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Enhanced Wettability Modification and C[O.sub.2] Solubility Effect by Carbonated Low Salinity Water Injection in Carbonate Reservoirs.

1. Introduction

For decades, waterflooding has been deployed to pressurize depleted reservoirs for oil recovery when primary recovery becomes inefficient. After waterflooding, general recovery of oil is limited to approximately 30% because of factors such as heterogeneity, wettability, and unfavorable mobility. Therefore, economic and practical enhanced oil recovery (EOR) technologies have been developed to recover the oil remaining after waterflooding.

One such technique is carbonated water injection (CWI), which is C[O.sub.2]-enriched waterflooding. When carbonated water (CW) comes into contact with oil, the C[O.sub.2] dissolved in CW moves into the oil, resulting in oil viscosity reduction and swelling [1]. These effects depend on the C[O.sub.2] solubility of brine. The effects of CWI have been investigated for decades. In the 1960s, commercial applications of CWI in Oklahoma, Texas, and Kansas demonstrated that CWI resulted in increased water injectivity and oil recovery [2]. In more recent studies, the CWI phenomenon has been visualized in glass micromodels [1, 3, 4]. These studies confirmed oil swelling, oil viscosity reduction, and the generation of C[O.sub.2]-enriched gas during CWI. Moreover, Sohrabi et al. [1] and Kechut et al. [4] have conducted coreflooding experiments to observe whether oil production is enhanced and performed numerical simulations.

Another attractive EOR process is low salinity water injection (LSWI). Because conventional waterflood injects seawater or produced formation brine and LSWI uses diluted seawater, low saline brine indicates diluted seawater hereafter. Various laboratory studies have demonstrated enhanced oil recovery by LSWI through spontaneous imbibition and coreflooding tests for carbonate reservoir rocks [5-7]. This enhanced oil production was attributed to wettability modification of the rock surface. Many experimental techniques (interfacial tension measurement, contact angle measurement, NMR, [zeta]-potential measurement, imbibition testing, and coreflooding testing) have suggested mechanisms responsible for wettability modifications, such as calcite dissolution [7, 8], anhydrite dissolution [9], and surface charge change [10-12]. Although the underlying mechanism is still unclear, Yousef et al. [13] confirmed the reduction of residual oil saturation through the single well tracer test in field trials.

Both CWI and LSWI are advanced waterflooding processes that modify the ionic composition of brine through C[O.sub.2] dissolution or dilution. Since both methods are waterflooding-based EOR processes, it is relatively straightforward to combine CWI with LSWI. Recently, Kilybay et al. [14] have performed such a study in which they evaluated carbonated smart water flooding. They selected smart water as the sulfate ion-enriched brine through surface charge evaluation, rather than diluted seawater. However, only one of the three coreflooding experiments showed enhanced oil production, while the last two experiments showed negligible oil production [14]. Moreover, this approach did not account for any synergetic effects between smart water and carbonated brine.

While various studies have focused on single low salinity water injection or carbonated water injection in carbonate, hybrid EOR has not yet been investigated as a carbonated low salinity water injection (CLSWI) technique. Moreover, hybrid EOR potentially has additional synergetic effects because of the relationship between C[O.sub.2] solubility in brine and the low salinity of brine. This promising hybrid CLSWI technique is expected to yield oil viscosity reduction, oil swelling, and wettability modification effects, with the additional advantage of storing C[O.sub.2] through the solubility mechanism. While the hybrid technique is expected to enhance oil recovery and C[O.sub.2] storage, complex geochemical phenomena in the brine-rock-oil system underlie the CLSWI mechanism.

The objective of this study was to evaluate oil production in CLSWI considering the geochemistry of the brine-rock-oil system. The performance of CLSWI in oil viscosity reduction, oil swelling, and wettability modification was investigated and compared to those of seawater injection (SWI), carbonated seawater injection (CWI or CSWI), and LSWI. Additionally, C[O.sub.2] storage by the solubility trapping mechanism was investigated.

