirs. It is also important to note that the smart water EOR effects observed in chalk have also been confirmed in reservoir limestone systems. The water / brine used in this study were FW, DW, and SW, as well as smart water brines designed by adding polyhalite (PS) to DW and SW, resulting in the final compositions shown in Table 17.

[0247] Before the 4PV oil exposure of Oil A, all SK cores used in this paper were equally recovered and the initial water saturation S was determined using FW. wi = 0.1. Finally, the cores were equilibrated in Oil A for at least 2 weeks to establish more uniform core wettability.

[0248] Polyhalite at 90℃

[0249] Four equally recovered cores were used at 90°C. Spontaneous imbibition tests were performed to evaluate the wettability of the recovered cores and the oil mobilization potential by using different imbibition brines.

[0250] Core SK1 was exposed to formation water (FW) as the imbibition brine. The FW will not promote any chemical-induced wettability changes as long as the FW is also the initial brine. Oil production during spontaneous imbibition with FW will yield the wettability and baseline oil production from the recovered core.

[0251] Core SK2 was imbibed with seawater (SW) as imbibition brine. SW is known to behave as smart water that mixes with wet cores and is commonly used as injection brine for pressure support in offshore reservoirs.

[0252] The other two imbibition brines tested were distilled water with polyhalite salts (DW-PS) and seawater spiked with polyhalite (SW-PS). These brines were used to evaluate the effect of PS on improving oil mobilization through wettability modification, which is achieved by imbibing Ca in the brine. 2+ and SO4 2- The presence and concentration of ions were controlled. Core SK3 was imbibed with DW-PS, while SK4 was imbibed with SW-PS. A summary of the results at 90°C is presented in Figure 18 middle.

[0253] like Figure 18As can be seen, the tests exposed to oil core SK1 used FW as the imbibition brine for imbibition, SK2 with SW, SK3 with DW-PS, and SK4 with SW-PS.

[0254] Figure 18 The results show that after 12 days of using FW as imbibition brine, the production plateau of core SK1 reached the ultimate recovery plateau of 22% OOIP. The low imbibition of FW confirms that the recovered SK core exhibits slightly water-wet properties.

[0255] Recovered core SK2 was imbibed using the SW method. Compared to the FW method, both the imbibition rate and the ultimate oil recovery plateau of 37% OOIP after 21 days were substantially improved. This confirms that the SW method altered the wettability of the chalk core during the test, resulting in a significantly more water-wet state.

[0256] For imbibed brine with polyhalite, wettability changes also occurred. Core SK3, imbibed with DW-PS, reached a final production plateau of 35% OOIP after 28 days, which is very close to the ultimate oil recovery achieved for SW. The results confirm that fresh surface aquifer water can be made smart by adding polyhalite before injection into the reservoir.

[0257] Core SK4 achieved the highest ultimate oil recovery and imbibition rate using SW-PS as the imbibition brine. After 44 days, the ultimate oil recovery was 45% OOIP, an additional 8% OOIP improvement compared to SW. This confirms that SW can be made smarter by adding PS salt to it before injection, which increases the SO4 required to induce efficient wettability changes. 2- and Ca 2+ The concentration of ions.

[0258] Polyhalite at 110℃

[0259] To evaluate the temperature effect of using polyhalite as a smart water additive in chalk, another set of identically recovered SK cores was used in four parallel spontaneous imbibition tests at 110 °C. The soaking brine was the same as that used for 90 °C, FW, SW, DW-PS, and SW-PS.

[0260] Spontaneous imbibition of recovered core SK5 using FW as the imbibition brine provided a baseline for oil production and wettability at 110°C, as no chemical-induced wettability changes occurred when FW was used as both the initial brine and the imbibition brine during core recovery. SW was used as the imbibition brine on core SK6 as a reference for smart water.

[0261] To evaluate the effect of polyhalite as a smart water additive, DW-PS and SW-PS brines were used as imbibition brines on cores SK7 and SK8, respectively. The results of four spontaneous infiltration experiments at 110 °C are shown in Figure 19 middle.

[0262] Figure 19 The oil recovery by spontaneous imbibition in the secondary mode at 110°C in similarly restored outcrop cores is shown using FW (core SK5), SW (core SK6), DW-PW (core SK7), and SW-PS (core SK8).

[0263] As can be seen, the oil recovery results follow the same trend as observed at 90°C, with the lowest oil recovery for FW and the highest oil recovery for SW-PS brine. We also observed a significant increase in imbibition rate when the temperature was increased from 90°C to 110°C, which also led to a significant increase in ultimate oil recovery. This confirms that the chemical reactivity of sulfate and calcium ions present in the smart water brine increases with increasing temperature, which also leads to a significant increase in ultimate oil mobilization from the heterogeneous pore system.

