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Article

Geochemical and Thermodynamic Study of Formation Water for Reservoir Management in Bibi Hakimeh Oil and Gas Field, Iran

by
Seyed Hossein Hashemi
1,
Amir Karimian Torghabeh
2,3,4,*,
Abbas Niknam
5,
Seyed Abdolrasoul Hashemi
5,
Mohamad Hosein Mahmudy Gharaie
3 and
Nuno Pimentel
6,*
1
Department of Chemical Engineering, University of Mohaghegh Ardabili, Ardabil 56199-1136, Iran
2
Department of Earth Sciences, Faculty of Sciences, Shiraz University, Shiraz 71946-84471, Iran
3
Department of Geology, Faculty of Science, Ferdowsi University of Mashhad, Mashhad 91779-48974, Iran
4
Chair of Exploration Group, Fossil Energy Technologies Development Research Center, Shiraz University, Shiraz 71946-84471, Iran
5
Gachsaran Oil & Gas Producing Company, Gachsaran 75, Iran
6
Instituto Dom Luiz, Faculty of Sciences of the University of Lisbon, Lisbon University, 1749-016 Lisboa, Portugal
*
Authors to whom correspondence should be addressed.
Fuels 2025, 6(1), 11; https://doi.org/10.3390/fuels6010011
Submission received: 30 September 2024 / Revised: 18 November 2024 / Accepted: 22 January 2025 / Published: 5 February 2025
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Abstract

:
This research evaluates the mineral ions and their concentrations in formation water from five well samples of the Bibi Hakimeh oil field (Iran). The analysis reveals the presence of calcium (Ca2+), sodium (Na+), and magnesium (Mg2+) cations, as well as sulfate (SO42−), bicarbonate (HCO3−), and chloride (Cl−) anions, which are soluble in water within the Bibi Hakimeh oil formation. Furthermore, mineral deposits of CaSO4, CaSO4.2H2O, CaCO3, and MgCO3 are investigated and predicted using StimCADE 2 software. The findings highlight the significant chemical precipitation of calcium sulfate and calcium carbonate mineral deposits under the operating conditions of the Bibi Hakimeh oil well. The geochemical composition of the formation waters is discussed to understand the equilibrium conditions and possible influence of the physical parameters. Additionally, this study examines the interaction between rock and water of the Bibi Hakimeh formation, revealing a notable correlation between the concentration of calcium and magnesium ions and the water–rock reaction in this field.

1. Introduction

Understanding reservoir water properties is crucial for assessing oil or gas field development feasibility. Water production can cause scale accumulations, corrosion, and plugging issues, requiring specialized treatments. Facilities are needed to handle and treat the produced water, impacting project costs and profitability [1]. Initially, reservoir waters tend to be mixed with hydrocarbons under specific pressure and temperature conditions. Hydrocarbons in the formation are saturated with water until pumping and production begins. In addition, reservoir rocks’ open spaces and surfaces are typically coated with water, facilitating natural fluid flow. When production starts, pressure and temperature drop, causing water to separate from hydrocarbons. This pressure difference drives hydrocarbons from the formation up to the surface. Early-stage water production often forms emulsions, which can be separated without treatment, and the water is usually sourced from connate water zones [2,3].
Interstitial formation waters are known as an important fluid in oil fields. By carefully analyzing them, important geological and geochemical information can be obtained. Those waters have different mineral cations and anions, including cations such as sodium (Na+), calcium (Ca2+), barium (Ba2+), strontium (Sr2+), potassium (K+), and iron (Fe2+), as well as chloride (Cl−), sulfate (SO42−), sulfide (S2−), and bicarbonate (HCO3−) anions. In the process of oil recovery operations in the subsurface formation, especially when seawater is used for injection, the precipitation of new minerals within the surface and subsurface equipment may be significant. In other words, with the mixing of injected water and formation water, the concentration of minerals in the solution increases, promoting changes in mineral solubility, and is also affected by changes in temperature and pressure conditions in the well [4,5]. Changes in mineral solubility can lead to the precipitation of mineral deposits in oil wells and ultimately reduce the production efficiency (Figure 1).
In this study, mineral ions in the water of the formation in Bibi Hakimeh oil field were analyzed, following previous studies on the thermodynamic properties of mineral ions in solid–liquid equilibrium systems [6,7,8,9,10]. The precipitation, an accumulation of calcium sulfate, gypsum, calcium carbonate, and magnesium carbonate, was modeled in the present-day operating conditions with StimCADE 2 software.