2. Basic Theories

In CLSWI, C[O.sub.2] moves into the oleic/gas phases to reach equilibrium at a specific temperature and pressure. This mass transfer across the interphase proceeds until the fugacity of C[O.sub.2] becomes equivalent in all existing phases. Li and Nghiem [15] have calculated the composition in each phase through the equation of state (EoS), considering Henry's law. The C[O.sub.2] solubility in the aqueous phase is determined from Henry's law and the C[O.sub.2] fugacity in the gas phase. The C[O.sub.2] fugacity in the gas phase is calculated from the EoS. Henry's law takes into account salinity by introducing a salting-out coefficient. This coefficient depends on temperature and salinity [16].

[mathematical expression not reproducible], (1)

where [mathematical expression not reproducible] indicates the C[O.sub.2] fugacity in phase j, j represents the gas and aqueous phases, [mathematical expression not reproducible] is Henry's constant of C[O.sub.2] in brine, [mathematical expression not reproducible] is the molar fraction of C[O.sub.2] in the aqueous phase, [mathematical expression not reproducible] is Henry's constant of C[O.sub.2] at zero salinity, [mathematical expression not reproducible] is the salting-out coefficient of C[O.sub.2], and [m.sub.salt] is the molality of the dissolved salt.

CLSWI interrupts geochemical equilibrium in the formation of brine/rock system and establishes a new equilibrium state. In compositional simulations, Nghiem et al. [17] have introduced geochemical reactions and captured aqueous phase behavior. The first reaction associated with CLSWI is an aqueous reaction. The ionic concentration in the reaction is calculated when the ion activity product (IAP) is equivalent to the equilibrium constant at a specific temperature.

[mathematical expression not reproducible], (2)

where [alpha] indicates the aqueous reaction, [K.sub.eq,[alpha]] is the temperature-dependent equilibrium constant, [Q.sub.[alpha]] is the IAP, k stands for the component, [] indicates the number of aqueous reactions, [a.sub.k] is the ionic activity, and [v.sub.k,[alpha]] are the stoichiometric coefficients of an aqueous reaction.

Geochemical reactions are determined by the effective ionic concentration, which is equivalent to ion activity, considering electrostatic interactions among ions in the aqueous phase. Ion activity is a function of activity coefficient and molality. The activity coefficient is determined by ionic strength, ion size, and temperature. Here, a modified Debye-Huckel model was used to calculate the ion activity coefficient at a specific temperature, as shown below:

[mathematical expression not reproducible], (3)

where [[gamma].sup.k] indicates the activity coefficient; [m.sub.k] is the molality; [A.sub.[gamma]], [B.sub.[gamma]], and [??] are temperature-dependent coefficients; I indicates the ionic strength; [[??].sub.k] is the ion size parameter; and [z.sub.k] represents the ionic charge.

Another geochemical reaction is mineral dissolution, otherwise known as precipitation. This reaction is characterized by nonequilibrium and slow kinetics, in contrast to aqueous reactions. Mineral dissolution is a rate-dependent kinetic reaction, represented by the rate law, by which ion species are generated or consumed in brine. In mineral dissolution/precipitation, the generation/consumption rates of minerals are determined by the reaction rates, mineral reactive surface areas, and stoichiometric coefficients, as shown below:

[mathematical expression not reproducible], (4)

where [beta] defines the mineral, [r.sub.[beta]] is the reaction rate, [k.sub.[beta]] is the reaction rate constant, [[??].sub.[beta]] is the reactive surface area of a mineral, [K.sub.eq,[beta]] is the solubility product constant at a specific temperature, [Q.sub.[beta]] is the IAP, and [v.sub.k,[beta]] are the stoichiometric coefficients of a given mineral reaction.

