Low-salinity water-alternating-CO2 EOR

Author’s Accepted Manuscript Low-salinity water-alternating-CO2 EOR Tadesse Weldu Teklu, Waleed Alameri, Ramona M. Graves, Hossein Kazemi, Ali M. AlSumaiti

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S0920-4105(16)30031-6 http://dx.doi.org/10.1016/j.petrol.2016.01.031 PETROL3332

To appear in: Journal of Petroleum Science and Engineering Received date: 29 July 2015 Revised date: 21 January 2016 Accepted date: 22 January 2016 Cite this article as: Tadesse Weldu Teklu, Waleed Alameri, Ramona M. Graves, Hossein Kazemi and Ali M. AlSumaiti, Low-salinity water-alternating-CO E O R , Journal of Petroleum Science and Engineering, http://dx.doi.org/10.1016/j.petrol.2016.01.031 This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting galley proof before it is published in its final citable form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.

Low-salinity water-alternating-CO2 EOR Tadesse Weldu Teklu*,†, Waleed Alameri†,‡, Ramona M. Graves†, Hossein Kazemi†, Ali M. AlSumaiti‡ Abstract Carbon dioxide flooding is currently the most technically and economically viable enhanced oil recovery (EOR) process in carbonate and sandstone reservoirs. Low-salinity waterflood is a relatively new EOR process; and our experiments in carbonate cores show significant oil recovery improvements with low-salinity waterflood. We propose a new EOR process to improve recovery, which involves low-salinity water-alternating-CO2/gas (LS-WACO2 or LS-WAG) injection. To evaluate the proposed idea, three core floods and several contact angle and IFT measurements were performed. The core floods include: seawater flood, followed by low-salinity waterflood, followed by CO2 injection, which yielded fourteen, twenty-five, and thirty-eight percent additional oil recovery by CO2 from two carbonate and one sandstone experiments. We performed contact angle measurements on several low-permeability carbonate, medium-permeability Berea sandstone, and ultra-low permeability Three Forks mudstone core discs using different salinities brine with and without CO2 gas. The contact angle measurements confirmed that favorable wettability alteration is achievable with the proposed EOR process. In addition, visual observations suggested that the proposed EOR process could be effective for cleaning the matrix-fracture interface in conventional and unconventional reservoirs. Interfacial tension (IFT) measurements and correlation relevant to the EOR process is also included in this study.

Keywords Low-Salinity Water EOR; CO2 EOR; LS-WAG; LS-WACO2; Wettability Alteration; Interfacial Tension (IFT)

Summary Carbon dioxide flooding is currently the most technically and economically viable enhanced oil recovery (EOR) process in carbonate and sandstone reservoirs. Low-salinity waterflood is a relatively new EOR process; and our experiments in carbonate cores show significant oil recovery improvements with low-salinity waterflood. We propose a new EOR process to improve recovery, which involves low-salinity water-alternating-CO2/gas (LS-WACO2 or LS-WAG) injection. To evaluate the proposed idea, three core floods and several contact angle and IFT measurements were performed. The core floods include: seawater flood, followed by low-salinity waterflood, followed by CO2 injection, which yielded fourteen, twenty-five, and thirty-eight percent additional oil recovery by CO2 from two carbonate and one sandstone experiments. We performed contact angle measurements on several low-permeability carbonate, medium-permeability Berea sandstone, and ultra-low permeability Three Forks mudstone core discs using different salinities brine with and without CO2 gas. The contact angle measurements confirmed that favorable wettability alteration is achievable with the proposed EOR process. In addition, visual observations suggested that the proposed EOR process could be effective for cleaning the matrix-fracture interface in conventional and unconventional reservoirs. Interfacial tension (IFT) measurements and correlation relevant to the EOR process is also included in this study. Introduction By combining low-salinity waterflood EOR and gas injection EOR, a new EOR process is proposed. The new EOR process is low-salinity water-alternate-gas EOR. We will first review both low-salinity waterflood and gas injection (mainly CO2 injection EOR processes); then we will introduce the theoretical background of the new hybrid of low-salinity and CO2 EOR. Finally, we will discuss our experimental observations and provide conclusion and recommendations. Low-salinity waterflood EOR Waterflooding is by far the most widely used method to increase oil recovery. Recent studies show that, by modifying the ionic content of water, wettability of reservoirs can be altered. When using seawater to alter wettability, there are different chemical mechanisms in effect between sandstone and carbonate formations. The polar components in the crude oil reacts †

