Introduction

Hydrocarbon reservoirs are considered the main source of energy supply and the essential factor in the world's economic development. Since most oil fields are in the second half of their life, it is necessary to apply secondary oil recovery techniques to maintain the reservoir pressure and increase the production rate. The most common secondary recovery method is water injection operation into oil reservoirs to compensate for the pressure drop due to oil production (Afekare et al. 2017; Hasankhani et al. 2018; Aminian et al. 2019; Khojastehmehr et al. 2019; Ghalib et al. 2023).

Extensive studies have shown that the success of water flooding operations depends on the interactions between injection water and formation fluid/rock. The chemical incompatibility between injected water and formation brine results in mineral scale formation, that is one of the serious problems in oil fields. In addition to the incompatible ionic composition of injection water, inorganic scales are formed due to brine supersaturation with changes in temperature, pressure, and pH value (Farrokhrouz et al. 2020; Nikoo et al. 2020; Veisi et al. 2020; Movahedi et al. 2021).

The significant issue in various operations performed in petroleum industry is increasing the oil recovery factor, however, reservoir damage is often neglected. Formation damage is a general expression used to describe reservoir permeability impairment, especially in near-wellbore regions. As an operational and economic challenge, formation damage may occur in different stages of oil and gas recovery, including drilling, production, workover, and enhanced oil/gas recovery operations. Therefore, simulation, prediction, and prevention of formation damage is an essential concern in the petroleum industry (Vasheghani et al. 2019; Hajipour 2020; Movahedi and Jamshidi 2021; Cheraghi et al. 2022).

To increase the oil production in water injection process, reservoir rock permeability impairment due to mineral scale formation should be avoided. Common inorganic scales observed in hydrocarbon reservoirs are sulfate, carbonate, oxides, and sulfide deposits (Luo et al. 2015; Mahat et al. 2016; Husna et al. 2022; Ismail et al. 2022). Since sulfate scales are hard, stable, almost insoluble in chemical solvents, and difficult to remove mechanically, these deposits lead to serious operational problems. Scales formed in the pores of reservoir rock restrict the oil flow, therefore the injection pressure and flow rate must be increased in water flooding operation to have a constant production rate. In fact, accurate prediction of the amount and type of scales is necessary to provide appropriate methods for the prevention of inorganic scale formation (Mahmoud et al. 2015; Adewole et al. 2019; Ko et al. 2020).

Various approaches, including experimental study and thermodynamic modeling can be applied to predict the amount and type of mineral scales and prevailing mechanisms of precipitation (Amjad et al. 2015; Qazvini et al. 2021). In experimental studies, brines compatibility tests are mainly conducted for the evaluation of scale amount. Park et al. explored the influence of barium ions in injection water on carbonate reservoir rock and indicated that rock surface dissolution and scale precipitation can simultaneously affect rock wettability and permeability. It was shown in their experiments that rock dissolution prevails the scale precipitation when the concentration of barium ions in the formation brine is low and the scale formation is increased by increasing barium cations concentration (Park et al. 2018). Anhydrite scale formation at high temperatures was investigated by Purswani et al. (2017). It was reported that the presence of rock grains in the brine solution accelerates the nucleation of calcium sulfate and the scale formation reaction. The presence of anhydrite in the rock sample leads to the reduction of anhydrite scale formation. Abbasi and Khamehchi (2020) revealed that rock dissolution can affect inorganic scale growth and deposition. In their experiments, both precipitation and dissolution were detected in the presence of carbonate rock samples. They showed that rock surface dissolution is the prevailing mechanism at lower salinities. Mixing of formation brine and injection water in the presence of carbonate rock indicated calcium and magnesium ion exchange on the calcite rock surface.