Since mineral dissolution or precipitation provides or consumes ionic species in the aqueous phase, the rate of generation/consumption of a given ionic species is closely related to the mineral reaction, as shown in the following equation:

[[gamma].sub.k,[beta]] = [v.sub.k,[beta]][r.sub.[beta]], (5)

where [[gamma].sub.k,[beta]] indicates the consumption or production rate of a given ionic species in brine due to the mineral reaction.

3. Numerical Modeling

Numerical modeling of hybrid CLSWI has been conducted with GEM simulator, which was developed by CMG (Computer Modeling Group Ltd.). This simulation study was based on a coreflooding experiment by Gachuz-Muro and Sohrabi [18]. Specifically, the numerical 1-dimensional model describes the limestone core, which was discretized into 20 grid blocks. The total pore volume and oil volume were 15.55 and 10.55 [cm.sup.3], respectively, and the permeability and temperature were set to 19.4 md and 92[degrees]C, respectively. The target oil had an API gravity and viscosity of 14.12[degrees]API and 53,484.31 cp, respectively, at 20[degrees]C; the oil viscosity was approximately 111.4 cp at the reservoir conditions. The compositions of the formation brine, injected SW, and injected LSW are shown in Table 1. In SW, the low concentration of [Ba.sup.2+] was neglected to improve numerical convergence. Geochemical reactions, including aqueous reactions and mineral reactions, were implemented into the flow simulation and are listed in Table 2.

First, the wettability modification effect was extracted from the LSWI experiment. Using the oil production data, history-matching was used with CMOST simulator to evaluate the modification of relative permeability curves and residual oil saturation. Next, CLSWI modeling was performed. The performance of CLSWI was assessed by comparing its results with those of continuous SWI, LSWI, and CSWI. To construct different saline CWI techniques (CSW and CLSW), geochemical analysis was used to estimate C[O.sub.2] solubility at specific temperature and pressure. The oil production from CLSWI was assessed in terms of wettability modification, oil swelling, and oil viscosity. Moreover, since CLSWI has the potential to capture C[O.sub.2] in the reservoir, the storage potential was evaluated by considering the solubility trapping mechanism.

4. Results

4.1. History-Matching Process: SWI and LSWI. History-matching was performed through CMOST to assess experimental oil production [18]. The injection scenario was designed with successive SWI following LSWI. The best history-matched model, shown in the red line, was used in the experiment (Figure 1). Regular seawater injection for the first cycle recovered up to 37% of the oil. Successive LSWI after SWI retrieved an additional 15% of the oil due to the wettability modification effect. This wettability modification effect is characterized by relative permeability change and residual oil saturation reduction, as shown in Figure 2. Residual oil saturation was modified with 4% reduction, after which the water endpoint was reduced by up to 20%, and the oil endpoint was increased by up to 4%. After LSWI, 48% of the OOIP (Original Oil in Place) remained in the reservoir due to unfavorable oil mobility. Based on this model, numerical modeling of CSWI and CLSWI was conducted, and the performances of both processes were compared.

4.2. Carbonated Water Injection: CSW and CLSWI. Geochemical analysis with PHREEQC (PH-Redox-EQuilibrium C programming language) simulator was used to evaluate C[O.sub.2] solubility in different brines. When the pressure increases, more C[O.sub.2] can be dissolved in the brine. Figure 3 illustrates the C[O.sub.2] solubility at the reservoir temperature and reveals salinity-dependent and pressure-dependent solubility. Both brines had higher solubility as the pressure increased. Of note, solubility was higher in LSW than in SW. SW and LSW have ionic strength as 0.4765 and 0.04934 mol/kg. At regular atmospheric conditions, as many as 9.74 x [10.sup.-3] and 1.07 x [10.sup.-2] moles of C[O.sub.2] could be dissolved into the SW and LSW, respectively. In high-pressure conditions (up to 10 atm), the dissolution increased up to 0.08913 and 0.1037 moles, respectively. The increased C[O.sub.2] solubility in low saline brine is a manifestation of the salting-out phenomenon, which predicts that low saline water is the optimum condition for constructing CWI.