Colorado School of Mines, Petroleum Engineering, 1600 Arapahoe Street, Golden, CO 80401. The Petroleum Institute, Petroleum Engineering, Abu Dhabi. * To whom correspondence should be addressed at present address: Colorado School of Mines, Department of Petroleum Engineering, Marquez Hall #206, 1600 Arapahoe Street, Golden, CO 80401. E-mail: [email protected] ‡

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with the positively charged carbonate rock surface differently from the negatively charged quartz/clay in sandstone formations, indicating different chemical bonding reaction mechanisms. In general, wettability alteration can be improved by modifying the ionic composition of the injected sea water (Jadhunandan and Morrow, 1995; Tang and Morrow, 1997; Strand et al. 2006; Zhang and Austad, 2006; Karoussi and Hamouda, 2007; RezaeiDoust et al., 2009; Cissokho et al., 2010; Austad et al., 2010; Morrow and Buckley, 2011; Zekri et al., 2012; Al-Harrasi et al., 2012; Nasralla et al., 2011; Alameri et al., 2014; Awolayo et al., 2014; Alameri 2015; Alameri et al., 2015a; Alameri et al., 2015b; and references cited in these studies). Several mechanisms have been proposed in the literature for low-salinity waterflooding EOR. These include: fines migration and rock dissolution (Tang and Morrow 1999; Pu et al., 2010; Yousef et al., 2011; Yi and Sarma 2012), pH increase (Morrow and Buckley 2011; McGuire et al., 2005), multi-component ion exchange (Lager et al., 2008; Austad et al., 2011; Zahid et al., 2012; Austad et al., 2012), and a double layer expansion (Ligthelm et al., 2009; Lee et al., 2010). Combinations of these mechanisms is believed to promote favorable wettability alterations, hence improved oil recovery (Alotaibi et al., 2011; Yousef et al., 2011; Yi and Sarma 2012; Emadi and Sohrabi 2013; Alameri et al., 2014; Teklu et al., 2015a). Fines Migration and Rock Dissolution: Tang and Morrow (1999) performed low-salinity waterflood experiments using sandstone core. They reported a reduction in the absolute permeability of the core samples during low salinity waterflood. They concluded that this might due to the fines migration when low-salinity water was injected. Hence, they sugest that this can lead to improved oil recovery as some pore throats were blocked allowing the water flood changes the path to unswept zones. Similarly, Pu et al. (2010) studied the effect of low-salinity waterflooding through coreflood experiments using sandstone core sample. An increase in anhydrite dissolution was observed when low-salinity water was used. Moreover, an increase in sulfate concentration was observed in the effluent samples due to anhydrite dissolution. Based on surface complexation modeling, Hiorth et al. (2010) concluded that calcite dissolution could be the main mechanism of low-salinity water EOR. Based on NMR study of before and after low-salinity waterflood of carbonate cores, Yousef et al. (2011) suggest that rock dissolution of carbonate cores could also be one of the contributing mechanism. pH Increase: McGuire et al. (2005) noticed an increase in pH due to low salinity waterflooding. This is due to reactions with the minerals in the reservoirs; hence