Dynamic experiments were performed by Azizi et al. (2019) on limestone cores by injecting water at different flow rates. In their experimental tests, the volume of oil produced and the pressure difference across the cores were measured with time. It was observed that the pressure drop increases constantly due to pores blockage by solid scale crystals. Tahmasebi et al. (2010) conducted dynamic tests in a packed column of glass beads and carbonate grains to explore the influence of temperature, ionic composition, and velocity of injection water on permeability variations. They reported that core permeability decreases due to the formation of calcium sulfate scale with increasing the temperature, and the injection rate. Recent studies indicate that the efficiency of water flooding operations is highly dependent on the salinity and composition of the injection water. In fact, oil/brine/rock interactions and the oil recovery can be optimized by modification of the injection water salinity and ionic composition (Sohal et al. 2016; Fattahi Mehraban et al. 2019; Mokhtari et al. 2019; Rostami et al. 2019).

Mixed salt precipitation which may occur during low salinity and smart water injection was experimentally examined by Abbasi et al. (2020). The water compatibility tests were performed to investigate the scaling potential in different injection/formation brine mixtures at 80 °C and ambient pressure. The results indicated that mixing formation brine and smart water with high concentrations of sulfate ions leads to the formation of sulfate scales. Therefore, the concentration of sulfate anions in smart water should be adjusted so that acceptable scale tendency, wettability alteration, and incremental oil recovery potential are obtained (Abbasi et al. 2020).

Various models based on thermodynamic relations and solubility changes are reported in the literature for the prediction of inorganic scale deposition. In most of these models, the potential of mineral scale formation is determined by the value of scale tendency and saturation index (Khormali et al. 2018). Scale tendency (i.e., ST) is defined as the ratio of the product of the ions' activity to the solubility product constant (Eq. 1). When the value of ST is greater than unity, inorganic scale formation occurs. The value of the solubility product constant (i.e., Ksp) is dependent on temperature and pressure.

$$ST=\frac{Ion\, Activity\, Product}{{K}_{sp}}$$
(1)

Saturation index is calculated using the following equation:

$$SI=log(ST)$$
(2)

When the value of SI is greater than zero, the solution is supersaturated and a solid scale is formed and when this value is less than zero, there is no scale in the solution. The solution is saturated if the calculated value of SI equals zero (Mahmoud et al. 2017).

In water flooding operations, injection water is often seawater with a high concentration of sulfate ions and formation brine has a high content of divalent cations, including calcium, strontium, and barium. Therefore, mixing injection water with formation brine results in sulfate precipitation. As the concentration of calcium and strontium cations in the formation brine is usually higher than barium cations, the deposition of calcium and strontium sulfate scales has been investigated in most previous studies. However, due to the high reactivity of barium cations with sulfate ions, even a small amount of these cations leads to barium sulfate deposit which is resistant to acid treatment and has the lowest solubility among mineral scales (Lakatos et al. 2002a, 2007; Al-Samhan et al. 2020).

Based on published research, most of the previous studies on formation damage due to inorganic scales have only focused on static compatibility tests and paid little attention to the presence of reservoir rock. In a few studies, dynamic core flooding experiments have been carried out, but no comparison has been made with the results of static compatibility tests (Manzari Tavakoli et al. 2018; Amiri et al. 2019; Ghasemian et al. 2019). The main objective of this study is to present the results of both static and dynamic compatibility tests, which indicates the importance of dominant mechanisms of scale precipitation. Comparing the results of static and dynamic experiments leads to determining the prevailing mechanisms of scale formation in the presence of reservoir rock and helps to select the appropriate remediation method.

To this end, synthetic brine samples were prepared according to the real ionic composition of formation brine and injection water. The impact of mixing ratio (i.e., the volume ratio of formation brine to injection water), temperature, pH value, and salinity on the amount of barium sulfate scale was explored and discussed. In the static experiments, the electrical conductivity and turbidity of the brines mixture at different conditions were measured. The dynamic tests were performed to simulate the fluid flow conditions in the reservoir. For this purpose, synthetic cores were prepared according to the type of reservoir rock in the investigated oil field, and the pressure drop across the core was recorded during the water injection. Finally, the variations of core permeability were calculated and compared. By comparing the results of static and dynamic compatibility tests, innovative outcomes were obtained and reported. In addition, the scale tendency was also inspected using the OLI ScaleChem software to determine the scale type and predict the volume ratio of seawater to formation brine which leads to minimum formation damage.