To compare the performance of CLSWI to that of other techniques, continuous SWI, LSWI, and CSWI were also modeled. Figure 4 displays the oil recovery history for SWI, LSWI, CSWI, and CLSWI. SWI recovered about 40% of the oil after 30 PV (pore volume), while LSWI recovered up to an additional 11% due to the wettability modification effect. Mineral dissolution of [Ca.sup.2+], [Mg.sup.2+], and S[O.sub.4.sup.2-] were the major factors responsible for this wettability modification. Figure 5 depicts the ionic concentrations in the reservoir and the mineral dissolution. The ionic concentrations of [Ca.sup.2+], [Mg.sup.2+], and S[O.sub.4.sup.2-] after LSWI were less than 10% of the concentrations after SWI. Both SWI and LSWI dissolved calcite minerals, with LSWI dissolving 16% more calcite minerals than SWI.

In CSWI, 5% more oil was recovered compared to SWI (Figure 4). Interestingly, CSWI and SWI led to different [Ca.sup.2+], [Mg.sup.2+], and S[O.sub.4.sup.2-] concentrations in the reservoir. Specifically, CSWI resulted in slightly increased (2 to 3%) concentrations. The main reason for this difference is the 11% increase in mineral dissolution. These increases in the ionic concentrations of [Ca.sup.2+], [Mg.sup.2+], and S[O.sub.4.sup.2-] mean that wettability could potentially be modified, albeit by a relatively small increment. However, the oil swelling and viscosity reduction changes were significant. Figure 6 presents the C[O.sub.2] dissolution in oil, oil density, and oil viscosity at the center of the core. In CSWI, the C[O.sub.2] dissolved in brine was transferred into the oil to reach an equilibrium state. This dissolution involved oil swelling and reduced oil density by as much as 2.8%, while also reducing oil viscosity by as much as 75%.

CLSWI recovered 56.5% of the oil. This yield was higher than that achieved with SWI, LSWI, or CSWI (up to 16%, 5%, and 9%, resp.) (Figure 4). First, the performance of CLSWI was evaluated in terms of oil swelling, density, and viscosity. This evaluation was performed by comparing CSWI with CLSWI. As illustrated in Figure 6, CLSWI involves mass transfer of C[O.sub.2] from brine into oil. This transport increases the C[O.sub.2] molar fraction in oil up to 0.148, which is as much as 8% higher than that in CSWI. Low salinity brine has C[O.sub.2] solubility by up to 15% higher compared to seawater due to the salting-out phenomenon (Figure 3). In these reservoir conditions, more dissolved C[O.sub.2] came out of the brine in CLSWI than in CSWI; this C[O.sub.2] dissolved into the oil. This enhanced dissolution resulted in greater reductions of oil density and viscosity, as shown in Figure 6. Next, the potential of CLSWI to modify wettability was evaluated and compared to that of LSWI. The slight changes in [Ca.sup.2+], [Mg.sup.2+], and S[O.sub.4.sup.2-] concentrations resulted from aqueous and mineral reactions. In addition, CLSWI yielded as much as 4% greater mineral dissolution, thereby providing more [Ca.sup.2+], [Mg.sup.2+], and S[O.sub.4.sup.2-] ions in the brine (Figure 5). This finding implies that CLSWI has the potential to improve wettability in terms of geochemical evaluation. In summary, CLSWI has advantages compared to both CWI and LSWI and also improves oil recovery.

Conventional CSWI has the ability to store C[O.sub.2] by the dissolution mechanism. The promising hybrid CLSWI technique also captures stable C[O.sub.2] in the reservoir. After CLSWI, the in situ brine exists in a low saline condition, which is favorable for C[O.sub.2] solubilization due to the salting-out phenomenon. CLSWI demonstrated an enhanced capability for C[O.sub.2] storage compared to conventional CWI.