pH increases. Similarly, Morrow and Buckley (2011) reported an increase in the pH can contribute to improved oil recovery during low-salinity waterflood. Based on published and their experimental observations, Austad et al. (2010) sugested that, local pH increase caused by desorption of adsorbed cations from clay minerals could be responsible for residual oil mobilization by low-salinity water flooding. Multi-component Ion Exchange: various studies presented in the literature on low-salinity waterflooding in carbonate reservoirs indicated that SO42-, Ca2+, and Mg2+ (divalent ions) played a vital role (key ions) in the wettability alteration (Strand et al., 2006; Zhang and Austad 2006; Austad et al., 2012). Based on experimental results of Austad et al. (2012), a chemical mechanism was discussed regarding the interactions between Ca 2+ and SO42-, and also between Mg2+ and SO42- at chalk surface (carbonate formation), causing to desorb the carboxylic organic materials. According to Austad et al. (2012), Mg2+ only has a strong impact on the low-salinity waterflood process when temperature is high. Similarly, Lager et al. (2008) showed that multicomponent ion exchange occurred when low salinity water was injected and improved oil recovery in sandstone reservoirs. They reported that multicomponent ion exchange happens between rock, oil, and brine; hence, oil droplets were detached from the rock surface. From laboratory experiments, Lager et al. (2008) observed a decrease in the concentration of Mg2+ and Ca2+ in the effluent samples. Electrical Double Layer (EDL) Expansion: Low-salinity waterflooding can lead to wettability alteration due to the double layer expansion (Ligthelm et al., 2009; Lee et al., 2010; Nasralla et al. 2011). Ligthelm et al. (2009) suggested that reducing the salinity and the multi-valent cations in the brine solution, the EDL surrounding the clay will expand; hence more oil will flow to the surface. Nasralla et al. (2012) conducted coreflood experiment, contact angle measurements, and zeta potential measurements to test if the electrical double layer expansion is the main mechanism of low-salinity waterflooding. The correlation of zeta potential measurements to the results of the coreflood of Nasralla et al. (2012) could demonstrate that double layer expansion can be one of the dominant mechanisms by which low salinity water alters the wettability or rock surfaces favorably. CO2 Flooding EOR Hydrocarbon and non-hydrocarbon gas injection in general, and CO2 floods in particular, is the leading EOR flooding process in light-oil and medium-oil, both in sandstone and carbonate reservoirs (Stalkup, 1978; Holm, 1987; Manrique et al., 2007; Ghedan 2009; Alvarado and Manrique 2010; OGJ 2014). Mostly from Permian basin, by the start of 2014, 300 M bbl/day of oil is produced by CO2-EOR in USA and is forecasted to grow to 638 M bbl/day by 2020 (Kuuskraa and Wallace 2014; OGJ 2014). Current utilization factor in mature USA CO2-EOR projects range from 5 to 15 Mcf of CO2 injected/bbl of oil produced (DOE/NETL 2014). Even though, miscible and immiscible continuous injection, carbonated water flooding, huff and puff injection are among the