[0264] The recovery plateau of 31% OOIP was reached with FW on core SK5 after 5 days. After 12 days, SW achieved a final oil recovery of 50% OOIP on core SK6. For imbibed brine with polyhalite, the recovery plateau of 49% with DW-PS on core SK7 was reached after 24 days. On core SK8, SW-PS achieved a maximum final oil recovery of 54% OOIP after 23 days, at which point the experiment was terminated due to inlet line fouling.

[0265] Baseline oil production with FW, without wettability alteration, confirmed slightly water-wet conditions on core SK5, consistent with experiments conducted on core SK1 at 90°C. When SW was used as the imbibition brine in core SK6, oil recovery increased from 31% OOIP with FW to 50% OOIP, an increase of 19% OOIP, confirming that core wettability changes resulted in increased imbibition rates and significantly higher oil mobilization.

[0266] By adding polyhalite to fresh water, DW-PS, we have successfully produced brine with smart water properties equivalent to SW. Using DW-PS as imbibition brine, 18% of additional oil in OOIP was mobilized from core SK7. The polyhalite added to SW significantly increased the Ca content in the SW-PS brine. 2+ (29.6mM) and SO4 2-Spontaneous imbibition of core SK8 with SW-PS brine, a more efficient smart water brine, mobilized 23% of the additional oil in the OOIP, 4% more than achieved with SW.

[0267] Effect of polyhalite on oil recovery

[0268] Based on the experimental results at 90 °C and 110 °C, it can be concluded that the brine prepared with polyhalite is validated as a wettability modifier and can be used to produce smart water with significant EOR effects.

[0269] The use of injection brines containing polyhalite outperformed the systems tested using FW. At 90°C, oil mobilization increased by 61% with DW-PS and by 105% with SW-PS. Furthermore, no salt precipitation or scaling was observed in the injection or production lines during spontaneous imbibition testing. Therefore, the best-performing brine in this set of experiments was the SW-PS brine.

[0270] At 110°C, the increase in oil mobilization relative to FW is 57% for DW-PS and 74% for SW-PS. 2+ and SO4 2- Concentrations can lead to anhydrite precipitation, as observed in the injection line after 23 days for core SK8. This could explain the relatively low performance of the SWPS compared to 90°C. If polyhalite is used as a smart water additive for a specific reservoir system, the amount of polyhalite added needs to be optimized based on the reservoir temperature, the bottomhole temperature of the injection well, and the ionic composition of the feed water.

[0271] Temperature effect

[0272] During surface reactivity testing using polyhalite brine DW-PS, it was observed that ionic reactivity increased with increasing temperature (Figure 2), which clearly indicates that temperature will affect the recovery potential of polyhalite brine. This result is consistent with previously reported results. The ultimate oil recovery results shown in spontaneous imbibition tests at 90°C and 110°C ( Figure 6-7 ) are summarized in Table 20.

[0273] Table 20. Summary of Oil Recovery Factors

[0274]

[0275] For brines that can induce wettability changes (ie, seawater, DW-PS, and SW-PS), significantly higher oil mobilization was observed at 110°C.

[0276] For SW, the ΔOOIP% relative to FW increased from 15% OOIP at 90°C to 19% OOIP at 110°C, and for DW-PS, the ΔOOIP% increased from 13% OOIP at 90°C to 17% OOIP at 110°C, Table 20.

[0277] For SW-PS, the ΔOOIP% of 23% OOIP at 90 °C does not increase when the temperature is increased to 110 °C, which is most likely because the CaSO4 precipitation will reduce the Ca required for the wettability change. 2+ and SO4 2- effective concentration.

[0278] According to some embodiments, the potential for using polyhalite as an additive exists and it may be a viable alternative among other EOR alternatives.

[0279] It is important to note that the recovery rates observed for DW-PS are very similar to those observed for seawater, which opens the possibility of using this mineral in oil recovery, such as in carbonate oil fields where seawater access is limited. The results for SW-PS show that increasing sulfate and calcium concentrations can lead to higher recoveries. Therefore, it is important to maximize their content while keeping them below a concentration threshold to avoid triggering significant scaling issues.

[0280] Another benefit of using polyhalite salts relates to improving current water management strategies. For example, when a specific water composition is required, polyhalite salts can be applied to minimize the use of expensive filtration systems (i.e., reverse osmosis or nanofiltration). This type of oilfield operation requires reliable industrial processes with low maintenance costs to ensure a stable concentration of the injection fluid, making oil production operations more reliable and predictable.