Materials and methods

Preparation of brines

Synthetic formation brine and injection water were prepared using high-purity salts, including \({\mathrm{BaCl}}_{2}.{2\mathrm{H}}_{2}\mathrm{O}\), \({{\mathrm{Na}}_{2}\mathrm{SO}}_{4}\), KCl, \({\mathrm{MgCl}}_{2}.{6\mathrm{H}}_{2}\mathrm{O}\), \({\mathrm{NaHCO}}_{3}\), and NaCl from Merck Chemicals. The ionic composition of the injection water and formation brine was based on the composition of real samples for the water flooding process in the investigated offshore oil field. Brine samples were made by dissolving specific amounts of salts in distilled water 24 h before performing the experiments. Then, samples were passed through filter paper to remove any solid particles from the prepared solutions and their stability was evaluated. Tables 1 and 2 show the concentration of ions and physical properties of brines, respectively.

Table 1 Ionic composition of injection water and formation brine
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Table 2 Physical properties of injection and formation waters at 25 °C
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Static experiments

Jar test was performed to investigate the brines compatibility and determine the amount of inorganic scale. First, formation and injection water samples were passed through filter paper and the turbidity, electrical conductivity, and pH values were measured. Since the turbidity of solutions depends on insoluble solid particles and the electrical conductivity depends on the concentration of free ions in the solution, the amount of scale can be quantified through changes in turbidity and electrical conductivity of solutions.

The turbidity of each sample was measured with Turb 355 IR turbidimeter and the electrical conductivity was recorded using EC-Meter GLP 31+ . Then, formation and injection waters were mixed in different volume ratios in nine glass tubes. The glass tubes were kept at constant temperature and pressure for 5 h and their content was stirred every 15 min to complete the precipitation reaction. After the complete mixing of brines, the electrical conductivity and turbidity of the solutions were measured. Finally, by passing each solution through 0.45 µm filter paper, the scale crystals were separated, dried, and prepared for XRF analysis. The experiments were repeated at least three times for each mixing ratio (i.e., the volume ratio of formation brine to injection water), and the results were reported as the mean values. The accuracy of the electrical conductivity and turbidity measurements was evaluated using distilled water and the relative error was found to be 0.5%. The mean error in static experiments was determined to be 3.8%. To investigate the influence of the temperature on barium sulfate scale formation, in addition to ambient temperature, static compatibility tests were repeated at the reservoir temperature of 85 °C.

One of the main parameters affecting the solubility of mineral scales is pH value (Lakatos et al. 2002b, c). Therefore, the impact of pH value in the range encountered in water injection operation was explored in this study. To this end, the injection water samples were prepared at different pH values by adding a specified amount of Sodium Hydroxide. At each pH value, jar tests were performed at different mixing ratios of formation brine to injection water, and variations in the electrical conductivity and turbidity of the solutions were measured.

Many studies have been conducted on smart water flooding to increase the recovery factor in oil reservoirs. The results of these studies indicate the high potential of this method to change the properties of reservoir rock to increase the oil production. The salinity of injection water is a key factor in designing low-salinity water injection operations. In previous studies, the impact of brine salinity on the surface characteristics of reservoir rock and the oil production rate has been studied, but its effect on the precipitation of mineral scales and formation damage has not received enough attention. Therefore, to evaluate the effect of injection water salinity on barium sulfate precipitation, 2, 3, and 5 times diluted seawater samples were prepared as shown in Table 3. In this Table, SW denotes seawater and SWXD indicates X times diluted seawater.

Table 3 Diluted injection water composition
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Dynamic experiments

In addition to static compatibility tests, dynamic experiments were conducted to simulate fluid flow conditions in the reservoir. The schematic of the experimental flooding system is shown in Fig. 1. Carbonate rock powder was used to prepare synthetic cores with properties similar to the reservoir rock. First, a sample of carbonate rock outcrop was broken into small pieces and then ground with a ball mill. The size of powdered grains was determined in the range of 125–210 microns using a laboratory sieve and shaker. X-ray fluorescence analysis was applied to evaluate the chemical composition and purity of rock powder.