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possible scenarios of CO2 injection EOR processes, water-alternating-CO2 (WAG) is the most frequently applied EOR process (Stalkup, 1983; Brock and Bryan, 1989; Hadlow, 1992; Christensen et al., 2001; Rogers and Grigg, 2001; Ghedan 2009; Alvarado and Manrique 2010). This is mainly to improve sweep efficiency and minimize cost. Typical incremental oil recovery by CO2 flooding ranges between 5 to 25 % (Holm, 1987; Ghedan 2009). Recent experimental, theoretical, and modeling studies show that CO2 injection with appropriate soaking time can be a promising EOR process for unconventional liquid rich shale reservoirs (Hawthorne et al., 2013; Gamadi et al., 2014; Teklu et al., 2014a; Teklu et al., 2014b; Teklu et al., 2014c; Alharthy et al., 2015; Sheng 2015). The mechanisms of residual oil mobilization by CO2 flooding in conventional reservoirs include – solution gas drive, immiscible drive, first or multiple contact miscible drive processes. These driving processes enhance oil recovery mainly by – (a) promoting oil-swelling, (b) reduce oil viscosity, (c) favorable density change of oil and water phases, where the density difference between oil and water reduces and minimizes gravity segregation, (d) rock wettability alteration towards water wet, and (e) lower IFT between hydrocarbon-enriched CO2 and CO2-saturated oil (Holm and Josendal 1974; Stalkup, 1987; Rao, et al., 1992; Lansangan and Smith, 1993; Srivastava, et al., 2000; Ghedan 2009). Residual oil mobilization by gas injection EOR is optimal when miscibility is achieved between injected gas and reservoir oil. Typically, the minimum miscibility pressure (MMP) of CO2 with a given reservoir oil is lower compared to light hydrocarbon and N2 injection gases (Stalkup, 1983; Stalkup, 1987; Holm, 1987; Teklu et al., 2012; Teklu et al., 2014a); hence, technically, CO2 injection is preferred to other injection gases. CO2 injection could offer economic advantage when it is cheaper than hydrocarbon gas for EOR. In addition, CO 2 injection sequesters significant amount of greenhouse gas while improving production. Theory In this study, we propose a new EOR process by combining low-salinity waterflood and CO2 flood EOR processes, for both sandstone and carbonate reservoirs. This combined EOR process optimizes oil recovery by synergistically utilizing the possible incremental oil recovery mechanisms of the two EOR processes. The following are some of the theoretical possibilities for improved oil recovery in the investigated EOR process: Effect salinity on CO2 solubility in brine and IFT: Experimental and modeling study show that solubility of CO 2 in brine increases with decreasing salinity of water (Li and Nghiem 1986; Pollack et al, 1988; Enick and Klara 1990; Duan and Sun, 2003). To show this effect, we implemented Enick and Klara (1990) CO 2-brine solubility model as shown in Appendix A and compared with Li and Nghiem (1986) CO 2-brine solubility model. Fig. 1 shows the comparison of solubility of CO2 in water (with zero salinity) and brine of 100,000 ppm total dissolved solute (TDS) at reservoir temperature of 160 oF and wide range of pressure. Eqs. A.1 through A.14 (Appendix A) are used for the case of Enick and Klara (1990) CO2-brine solubility model, and WINPROP software is used for the case of Li and Nghiem (1986) model. As can be seen in Fig. 1, the CO2-brine solubility of both approaches agrees with each other very well. This CO2 solubility increment with low-salinity can lead to improved oil recovery through CO2–brine IFT reduction. Reservoir conditions CO2–brine IFT experiment by Bennion and Bachu (2008) show that CO2–brine IFT decreases with increasing CO2 solubility in brine. CO2–brine IFT as a function of pressure, temperature and salinity (solubility) can be mathematically expressed as in Eq. 1. 0.2369   T   T 22.178  ; if ln    pw  CO , b  p wCO ,b      0.0576  T   T  ; if ln   47.7128  p w pw CO , b  CO , b    2