Specifically, the total amounts of C[O.sub.2] injected by CSWI and CLSWI were 6.25123 x [10.sup.-2] and 7.23759 x [10.sup.-2] moles, respectively. As shown in Figure 7(a), CSWI stably stored as many as 1.25 x [10.sup.-2] moles C[O.sub.2] in brine. Moreover, CLSWI captured up to 24% more C[O.sub.2] than CSWI. While up to 17% more C[O.sub.2] was injected in CLSWI, mass transfer of C[O.sub.2] into oil and brine was greater in CLSWI than in CSWI. Finally, CLSWI yielded as much as 13% lower supercritical C[O.sub.2], which corresponds to C[O.sub.2] not stored by the solubility mechanism, in the reservoir compared to CSWI (Figure 7(b)).

4.3. Pilot-Scaled Reservoir. The performance of CLSWI was also assessed in a 2-dimensional heterogeneous permeable reservoir (Figure 8), which had a pore volume of 1.8576 x [10.sup.2] [m.sup.3]. The average horizontal permeability of this reservoir was approximately 19.4 md, and the Dykstra-Parsons coefficient of the permeability was calculated to be 0.35. Figure 9(a) shows the oil recovery after injection of 10 PV, with SWI yielding 27.8% oil recovery. CSWI improved oil recovery by 7% compared to SWI due to the oil swelling effect and viscosity reduction. The viscosity reduction also contributed to the improved injectivity compared to SWI. The relative injectivity of CSWI, which is defined as the injectivity of CSWI divided by the injectivity of SWI, is shown in Figure 9(b). The injectivity of CSWI was improved by as much as 20% compared to SWI due to oil viscosity reduction. Hybrid CLSWI enhanced oil recovery by up to 22% compared to SWI; the hybrid approach showed as much as 15% more recovery than CSWI. This significant increase in oil recovery is mainly attributed to the wettability modification effect and oil viscosity reduction. In terms of injectivity, the wettability modification effect introduced a slight increase in injector BHP. However, the oil viscosity reduction by C[O.sub.2] dissolution into the oil significantly improved injectivity. At injection of 1PV, CLSWI exhibited up to 170% greater injectivity than SWI. After injection of 10 PV, 55% improvement was observed, still as much as 31% higher than that of CSWI. Moreover, 45% more C[O.sub.2] was stored in CLSWI than in CSWI due to the solubility mechanism (Figure 9(c)).

5. Conclusions

This study assessed the performance of hybrid CLSWI in terms of oil production and C[O.sub.2] storage. The process behind hybrid CLSWI depends on geochemical reactions in the brine/oil/rock system. This study, which incorporated geochemical reaction modeling, demonstrated the promising potential of CLSWI. Compared to LSWI, CLSWI resulted in negligible changes of ionic concentrations ([Ca.sup.2+], [Mg.sup.2+], and S[O.sub.4.sup.2-]) and 4% greater mineral dissolution. These geochemical reaction results explain why CLSWI has the potential to introduce the wettability modification effect, similar to LSWI. Additionally, CLSWI yielded enhanced oil swelling and oil viscosity reduction compared to CSWI. Because of the salting-out phenomenon, CLSWI carried up to 15% more dissolved C[O.sub.2] into the reservoir and transferred more C[O.sub.2] from brine into oil, thereby reducing oil viscosity. These results clearly demonstrate that CLSWI yielded up to 31% improved injectivity compared to CSWI in the pilot-scale reservoir. The synergetic effects of wettability modification, oil swelling, and oil viscosity reduction in hybrid CLSWI contributed to enhanced oil recovery (up to 9% and 15% more in core-scaled and pilot-scaled systems, resp.). Along with the enhanced oil recovery, CLSWI yielded enhanced C[O.sub.2] storage by the solubility mechanism. Specifically, CLSWI captured more C[O.sub.2] than CSWI (by up to 17% and 45% more in core-scaled and pilot-scaled systems, resp.) because of the salting-out phenomenon. In summary, hybrid CLSWI is a promising EOR method for improving oil recovery, injectivity, and C[O.sub.2] storage. In addition to enhanced oil production, additional direct economic benefit via CLSWI is smaller amount of C[O.sub.2] to be required than C[O.sub.2] EOR. Future value of C[O.sub.2] emission reduction considering carbon tax is also expected via hybrid EOR technology. 10.1155/2017/8142032

Conflicts of Interest

The authors declare that they have no conflicts of interest.