Fig. 1
figure 1

Schematic of experimental flooding system

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To make synthetic cores, rock powder was placed and compressed into a core holder made of stainless steel. The inlet and outlet of the core holder were closed by fine meshes to prevent the movement of solid particles. Two valves were installed at the inlet and outlet of the core holder to control the fluid flow rate. The prepared cores were dried in a furnace at 100 °C for 24 h, vacuumed, and their weight was measured. After complete saturation of the cores with formation brine, their weight was measured again. For each core, the pore volume (Vp) was calculated from the difference between the weight of the saturated and dry cores. The porosity of the cores was computed using the following equation:

$$\mathrm{\varnothing }=\frac{{V}_{p}}{{V}_{b}}$$
(3)

where Vb is the total volume of the core. To determine the core permeability, formation brine was injected with a flow rate of 0.5 cc/min. The pressure difference across the core was recorded and the initial permeability was calculated using Darcy's law, i.e., Eq. 4 (Ahmed 2010; Mahmoud et al. 2017; Manzari Tavakoli et al. 2018; Khormali et al. 2023).

$$K=\frac{q \mu L}{A\Delta P}$$
(4)

After determining the initial porosity and permeability of cores, injection water and formation brine were injected into each core at different mixing ratios. All dynamic experiments were performed at the reservoir temperature of 85 °C. The flow pressure drop was measured against the injected pore volume and then core permeability variations were calculated. Figure 2 displays the process of this study in a flowchart.

Fig. 2
figure 2

Flowchart of the study

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Results and discussion

XRF spectroscopy analysis of the rock sample is presented in Table 4. As can be seen, the main component of the rock sample is calcium oxide which represents carbonate reservoir rock.

Table 4 Carbonate rock composition
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Static tests results

The effect of various parameters on barium sulfate scale, including mixing ratio, temperature, salinity, and pH value of injection water was investigated in static compatibility tests. In all experiments, the variations of electrical conductivity and turbidity of solutions were measured as indicators of solid scale formation.

Effect of mixing ratio

The most important parameter affecting inorganic scale precipitation is the volume ratio of formation brine to injected water. The scale formation tendency and the amount of scale change significantly by variations of brines mixing ratio. As shown in Fig. 3, the electrical conductivity increases with increasing the ratio of formation brine to injection water. In fact, increasing the formation brine, which has a much higher salinity and dissolved ions than seawater, increases the electrical conductivity of the waters mixture.

Fig. 3
figure 3

Electrical conductivity and turbidity of brines mixture at different mixing ratios

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Figure 3 shows that the turbidity of brines mixture increases by increasing the ratio of the formation brine to injection water due to further formation of the barium sulfate scale. In fact, the increase of brines mixture turbidity indicates the removal of ions from the solution and the formation of solid crystals of scale. By increasing the volume fraction of the formation brine, the amount of barium ions in the solution increases, and therefore the chemical reaction of barium sulfate formation (i.e., Eq. 5) proceeds toward the formation of the solid phase (Ferguson et al. 2011). The maximum turbidity which indicates the presence of insoluble solid particles and the highest amount of scale was observed for the solution containing 90% formation water.

$${\mathrm{Ba}}^{2+}(\mathrm{aq})+{\mathrm{SO}}_{4}^{2-}(\mathrm{aq})\leftrightarrows {\mathrm{BaSO}}_{4}(\mathrm{s})$$
(5)

XRF analysis of scale precipitation is presented in Table 5, which confirms that barium sulfate is the dominant type of scale. SEM image of the barium sulfate scale in Fig. 4 shows the size and morphology of scale crystals.

Table 5 XRF analysis of scale
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Fig. 4
figure 4

SEM image of scale crystals

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Effect of temperature

To inspect the influence of temperature on barium sulfate scale formation, static experiments were performed at reservoir temperature (i.e., 85 °C) and the results were compared with the data obtained at ambient temperature. Figure 5a shows the variations of electrical conductivity for brines mixture at ambient and reservoir temperatures. By increasing the temperature at a constant mixing ratio, the solubility of barium sulfate, and consequently the electrical conductivity of the brines mixture are increased. In fact, the reduction of temperature disrupts the chemical equilibrium between soluble ions and solid phase toward the formation of more scale.