IFTco2 brine

2

2

2

   4.5  (1)

   4.5 

In Eq. 1, IFTco2 brine is in dynes/cm, wCO2 ,b is mole fraction of CO2 in aqueous phase of corresponding salinity at in-situ condition of T in oF, and p in psi. Note that the salinity effect on IFT is accounted in the solubility calculation. Eq. 1 is a new CO2–brine IFT correlation developed in this study. The correlation is based on reservoir conditions experimental IFT data from Bennion and Bachu (2008) in conjunction with the solubility model discussed above. Details of the correlation are provided in Appendix B. Reduction in CO2-Brine IFT with increasing CO2 solubility can lead to enhancement of oil recovery due to wettability alteration and by reducing the IFT between CO2 saturated brine and oil phases. A study by Yang et al. (2005) show that, at a given pressure and temperature conditions, brine-oil IFT reduces if CO2 is introduced to the system. They also show that, the

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CO2-brine IFT and oil-brine IFT reduction increases with increasing pressure or increasing CO2 solubility. A moderate CO2– brine IFT reduction was also observed in our room condition experiment setup as we will discuss in the experimental section. Wettability Alteration: Wettability alteration is an effective approach to enhance oil recovery. Rock wettability alteration is dependent on – oil composition, brine composition, rock surface mineralogy, and system temperature, pressure and saturation history (Anderson, 1986; Morrow, 1990a; Morrow 1990b; Hirasaki, 1991; Buckley et al., 1998; Alameri et al., 2014; Teklu et al., 2015a). One of the main mechanisms of enhancing oil recovery by miscible gas flooding, such as CO2 flooding, is the achievement of favorable wettability alteration (Huang and Holm, 1988; Rao, et al., 1992). Al-Mutairi et al., (2014) performed reservoir temperature and immiscible pressure condition wettability measurement on carbonate core, and their result show that – (a) exposing oil-wet carbonate rock to brine saturated with CO2 causes wettability alteration to an intermediate-wet state; (b) as the CO2 concentration in brine increases, the level of wettability alteration increases. Similar results were observed in our contact angle measurement between reservoir core discs that mimics a condition of miscible CO2 flooding condition. The experimental procedure and results are presented in the wettability and IFT experiment section. Carbonated Waterflood EOR: Laboratory (Johnson, 1952; Holm, 1959; Holm, 1963; Riazi et al, 2011; Dong et al., 2011) and field scale (Martin, 1951; Hickok, et al., 1960; Christensen, 1961; Hickok and Ramsay, 1962) studies show that carbonated waterflood improves oil recovery as compared to conventional water flooding. Carbonated water flood (CWF) is an improved oil recovery mechanism by injecting CO2 saturated (or nearly saturated) water into oil reservoirs. The mechanism of CWF to improve oil recovery is similar to CO2 flooding. And as CO2 concentration in the water phase increases, residual oil mobilization by CWF increases. LS-WACO2 or LS-WAG EOR – Theory: From the above discussions on IFT reduction and wettability alteration and from the experimental study that will be discussed below, we claim that, low-salinity water-alternate-CO2/gas injection improves oil recovery of conventional or high-salinity water (such as seawater) alternate gas flooding by forming in-situ carbonated water of higher CO2 saturation in the brine phase. Even though, higher CO2 saturation in brine phase would mean slightly lower CO2 concentration in the oil phase, which would seem overall reduction of oil recovery, on the other hand, higher CO2 saturation in the brine phase lead to: improved wettability alteration effect towards hydrophilic, and improved IFT reduction; subsequently, improved oil recovery. By introducing appropriate type and pore volume of surfactant slug in the proposed EOR process, one would expect further improvement in – (a) IFT between oil and brine reduction and (b) wettability alteration effects; hence, further improved oil recover. Experimental study of low-salinity water alternating surfactant and CO2 flooding on oil-wet carbonate core shows improved oil recovery (Teklu et al., 2015b; Teklu 2015). Experimental Studies Materials Carbonate Cores: several coreflood and contact angle experiments were performed using cores from a low-permeability giant carbonate reservoir in the Middle East. The reservoir is subdivided into three main reservoirs: Reservoir I, II, and III. The experiments in this paper is on cores from Reservoir I. Reservoir I is fractured reservoir with average matrix permeability of 1.5 md, average porosity of 24%, and has average thickness of 43 feet. The three reservoirs have a combined thickness of about 300 ft and currently is undergoing water injection at 800 MB/day and oil production at 560 MSTB/day. Primary oil production began in 1983 with water injection starting in 1984. The first water breakthrough occurred in 1991. Over the years, water cut has increased from 5% in the early 1990s to 24% in 2006 (Shibasaki et al., 2006). Currently, most of the oil production comes from Reservoir II and III. These two reservoirs have high porosity and permeability as compared to Reservoir I. Jobe (2013) conducted extensive geological description of Reservoir I. The cores used in core flooding experiments and wettability measurements are from facies A of Reservoir I (Fig. 2). Additional low-salinity water flood corefloods on Facies A, B and C is reported elsewhere in Alameri et al. 2014 and Teklu et al., 2015a. According to facies description by Jobe (2013), Facies A is heterogeneous with dominant micro/macro porosity and heavy oil stains, and the rock texture is Lithocodium-Bacinella boundstone; abundant Lithocodium-Bacinella echinoderm, coral bivalve skeletal debris, and benthic forams are present in this facies. Facies B is Rudist-Bivalve wacke- to packstone, has plenty of vugs and burrows, with dominant micro/macro porosity. Facies C is Lithocodium-Bacinella wackestone with dolomitic burrows (Jobe, 2013). The mineralogical study by Jobe (2013) using thin section analysis and quantitative mineral mapping shows facies A, B, and C are dominantly calcite with only minor occurrences of dolomite, glauconite and pyrite. Sandstone Cores: additional coreflood experiment was performed on a low permeability sandstone core and wettability measurements on 65.4md permeability and 17% porosity Berea sandstone. The Berea sandstone mineralogy is mainly quartz.