2. Previous Studies

The formation of mineral deposits in oil systems is a major operational concern and has been considered by many researchers in recent decades.
Mitchell and Grist (1980) [11] studied the formation of carbonate and sulfate mineral sediments at the North Sea Fortis Reservoir. According to their research, due to the operation of injecting seawater into the reservoir and mixing two impure waters containing dissolved salts, the formation of barium sulfate and strontium sulfate mineral deposits is significant.
Jordan et al. (2000) [12] studied the formation of mineral sediments in the Ab Formation, in northern Alaska. Their experimental work showed that, during the process of oil recovery operations, the high amounts of strontium, barium, and calcium cations promoted significant precipitation of sulfate deposits.
Moghadasi et al. (2003) [13] evaluated the formation of mineral sediments and permeability changes in the porous environment of the oil zone reservoir. The combination of water containing calcium cations with water rich in sulfate and carbonate ions in the porous medium of the reservoir was studied. A significant reduction in the permeability ratio in the porous environment of the reservoir was modeled and observed due to the composition of the gross mineral solution and temperature changes.
Nasruddin et al. (2004) [14] studied the interaction of water formation and injected water in oil recovery operations. Their critical research approached the saturation index and calcium sulfate mineral precipitation with OKSCALE software (OS-2000), showing the effect of two incompatible waters mixing in the precipitation of mineral deposits.
Raju (2009) [15] studied the formation of mineral deposits in Saudi Aramco wells, due to water injection operations. According to the results of his study, the formation of calcium carbonate deposits can be due to conditions such as a pressure drop and pH.
Al-Roomi and Hossein (2016) [16] studied the importance of reaction kinetics in the precipitation of mineral deposits and pointed to the role of the excessive mineral cations and anions.
Ghalib and Almallah (2017) [17] studied the water of the Mishrif Formation to investigate the precipitation of mineral deposits during water injection operations. In this study, they combined the water of the Mishrif Formation with sea water, Euphrates river water, and the main drainage water of the waterfall, predicting mineral precipitation at reservoir conditions. According to their results, calcium carbonate and barium sulfate mineral sediments are the most serious problem in terms of inorganic sediments in the reservoir of the Mishrif Formation.
Wang et al. (2018) [18] studied the formation of calcium carbonate deposits despite inhibitors during oil recovery operations (EORs). The oil recovery method used injectable chemicals with a combination of surfactant and polymer, as well as inhibitors of triphosphonate-, pentaphosphonate-, and polyacrylate-based chemicals. According to the results, the performance of calcium carbonate precipitate inhibitors can be significantly affected by EOR chemicals.
Hashemi et al. (2019) [4] applied a thermodynamic model to study the conditions of water injection operations and precipitation of barium sulfate and strontium sulfate deposits in the Siri and Nusrat oil fields. The studies were based on the composition of the formation water and of the injected water (Persian Gulf water) and operating conditions. The results showed that the precipitation of barium sulfate and strontium sulfate in the Nusrat oil field is significant, whereas for the Siri oil field, with different formation waters and operating conditions, the formation of deposits is not significant.
Hashemi and Hashemi (2020) [5] studied the Nusrat oil field waters, which have a high concentration of mineral ions. According to the results of their study, the formation of mineral deposits of calcium carbonate, magnesium carbonate, and barium sulfate in the Nusrat oil field can cause problems during operation.
Ghalib et al. (2023) [19] studied the formation of oil field scales in the Mishrif Formation of Halfaya oil field by mixing it with different water sources, including Tigris river water and Gulf sea water. Using geochemical modeling, Middle Kirkuk formation water was identified as the most suitable water for injection. The results obtained in their work showed that understanding mineral precipitation through geochemical modeling can optimize injection water selection and increase oil production efficiency.