Fig. 5
figure 5

Effect of temperature on a electrical conductivity and b turbidity of brines mixture

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Figure 5b displays the variations in turbidity of brines mixture at ambient and reservoir temperatures. It can be seen that the turbidity of solutions decreases with increasing temperature at a constant mixing ratio. Increasing the temperature increases the solubility of barium sulfate and results in the reduction of insoluble solid particles. Similar to the results obtained at ambient temperature, the highest turbidity and scale amount at reservoir temperature were detected in the mixture containing 90% formation water.

The increase of scale solubility with temperature can be justified by the exothermic nature of the barium sulfate precipitation reaction. According to Le Chatelier's principle, increasing the temperature causes the reaction to proceed in a direction that consumes further heat and decreases temperature. Therefore, increasing the temperature increases the solubility of barium sulfate and decreases the amount of solid scale. It was observed that the amount of scale in the mixture containing 90% formation brine is decreased by 17% at reservoir temperature.

Effect of pH value

Since most mineral scales are soluble in acidic or alkaline solvents, the pH value of injection water is an effective factor on inorganic scales. In water injection operations, different additives including corrosion inhibitors, scale inhibitors, antibacterial additives, and other chemicals are added to the injection water for various considerations. These additives may change the pH value of the injected water. Sometimes, the pH value of injection water should be increased to have a compatible mixture with different additives (Mahmoud et al. 2017). Therefore, in this study, the pH range that may encounter in water injection operations was investigated.

The variations of electrical conductivity and turbidity of brines mixture at different pH values are compared in Fig. 6. According to Fig. 6a, the variations of electrical conductivity of brines mixture versus mixing ratio coincide at different pH values. Also, Fig. 6b indicates a similar trend for the turbidity variations at different pH values. It was observed that pH value has no effect on barium sulfate precipitation. In other words, the results of static compatibility tests confirm that barium sulfate scale formation is independent of pH value. Similar results have been reported in the literature (Sorbie and Laing 2004; Tantayakom et al. 2005; Mahmoud et al. 2017).

Fig. 6
figure 6

Effect of pH value on a electrical conductivity and b turbidity of brines mixture

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Effect of injection water salinity

Figure 7a, b show the variations of electrical conductivity and turbidity of brines mixture at various dilutions of injection water, respectively. As the salinity of injected water decreases, the concentration of dissolved ions, and therefore the electrical conductivity of brines mixture reduces. Moreover, as can be seen in Fig. 7b, reducing the salinity of injected water reduces the turbidity of solutions so that minimum turbidity was observed for 5 times diluted seawater (i.e., SW5D).

Fig. 7
figure 7

Effect of salinity on a electrical conductivity and b turbidity of brines mixture

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Indeed, by diluting seawater, the concentration of sulfate ions decreases and less scale is formed in the mixture which results in the reduction of the solutions turbidity. It was detected that the turbidity of brines mixture is further reduced at higher proportions of the formation brine. It can be concluded that not only the low salinity water injection improves the oil recovery as reported in the literature but also reduces the risk of formation damage due to the barium sulfate scale.

Simulation results

The brines compatibility tests were simulated using OLI ScaleChem software to predict the amount of barium sulfate precipitation at different conditions. As stated before, the potential of scale formation in a solution can be determined by the value of scale tendency (ST) and saturation index (SI). The values of scale tendency and saturation index for barium sulfate precipitation at ambient and reservoir temperatures were calculated and presented in Fig. 8. As can be seen, the value of saturation index is greater than unity and the scaling tendency is more than zero at all mixing ratios, which confirms the formation of barium sulfate scale in the brines mixture.