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Three Forks Mudstone Cores: contact angle measurements on ultra-low permeability unconventional reservoir core samples from Three Forks carbonate mudstone formation in the Williston Basin were performed. The rock fabric of the Three Forks core plug is clay mottled siliceous dolomudstone; it has an effective permeability of 14.4 µD and porosity of 3.81 %. The mineralogy analysis shows that it is 74% dolomite, 19.9% quartz, 3.2% Feldspars, 2.4 % Clays, 0.2% Pyrite, and 0.3 % other minerals. The major pore size contribution determined from mercury intrusion porosimetry (MIP) data is 0.7 µm (Franklin 2014). Crude Oil: A 32 oAPI crude oil from a carbonate reservoir in the Middle East (Reservoir I) is used in the experiments. It has a pH value of 6.5 and its viscosity is 3 cp at reservoir temperature of 195 oF. The crude oil was filtered at 1 micron. Table 1 lists the composition of the reservoir oil. Synthetic Brine: the composition of synthetic seawater (SW) representative of the seawater in the Middle East, and lowsalinity water (LS1, LS2 and LS3) used in coreflood, IFT, and contact angle measurements are listed in Table 2. Their viscosity at reservoir temperature of 195 oF was measured as 0.535 cp. Filtered Formation Brine: the ionic compositions of the filtered Reservoir I Formation Brine (FB) used in the experiments are given in Table 3. Its pH was 7.17 and its viscosity at reservoir temperature of 195 oF was 0.535 cp. However, it should be noted that, the actual formation brine of Reservoir I is around 200,000 ppm. Note that, the formation brine composition in Table 3 is the measured afar filtering it with 0.5 micron to avoid pore plugging during core saturation; also some of the salts were settled down while it was kept in stock for more than 4 years; hence, its salinity was reduced to almost half the actual salinity. Equipment This study was carried out using four main equipments – coreflooding apparatus, ultra-fast centrifuge, contact angle and IFT measuring apparatus (Drop Shape Analyzer, DSA-100), and Rising Bubble Apparatus (RBA). Fig. 3 presents schematic diagram of the core flooding apparatus, which is capable of running experiments at reservoir conditions. Centrifuge equipment was used to saturate the core samples. Drop Shape Analyzer (DSA-100) was used to measure contact angles between solids and fluids and IFT between different fluids. And the RBA was used to measure the minimum miscibility pressure (MMP) of reservoir oil and injection gas at reservoir temperature. Other experimental equipment such as capillary tube viscometer, air permeability and porosity measuring equipment are also used in this study. Experimental Procedures MMP Experimental Procedure The experimental procedure describe in Adekunle (2014) was followed for the MMP measurement between reservoir oil and CO2 gas using the Rising-Bubble Apparatus (RBA) equipment at a reservoir temperature of 195 oF. Contact Angle Measurement Procedure The experimental procedure followed to measure the contact angle is as follows: (a) Core discs / slice were prepared; the core disc dimensions are approximately 2 cm by 2 cm and 0.5 cm thickness; (b) Core discs were cleaned from hydrocarbon using Soxhlet extractor -- first with toluene, then with methanol, and again with toluene, until no oil trace was observed; then they were dried in an oven of about 120 oF for 24 hrs.; (c) Core disc surfaces were smoothed (polished) using different grades of sandpaper (of increasing in fineness), with veryfine sandpaper size used to smooth the surface at last; (d) Core discs were saturated with formation brine using desiccator; (e) The cleaned, polished, and saturated core discs were aged inside crude oil at reservoir temperature for eight weeks (here after crude-aged core discs); (f) Prior to surface condition contact angle measurements, unbleached paper towels were used to remove crude oil from the surface of the core. The intent was to remove the extra oil film on the rock surface, and to make sure that the oil droplet is in direct contact with the aged core surface. The unbleached paper towel type used doesn’t leave any fine particle on the core disc surface; hence, doesn’t affect the wettability measurements; (g) The core discs were then submersed inside variable salinity brine with or without 1,000 ppm surfactant; equilibrated inside the sounding fluids for 30 min. to 1 hr.; and oil droplet (usually 1 to 10 µl) was dispensed from beneath of the core discs using a 0.632 mm outer diameter syringe needle. This method of measuring contact angle is called captive bubble or captive droplet method. The contact angle measurements were performed using DSA-100 apparatus equipped with high resolution camera and digital processing software. The measurements were checked for repeatability for at least three times in each experiment. The contact angle measurement variation in repeated experiments typically falls in the range of less or equal to +/- 0.5 degrees of the reported (average) ones.