3. Materials and Methods

This study was developed in waters and wells from the Bibi Hakimeh oil field, situated in the southwest of Iran, one of the largest oil fields in the region. It is located northeast of the Delam Port, adjacent to Pazanan, Sarboury, Garangan Chilingar, Sulabdar, and Ragh-e Sefid fields. It lies to the south of the Dezful depression, with its main reservoir formations comprising Asmari and Sarvak siliciclastic formations. Additionally, it holds potential for gas production from carbonate formations. The reservoir oil layer, with an initial thickness of 1000 m above the oil–water contact at a depth of 1979 m below sea level, features a gas cap 250 m below sea level. Production formations of Asmari and Bangestan, separated by Pabdeh and Gurpi layers with a thickness of 400 m, yield minimal oil output (Figure 2) [20,21,22].
Five samples collected from formation waters of the Bibi Hakimeh field were analyzed, representing five different wells of this field. In this study, the measurement method for calcium and magnesium ions based on ASTM-D511 [23] standard, chlorine ion based on ASTM-D512 [24] standard, iron ion based on HACH 8008 [25], sodium ion using Flamephotometer, sulfate ion based on HACH 8051 [26], and bicarbonate based on handbook Betz [27] was carried out.
StimCADE 2, a commercial software by Schlumberger, was used to predict sulfate and carbonate mineral sediment. This software is used to simulate the working acid of wells and also to predict the deposition of mineral salts in oil fields. The allowable temperature range in this software is from −50 to 600 degrees Fahrenheit, and the pressure is from 15.99 to 24,999.988 psia. Carbonate, calcium sulfate (anhydrite), calcium water sulfate (gypsum), strontium sulfate, barium sulfate, and iron sulfide can be detected. This software reports saturation percentage, sediment amount, and pH. Figure 3 shows the home page of this software.

4. Results and Analysis

4.1. Thermodynamic Analysis

Table 1 presents the analysis of mineral ions in five samples of Bibi Hakimeh oil field wells. Based on the results obtained in Table 1, the cations of calcium, magnesium, and sodium, as well as anions of sulfate, chloride, and bicarbonate, in the water of the oil field formation are significant, whereas iron ions are not observed in the five samples studied.
Sulfate ions have a higher concentration than bicarbonate, which may be due to the dissolution of calcium sulphate. Also, according to the obtained results, there is a significant amount of chlorine ions in Bibi Hakimeh Formation, the source of which may be the dissolution of minerals containing chlorine ions in the water of the formation. According to the results of Table 1, due to the change in concentration (mg/L) of sodium, calcium, magnesium, chloride, sulfate, and bicarbonate ions (change in ionic strength), the solubility of mineral ions in aqueous solution water changes. In other words, due to the electrostatic forces between the ions and the short-range forces between the ions and water, electrolytic solutions can make the behavior of the aqueous solution non-ideal at low and high concentrations. By changing the solubility of mineral ions based on the appropriate temperature and pressure conditions of the reservoir, the formation of mineral sediment at the inlet of the well in the reservoir and along the well is exploited.
The level of saltiness in underground water depends on factors like water flow, depth, movement, how well substances dissolve, chemical exchanges, the creation of minerals, reducing sulfate, and how water passes through clayey shale layers [28]. Sulfate reduction in oil field water is thought to happen alongside certain minerals (like gypsum, celestite, and barite), forming from cations like calcium, strontium, and barium. These reactions are connected to interactions with hydrocarbons and might decrease over time [29]. Even though sodium dissolves easily, having a lot of it does not always lead to a buildup of alkaline deposits. Double-charged ions can easily switch places with single-charged ions [30].
The pH values of formation water samples in Bibi Hakimeh oil and gas field range from 6.16 to 6.99 (Table 1). These results emphasize that the formation water in this area is mainly acidic water. Bicarbonates mainly come from carbonates dissolving when the pH is acidic, typically between 5 and 7 [31].
Table 2 presents the mineral sediment prediction of calcium carbonate, magnesium carbonate, calcium sulfate, and gypsum for five samples of wells in Bibi Hakimeh oil field. According to Table 2, for samples 1 to 5, the formation of calcium carbonate precipitate is significant. Calcium sulfate mineral deposition is also expected for sample 5. However, based on the concentration of water-soluble ions and the temperature and pressure conditions of the well, the formation of gypsum and magnesium carbonate mineral deposits is not possible.
According to the results of Table 2, with increasing temperature and pressure, the saturation of gypsum (CaSO4.2H2O) decreases, whereas that of magnesium carbonate increases. This can be related to the solubility of magnesium carbonate and gypsum as well as the activity coefficient of calcium, magnesium, bicarbonate, and sulfate ions.
In Table 3, the amount of mineral sediment formation for the studied samples (based on well temperature and pressure conditions) in Bibi Hakimeh oil field is presented. According to the results of Table 3, the formation of calcium carbonate and calcium sulfate (anhydrite) mineral deposits is significant. In other words, according to the results of StimCADE 2 software, calcium carbonate deposition in all five studied samples is supersaturated and can cause problems in the facilities of this oil field, with sample 3 having the highest and sample 1 the lowest amount of calcium carbonate deposition that can be expected. Also, according to the evaluation of the formation of calcium sulfate (anhydrite), only in sample 5 is the formation of this sediment significant, while in the other four cases it is unsaturated. According to the results of Table 3, the effect of operating conditions such as temperature and pressure on the process of increasing the formation of mineral sediments in oilfield facilities is significant.