Fig. 8
figure 8

Scale tendency and saturation index at a ambient temperature and b reservoir temperature

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Figure 8 indicates that by increasing the ratio of formation brine to injection water, the barium sulfate scale tendency increases to a maximum before decreasing. It can be explained that by increasing the mixing ratio, the concentration of barium ions in the brines mixture increases. The increase of barium cations concentration leads to the increase of ionic activity which consequently increases the scaling tendency. As the mixing ratio increases, the salinity of brines mixture also increases and leads to an increase in the solubility product of BaSO4. In fact, at higher salinities, the effect of salinity prevails ions concentration and reduces the scaling tendency. Since the maximum amount of scale is formed at 90% formation water, the scale formation tendency of brines mixture reaches the minimum value. Comparing Fig. 8a, b show that barium sulfate scale tendency and saturation index are reduced by increasing the temperature. Therefore, it can be concluded that the potential of barium sulfate scale precipitation is much higher at wellhead conditions than in reservoir formation.

The predicted amount of barium sulfate scale as a function of the mixing ratio at reservoir temperature was compared with experimental data in Fig. 9. It can be seen that barium sulfate deposition is formed at all mixing ratios and the predicted amount of scale increases linearly by increasing the ratio of formation brine to injection water. The maximum amount of barium sulfate scale was calculated as 74.6 mg/l at the highest ratio of formation brine to injection water (i.e., 90% formation brine). Similar results have been reported in the experimental studies of Azizi et al. (2019). The amount of scale at different mixing ratios is illustrated in Fig. 10.

Fig. 9
figure 9

Comparison of predicted and experimental amounts of BaSO4 scale

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Fig. 10
figure 10

The amount of barium sulfate scale at 30%, 60% and 90% FW from left to right

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Although similar trends are observed for variations of barium sulfate scale, the calculated amounts of deposition using OLI ScaleChem software do not coincide with experimental values. The discrepancy between the calculated values and measured data of the barium sulfate scale can be related to the assumptions applied to calculate the solubility product of BaSO4. The solubility product is affected by various factors, including salinity and ionic composition of the solution, but in the commercial software, these effects are not taken into account. The increase in the difference between simulation results and experimental data by increasing the mixing ratio can well confirm the impact of solution salinity on the amount of barium sulfate scale.

Dynamic tests results

Dynamic experiments were designed and conducted according to the results obtained from static experiments. In these tests, the pressure drop due to water injection into synthetic cores was recorded and permeability changes were calculated. For this purpose, formation brine and seawater were injected simultaneously into the core with a constant flow rate of 0.5 cc/min at a ratio of 90% to 10%. The mixing ratio was selected based on the results of static experiments at which a maximum amount of scale was observed.

The variations of pressure drop and permeability ratio versus injected pore volume are displayed in Fig. 11. By increasing the injected pore volume, the core permeability was reduced about 54% due to the formation of barium sulfate scale. The permeability reduction is severe during the injection of the first pore volume, and the permeability of the core becomes almost constant after injecting about 1.3 pore volume. This observation can be justified by the fact that in early times of water injection, barium sulfate scale nucleation occurs rapidly which results in a severe decrease in the core permeability. After that crystal growth happens slower than scale nucleation. By injection of more than two pore volumes, the permeability reduction proceeds with a lower slope. In fact, deposition of scale crystals on the pore surface and blockage of the pore throats by solid particles lead to more reduction in permeability (Shemer et al. 2013; Dobra et al. 2017). The pressure variations show the opposite trend compared to the permeability changes, namely the pressure difference across the core increases by increasing the injected pore volume.

Fig. 11
figure 11

Permeability variations and differential pressure with injected pore volume

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To explore the impact of injection water pH value on the amount of scale and permeability reduction, dynamic tests were performed at different alkalinity levels. Figure 12 reveals that at a constant injected pore volume, the core permeability decreases with increasing the pH value of injection water. In static compatibility tests, it was observed that the amount of barium sulfate scale is not dependent on pH value. However, in the presence of rock samples in dynamic tests, the reverse effect of pH value on rock permeability was detected. This may be due to variations in carbonate rock surface charge with pH value. As the pH value increases, the carbonate rock surface charge becomes more negative and repels sulfate ions into the aqueous phase which results in more scale formation. Another justification for permeability reduction in the presence of carbonate rock is the dissolution of the rock surface which leads to an increase in the concentration of calcium ions in the brines mixture and calcium sulfate scale formation. Indeed, two mechanisms, namely rock surface dissolution and scale formation are involved due to rock/brine interactions in dynamic tests (Naseri et al. 2015). The dissolution of carbonate rock surface occurs at pH levels higher than neutral value according to Eq. (6). However, by increasing the pH value, scale formation is predominant and causes permeability reduction.