[0281] According to some embodiments, the present invention comprises using a solution comprising polyhalite brines as a new additive for smart water processes for carbonate rocks.

[0282] According to some embodiments, the present invention combines chemical and physicochemical characterization with wettability studies using chromatography and spontaneous imbibition testing. The rock material used was chalk from the Steywins-Clint outcrop, a common parameter used in carbonate wettability studies. SI testing was conducted at 90°C and 110°C using FW, SW, DW-PS, and SW-PS as imbibition brines, the latter two containing polyhalite salts. The conclusions drawn from this work are presented below.

[0283] Chromatographic wettability tests showed that it was possible to modify wettability by using polyhalite-based brines.

[0284] By increasing the temperature from 25°C to 90°C, the chromatographic separation area increased from 0.18 to 0.35, confirming that the reactivity of sulfate increased with increasing temperature.

[0285] Polyhalite salts were dissolved in seawater and distilled water. The solubility of polyhalite salts in the different brines appeared to be quite high, with more than 95% of the used salts being completely dissolved at a concentration of 5 g / L.

[0286] By mixing polyhalite salt with DW and SW, the three determining ions Mg 2+ , Ca 2+ and SO4 2- Add to these solutions.

[0287] During the SI tests, FW recovered 22% and 31% OOIP at 90°C and 110°C, respectively; these results set a minimum oil production baseline since no wettability changes were induced in these tests.

[0288] The use of DW-PS and SW-PS confirmed the altered wettability, as they recovered more oil than was observed with FW. At 90°C, oil production with DW-PS increased by 61% relative to FW, and with SW-PS by 105%. At a temperature of 110°C, the increase in brine DW-PS relative to FW was 57%, and for SW-PS, an increase of 74% was observed.

[0289] Precipitation was observed with the SW-PS brine at 110°C, occurring at the inlet line of the spontaneous unit, but its ultimate oil recovery was the highest observed at 54% OOIP.

[0290] The performance of DW-PS at 110 °C and 90 °C is very similar to that observed in the SW case, providing an opportunity to obtain injection brine with similar efficacy to SW for onshore fields with limited or restricted SW access.

[0291] While the invention has been described with respect to a limited number of embodiments, it will be appreciated that many variations, modifications and other applications of the invention may be made.

[0292] It will be understood that various features of the present invention described for clarity in the context of separate embodiments may also be provided in combination in a single embodiment. Conversely, various features of the present invention described for clarity in the context of a single embodiment may also be provided individually or in any suitable subcombination. It will also be understood by those skilled in the art that the present invention is not limited to what has been specifically shown and described above.

Claims

1. A liquid solution for recovering petroleum from a carbonate reservoir, comprising: A solid chemical composition comprising: Polyhalite in the range of 70 to 99.5% by weight; NaCl in the range of 5 to 30% by weight; SiO2 in the range of 0.1 to 5% by weight; and injection water selected from the group consisting of seawater, diluted seawater, desalinated seawater, produced water, aquifer water, river water, surface water, fresh water, distilled water, or combinations thereof; wherein the solid chemical composition is dissolved in the injection water in an amount of 1-10 grams per liter of the injection water; wherein the solution comprises a dissolved chlorine concentration of less than 1500 mg / L and a dissolved sodium concentration of less than 1000 mg / L.

2. The solution of claim 1, wherein the injection water is low-salinity water selected from the group consisting of surface water, fresh water, distilled water, or a combination thereof.

3. The solution of claim 2, wherein the low salinity water comprises a TDS of 0.4% or less.

4. The solution of claim 1, wherein the dissolved chlorine concentration is less than 600 mg / L and the dissolved sodium concentration is less than 300 mg / L.

5. The solution of claim 1, further comprising a divalent salt of magnesium sulfate or calcium sulfate.

6. A method for recovering oil from a carbonate reservoir, comprising: dissolving 1-10 grams of the solid chemical composition in 1 liter of low-salinity injection water containing 0.4% or less TDS to obtain a recovery solution; injecting the recovery solution into the reservoir to enhance oil recovery; and wherein the solid chemical composition comprises: Polyhalite in the range of 70 to 99.5% by weight; NaCl in the range of 5 to 30% by weight; SiO2 in the range of 0.1 to 5% by weight, wherein the solution comprises a dissolved chlorine concentration of less than 1500 mg / L and a dissolved sodium concentration of less than 1000 mg / L.

7. The method of claim 6, further comprising heating the recovery solution to a temperature between 30-130 degrees before injecting the recovery solution into the reservoir.

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