4.2. Geochemical Analysis

Table 4 presents the hydrochemical properties of the mineral ions in the water of the Bibi Hakimeh oil field formation.
Sodium/chloride ratio—this ratio is in the range of 0.22 to 0.58 and always less than 1, pointing to old residual seawater sealed in the reservoir [32,33,34]. The reason for the lower weight and molar ratio of sodium to chloride in oil brines is the ion exchange of sodium and its subsequent depletion over time. As sodium exits the environment gradually, the ratio of sodium decreases while that of chloride increases. This occurs due to the lack of reaction between chloride and other ions. Another characteristic of oil brines is their low sulfate content compared to halite brines [35].
(Ca2+ + Mg2+)/SO42− ratio—this ratio varies from 1.97 to 9.37, with these high values pointing to oil brines, whereas halite brines are typically around 1 [35].
Ca2+/Cl− ratio—this ratio is in the range of 0.018 to 0.06, with very low values suggesting a marine origin [29].
Mg2+/Cl− ratio—this ration is in the range of 0.0073 to 0.0113, resulting from the presence of MgCl2 and signaling hydrocarbon accumulation or diagenetic processes [29].
SO42−/Cl− ratio—this ratio is in the range of 0.0074 to 0.014, which is quite low, suggesting limited deep-water circulation, leading to sulfate reduction [29].
SO42−/HCO3− ratio—this ratio is in the range of 1.639 to 10.655, reflecting specific chemical reactions near hydrocarbon accumulations, serving as an indicator of water’s proximity to hydrocarbons [29].
(Cl− − Na+)/Mg2+ ratio—this ratio is also called the “metamorphic coefficient” and is considered to evaluate the degree of water–rock interaction and ion replacement [36,37]. According to Table 4, this ratio in the five water samples of the formation in Bibi Hakimeh is in the range of 46.57 to 73.18. Strong interactions between water and rock [38] are one of the most important reasons for the high value of the metamorphic coefficient in the five samples studied in the Bibi Hakimeh oil field. Therefore, it is mainly displaced by Ca2+ and by two mineral ions, Na+ and Mg2+, and as a result, they have high metamorphic coefficients.
(Mg2+/Ca2+) ratio—the ratio of magnesium to calcium in the water of Bibi Hakimeh Formation is less than one. In other words, the concentration of calcium ions is higher than that of magnesium, which can be caused by dolomite formation (an important factor in controlling the concentration of Ca2+ and Mg2+) in the water of the formation conditions [32,39,40,41,42,43,44]. Considering that the Mg2+/Ca2+ ratios are less than one, in Bibi Hakimeh Formation, good hydrocarbon storage may be predicted [38].
(HCO3− − CO32−)/Ca2+) ratio—this ratio is in the range of 0.04 to 0.08, which is considered to be suitable for hydrocarbon storage and production [45,46,47,48].
(HCO3−)/Cl− ratio—this ration is in the range of 0.00085 to 0.0046; considering that the ratio 0.006 ≥ (HCO3−)/Cl− and also the ratio of (Cl− − Na+)/Mg2+ > 17.855 [38], the formation of Bibi Hakimeh oil field has suitable conditions for gas storage and production.
According to the Piper diagrams for the five water samples of the Bibi Hakimeh oil and gas field, the amount of chloride and sodium is significant, and the amount of calcium and magnesium is noticeable (Figure 4).