Fig. 12
figure 12

Core permeability versus injected pore volume at different pH values

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$${\mathrm{CaCO}}_{3}+{\mathrm{H}}_{2}\mathrm{O}\leftrightarrow {\mathrm{Ca}}^{2+}+{\mathrm{HCO}}_{3}^{-}+{\mathrm{OH}}^{-}$$
(6)

In static compatibility tests, the impact of brine/rock interactions on the scale formation are eliminated, and therefore the variations of pH value do not affect the amount of scale. On the contrary, pH value has a significant influence on the barium sulfate scale in dynamic tests due to the presence of rock and surface phenomena involved as the result of contact between brine and rock surface.

The variations of core permeability at different salinities of the injection water are displayed in Fig. 13. As shown, the injection of 5 times diluted seawater reduces the amount of scale at reservoir temperature by 10% and leads to the minimum permeability impairment. It can be stated that by decreasing the salinity of injection water, the tendency of ions for getting out of the aqueous phase and scale formation decreases. Moreover, partial dissolution of rock surface occurs at lower salinities which has a direct effect on rock permeability (Ghasemian et al. 2019).

Fig. 13
figure 13

Core permeability versus injected pore volume at different salinities

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In offshore oil fields, seawater is an accessible fluid for reservoir injection. However, various issues may arise if required investigations are not carried out. In most industrial projects, only static water compatibility tests are performed and core flooding tests are ignored due to time and cost savings. The output of this study indicates the importance of conducting dynamic compatibility tests in the presence of reservoir rock along with the static tests. The main advantage of this research is helping to increase the efficiency of water injection operations through the more appropriate determination of water properties. To enhance the oil production and simultaneously prevent the formation damage in water flooding process, conducting both static and dynamic experiments for the investigation of brines compatibility is essential. Comparing the results of static and dynamic compatibility tests leads to determining the dominant mechanisms of scale formation in the presence of reservoir rock and helps to select the suitable remediation technique. The potential limitations of this study are given in the following. The results indicated that the injection of 5 times diluted seawater leads to the minimal formation damage. Yet, reducing the water salinity requires potentially costly treatment before the injection. The results are applicable for oilfields in the vicinity of seawater where facilities for water transportation from the source to the oilfield are feasible. The presence of oil droplets can affect the scale formation conditions, which should be studied in future studies.

Conclusions

Scale formation is the primary problem in water injection operations. The formation of scales is affected by many factors, such as pressure, temperature, ions concentration, brines mixing ratio, salinity, and pH value. In the current study, static and dynamic experiments were conducted to explore brines compatibility and the potential of barium sulfate scale formation in water injection operation. Moreover, scale formation was simulated using OLI ScaleChem software and the predicted results were compared with experimental data. The main findings are as follows.

  • The results showed that the maximum barium sulfate scale forms in a mixture containing the highest ratio of formation brine to injection water.

  • Since the solubility of barium sulfate increases at elevated temperature, the potential of scale precipitation is lower at reservoir temperature.

  • To minimize formation damage due to inorganic scales, performing both static and dynamic compatibility experiments is essential.

  • Comparing the results of static and dynamic tests leads to determining the dominant mechanisms of scale formation and helps to select the appropriate remediation method.

  • The dynamic tests indicated that the barium sulfate scale increases at higher pH values due to carbonate rock/brine interactions while no effect was observed in static experiments.

  • The results showed that the appropriate condition for injection water is 5 times diluted seawater for which minimum permeability reduction, i.e., 54% was detected.

  • The permeability reduction was severe during the injection of the first pore volume due to the rapid nucleation of the barium sulfate scale. After that, the permeability reduction proceeds with a lower slope because crystal growth and deposition occur slower than scale nucleation.