This work was supported by a grant funded as a part of the project "Development of IOR/EOR Technologies and Field Verification for Carbonate Reservoir in UAE" by the Korean Government Ministry of Trade, Industry and Energy (MOTIE) (no. 20152510101980). This paper is a revised and expanded version of a paper entitled "Geochemical Modelling of Carbonated Low Salinity Water Injection (CLSWI) to Improve Wettability Modification and Oil Swelling in Carbonate Reservoir," presented at SPE Latin America and Caribbean Mature Fields Symposium, Salvador, Bahia, Brazil, March 15-16, 2017.


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Ji Ho Lee and Kun Sang Lee

Department of Earth Resources and Environmental Engineering, Hanyang University, Seoul 04763, Republic of Korea

Correspondence should be addressed to Kun Sang Lee;

Received 27 February 2017; Revised 30 April 2017; Accepted 5 June 2017; Published 17 July 2017

Academic Editor: Davide Vione

Caption: FIGURE 1: History-matched oil production in successive seawater injection and low salinity water injection.

Caption: FIGURE 2: Modification of relative permeability and residual oil saturation in successive seawater injection and low salinity water injection.

Caption: FIGURE 3: Pressure-dependent C[O.sub.2] solubility in brine.

Caption: FIGURE 4: Cumulative oil recovery after seawater injection, low salinity water injection, carbonated seawater injection, and carbonated low salinity water injection.

Caption: FIGURE 5: History of ionic concentrations ([Ca.sup.2+], [Mg.sup.2+], and S[O.sub.4.sup.2-]) and mineral dissolution in the reservoir after seawater injection, low salinity water injection, carbonated seawater injection, and carbonated low salinity water injection.

Caption: FIGURE 6: History of oil density and viscosity reduction for carbonated seawater injection and carbonated low salinity water injection.

Caption: FIGURE 7: History of dissolved C[O.sub.2] concentration in brine and supercritical C[O.sub.2] after carbonated seawater injection and carbonated low salinity water injection.

Caption: FIGURE 8: Heterogeneous permeability (md) of the reservoir.

Caption: FIGURE 9: History of oil recovery, relative injectivity, and C[O.sub.2] storage after seawater injection, carbonated seawater injection, and carbonated low salinity water injection.
TABLE 1: Brine compositions [18].

Ion                 FW (mg/L)   SW (mg/L)   LSW (mg/L)

[Na.sup.+]          9,614.97    11,429.38    1,142.93
[Ca.sup.2+]          320.36      429.60       42.96
[Mg.sup.2+]          218.94     1,361.60      136.16
[K.sup.+]                        351.10       35.11
[Ba.sup.2+]                       0.01
[Sr.sup.2+]                       8.37         0.83
[Cl.sup.-]          15,117.25   20,040.00    2,004.00
S[O.sub.4.sup.2-]    550.63     3,500.00      350.00
HC[O.sub.3.sup.-]   1,135.90      47.58        4.75
pH                    8.01        7.80         7.20

TABLE 2: Geochemical reactions.

Aqueous reactions                      [mathematical expression
                                           not reproducible]

Mineral dissolution/precipitation      [mathematical expression
                                           not reproducible]
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Title Annotation:Research Article
Author:Lee, Ji Ho; Lee, Kun Sang
Publication:Journal of Chemistry
Article Type:Report
Date:Jan 1, 2017
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