4.3. Water and Formation Rock

In Figure 5, the distribution of elements in the formation rock in the Bibi Hakimeh oil and gas field can be seen. The amount of calcium and magnesium are important elements of this formation. According to the concentration of ions presented in Table 1, there is a significant relationship between the concentration of calcium and magnesium ions in the formation water and the amount of these two minerals in the formation rock. In other words, it can be pointed out that the chemical composition of the formation water is clearly related to formation rock of Bibi Hakimeh oil and gas field. Meanwhile, the origin of other mineral ions, such as sodium, chlorine, sulfate, and carbonate, in formation water can be related to ancient sea water.

5. Discussion and Conclusions

The analysis of formation water in oil and gas fields with carbonate reservoirs has been addressed by several studies to understand the problems related to the chemical precipitation of secondary minerals. Formation water geochemistry depends highly on the nature of the rocks and the nature of the original water contained in these rocks. In carbonate rocks such as those in the Bibi Hakimeh oil and gas field the significance of cationic and anionic mineral particles in aqueous solutions derived from the interaction with the rocks cannot be overstated. In chemical systems with the presence of hydrocarbons, such as the studied field, this interaction tends to be more complex, leading to dissolution and precipitation and eventually decreased production efficiency and operational challenges in oil wells.
To increase complexity, the composition of the original formation water may be highly variable, ranging from pure meteoric water (with very low TDS) to normal salinity seawater or even highly evolved deep brines. Analyzing formation waters in Ordovician carbonates, Xu et al. (2002) detected a gradual substitution of meteoric water by seawater, increasing in time and depth [49]. These waters have been responsible for the increasing dissolution of carbonates, thus improving the reservoir potential of the Ordovician limestones. In the present study, the influence of seawater was detected, which may have also contributed to the dissolution of the Bibi Hakimeh carbonates and the enrichment in calcium and magnesium. This process has probably improved the reservoir potential, as it did in those Ordovician limestones.
In another study, Yu et al. (2020) considered the original water to be mainly seawater, strongly interacting with the carbonate rocks and with its hydrocarbon content in Ordos basin gas fields [38]. This interaction changed its composition and the formation water chemistry showed a clear correlation with hydrocarbon preservation, pointing to a geological indicator to hydrocarbon exploration. In the present study, we considered the presence and effects of seawater, and several geochemical indicators pointed to good hydrocarbon storage potential. This finding may become a regional lead for other hydrocarbon accumulations.
-
The hydrochemical analysis and water geochemistry of five wells at the Bibi Hakimeh oil and gas field pointed to strong geochemical interactions and potential production consequences, with the following key conclusions:
-
A comparison between the water formation and Bibi Hakimeh formation rock indicates that, except for calcium (Ca2+) and magnesium (Mg2+) ions, the source of ions in the water reservoir is not the rock reservoir itself but rather original marine water.
-
Under the temperature and pressure conditions of the Bibi Hakimeh oil field, the precipitation of calcium carbonate and calcium sulfate is to be expected.
-
The concentration of mineral ions such as calcium, sodium, magnesium, sulfate, chloride, and bicarbonate in the water of the Bibi Hakimeh oil field formation can significantly impact the oil exploitation process.
-
The geochemical properties of water from the Bibi Hakimeh oil and gas field formation suggest suitable conditions for gas storage and production.

Author Contributions

Conceptualization, S.H.H. and A.K.T.; methodology; S.H.H. and A.K.T.; software, S.H.H.; validation and data curation, S.H.H., A.K.T., A.N., S.A.H., M.G. and N.P.; writing—original draft preparation, S.H.H. and A.K.T.; writing—review and editing, N.P. and A.K.T., supervision, S.H.H. and A.K.T. All authors have read and agreed to the published version of the manuscript.

Funding

This research received no external funding.

Data Availability Statement

The original contributions presented in this study are included in the article. Further inquiries can be directed to the corresponding authors.

Acknowledgments

We are thankful to both reviewers for their constructive comments and suggestions, which contributed to improving the final version of this paper.

Conflicts of Interest

Seyed Abdolrasoul Hashemi was employed by Gachsaran Oil & Gas Producing Company. The remaining authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

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Figure 1. Schematic of mineral sediment formation during operation in an oil well [1].
Figure 1. Schematic of mineral sediment formation during operation in an oil well [1].
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Figure 2. Stratigraphy and faulting pattern of Bibi Hakimeh field (Iran), showing the oil-producing Bangestan and Asmari Formations, which are affected by compression, folding, and faulting, which defines an anticlinal trap [20].
Figure 2. Stratigraphy and faulting pattern of Bibi Hakimeh field (Iran), showing the oil-producing Bangestan and Asmari Formations, which are affected by compression, folding, and faulting, which defines an anticlinal trap [20].
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Figure 3. StimCADE2 software (Schlumberger) workflow, showing the inputs, processing steps, and outputs related to the prediction of chemical precipitates from formation waters.
Figure 3. StimCADE2 software (Schlumberger) workflow, showing the inputs, processing steps, and outputs related to the prediction of chemical precipitates from formation waters.
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Figure 4. Piper diagram for 5 water samples of Bibi Hakimeh oil and gas field formation.
Figure 4. Piper diagram for 5 water samples of Bibi Hakimeh oil and gas field formation.
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Figure 5. Chemical composition of formation rock in Bibi Hakimeh oil and gas field, showing the predominance of calcium (dark blue) and magnesium (light blue) carbonates. LOI = loss on ignition.
Figure 5. Chemical composition of formation rock in Bibi Hakimeh oil and gas field, showing the predominance of calcium (dark blue) and magnesium (light blue) carbonates. LOI = loss on ignition.
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Table 1. Analysis of water formation based on 5 samples of Bibi Hakimeh oil field wells.
Table 1. Analysis of water formation based on 5 samples of Bibi Hakimeh oil field wells.
Ions (mg/Lit)Sample1Sample 2Sample 3Sample 4Sample 5
Na+22,97931,67176,37978,31175,413
Ca2+16402720760064008400
Mg2+92316289721215972
Fe2+00000
Cl−90,525143,775133,125134,900133,125
SO42−13001200100010001000
HCO3−122122610244488
Total dissolved solids117,489181,116219,686222,070219,398
pH (at 25 °C)6.376.996.166.486.19
Table 2. Prediction of saturation percentage of sulfate and carbonate mineral precipitation at different pressures and temperatures.
Table 2. Prediction of saturation percentage of sulfate and carbonate mineral precipitation at different pressures and temperatures.
WellDeposition
(% Saturation *)		Survey Data
3000 Psia and 176 F3130 Psia and 180 F3200 Psia and 182 F3300 Psia and 186 F
Sample 1CaSO438.7340.1840.9242.44
CaSO4.2H2O11.2710.9410.7810.46
CaCO3100100100100
MgCO330.7233.1434.4137.07
Sample 2CaSO443.2244.9345.8147.6
CaSO4.2H2O10.8110.5210.3710.08
CaCO3100100100100
MgCO330.8333.2634.5337.19
Sample 3CaSO489.4692.8894.6398.2
CaSO4.2H2O20.1719.5919.3118.74
CaCO3100100100100
MgCO37.187.748.048.66
Sample 4CaSO475.2878.1679.6482.65
CaSO4.2H2O16.8316.3516.1115.64
CaCO3100100100100
MgCO310.5111.3411.7712.68
Sample 5CaSO4100100100100
CaSO4.2H2O22.5821.1320.4419.12
CaCO3100100100100
MgCO36.466.987.257.82
* % Saturation (% SR) = 100: scale formation.
Table 3. Mineral deposition formation rate for the studied samples (based on temperature and well pressure conditions) in Bibi Hakimeh oil field.
Table 3. Mineral deposition formation rate for the studied samples (based on temperature and well pressure conditions) in Bibi Hakimeh oil field.
WellDeposition
(mg/L)		Survey Data
3000 Psia and
176 F		3130 Psia and
180 F		3200 Psia and
182 F		3300 Psia and
186 F
Sample 1CaCO334.635.63636.98
Sample 2CaCO340.4941.4941.9842.97
Sample 3CaCO3370.6373.73375.28378.31
Sample 4CaCO3119.48121.20122.06123.74
Sample 5CaSO40.16749.9274.02120.73
CaCO3291.79294.3295.5297.99
Table 4. Ion ratio for estimation of preservation of hydrocarbon in the studied field.
Table 4. Ion ratio for estimation of preservation of hydrocarbon in the studied field.
RatiosFormation Water
Sample 1Sample 2Sample 3Sample 4Sample 5
Na+/Cl−0.2540.220.5740.580.566
(Ca + Mg)/SO41.973.628.577.619.37
(Cl− − Na+)/Mg2+73.1868.8658.3846.5759.37
HCO−/Cl−0.00130.000850.00460.00180.0036
(HCO− − CO3)/Ca2+0.070.040.080.040.06
Mg2+/Ca2+0.560.60.130.190.12
Ca/Cl0.0180.1890.05710.0470.064
Mg/Cl0.01020.01130.00730.0090.0073
SO4/Cl0.01430.00830.00750.00740.00751
SO4/HCO310.6559.8361.6394.0982.049
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Hashemi, S.H.; Torghabeh, A.K.; Niknam, A.; Hashemi, S.A.; Gharaie, M.H.M.; Pimentel, N. Geochemical and Thermodynamic Study of Formation Water for Reservoir Management in Bibi Hakimeh Oil and Gas Field, Iran. Fuels 2025, 6, 11. https://doi.org/10.3390/fuels6010011

AMA Style

Hashemi SH, Torghabeh AK, Niknam A, Hashemi SA, Gharaie MHM, Pimentel N. Geochemical and Thermodynamic Study of Formation Water for Reservoir Management in Bibi Hakimeh Oil and Gas Field, Iran. Fuels. 2025; 6(1):11. https://doi.org/10.3390/fuels6010011

Chicago/Turabian Style

Hashemi, Seyed Hossein, Amir Karimian Torghabeh, Abbas Niknam, Seyed Abdolrasoul Hashemi, Mohamad Hosein Mahmudy Gharaie, and Nuno Pimentel. 2025. "Geochemical and Thermodynamic Study of Formation Water for Reservoir Management in Bibi Hakimeh Oil and Gas Field, Iran" Fuels 6, no. 1: 11. https://doi.org/10.3390/fuels6010011

APA Style

Hashemi, S. H., Torghabeh, A. K., Niknam, A., Hashemi, S. A., Gharaie, M. H. M., & Pimentel, N. (2025). Geochemical and Thermodynamic Study of Formation Water for Reservoir Management in Bibi Hakimeh Oil and Gas Field, Iran. Fuels, 6(1), 11. https://doi.org/10.3390/fuels6010011

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