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To capture the effect of CO2 on wettability alteration, additional room condition contact angle measurements were performed on crude-aged Carbonate, Berea sandstone, and Three Forks core discs at measurement conations B and C and compared with measurement condition A and D with no involvement of CO 2. The following are brief descriptions of the measurement condition A to D: Measurement condition A – this is base case contact angle measurement, where the core discs were crude-aged for eight weeks at reservoir temperature and the surrounding brine during contact angle measurements between the discs and oildroplet was seawater (SW) (performed using the procedures described ‘a’ to ‘g’). Measurement condition B – the crude-aged discs where kept for two days in a piston at 2,500 psi inside a mixture of 300 ml seawater (SW) and 200 ml CO2; the core discs and SW+CO2 mixture were then extracted from the piston after slowly releasing the pressure; then contact angle measurements were performed at room conditions between oil-droplets and the core discs where the surrounding fluid was the SW-CO2 mixture extracted from the cylinder hence has less CO2 concentration as the pressure was atmospheric. This was to mimic the reservoir condition of seawater alternated CO 2 EOR process. Measurement condition C – the core discs that underwent measurement condition B were kept for additional two days in a piston at 2,500 psi inside a mixture of 300 ml LS 1 and 200 ml CO2; the core discs and LS1+CO2 mixture were then extracted from the piston after slowly releasing the pressure; then contact angle measurements were performed at room conditions between oil-droplets and the core discs where the surrounding fluid was the LS 1-CO2 mixture extracted from the cylinder hence has less CO2 concentration as the pressure was atmospheric. This measurement condition was to mimic the reservoir condition of low-salinity water alternated with CO2 EOR process. The 2,500 psi in both measurement conditions B and C were chosen to mimic miscible CO2 situation. Measurement condition D – this measurement condition is where the core discs are cleaned and un-aged and the surrounding fluid was seawater (SW) (performed using the procedures described ‘a’ to ‘g’ without step ‘e’). This measurement condition was performed for comparison reason to show how reservoirs wettability is altered in secondary and tertiary recovery mechanisms where condition D is the extreme possible situation when the reservoir pore is ‘cleaned’ during many pore volume CO2 injection. IFT Experimental Procedure IFT measurement between two immiscible fluid phases can be measured using various methods; among them are – (a) pendant drop, (b) sessile drop, (c) spinning drop, (d) capillary rise methods. In this study DSA-100 equipment and pendant drop method is used to measure the IFT between oil and variable salinity brine. In the case of SW+CO 2 and LS1+CO2 mixtures, similar approach to the contact angle measurement described in measurement conditions B and C were employed; i.e. keeping the fluid of interest with the core discs in a high pressure cylinder for two days, and measure the IFT at surface conditions. This measurement may not be a representative of the brine-oil IFT decrease because of CO2 at reservoir conditions, as most of the CO2 were escaped during the IFT measurement; however, it can be used as a qualitative indication. Coreflood Experimental Procedure Cores were prepared, cleaned using toluene and methanol. The petrophysical properties such as permeability and porosity were measured. Rock properties and brief description of the core flood experiments are listed in Table 4. All cores are from the Middle East carbonate reservoir, except one of the experiment which was performed on a low permeability sandstone core. Since the cores are tight, the ultra-high speed centrifuge was used to fully saturate the cores with formation brine. After the cores were saturated with formation brine using centrifuge, the following procedures were followed during the core flooding experiment: i. Cores were placed in the core holder, and confining pressure (2,300 psi), back pressure regulator (1,800 psi), and reservoir temperature (195 oF) were applied to mimic the reservoir conditions. ii. Formation brine was injected at 0.1 cc/min flow rate. This is to make sure that the core is still 100% saturated with brine and no air is trapped in the pores and also to determine the relative permeability of the core to brine as shown in Table 4. iii. Oil was then injected at 0.1 cc/min flow rate until residual water saturation (S wi) is achieved. The oil relative permeability end point was also determined at this step. iv. To restore wettability, eight weeks of aging was applied for the first and second core flood experiments; whereas two weeks of aging was applied for the third experiment. v. Prior to sea water injection, about 4 PV oil is injected to mimic oil saturated reservoir condition. vi. Seawater was injected to displace the oil at 0.1 cc/min flow rate. At this point, oil recovery during seawater flooding and seawater relative permeability end point was determined. vii. After establishing residual oil saturation to seawater flooding (Sorw), three sets of low-salinity waterflooding were performed. The first low-salinity flood (LS1) is obtained by diluting the seawater twice, and LS2 is four times diluted seawater and LS3 is fifty times diluted seawater.

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viii. ix. x.

CO2 flood at 0.3 cc/min was followed the low salinity water floods. During the CO 2 flood, the confining pressure and back-pressure regulator were raised to 2,700 psi and 2,500 psi to achieve miscible flood process. During seawater or low-salinity water flooding, the production fluids are collected in fraction collector (see Fig. 3), then the oil and brine are collected in a graduated tube and centrifuged and measured. For the case of CO2 flooding case, the separator is used to collect the production fluid; and the produced gas is measured using the gas flow meter (GFM) (see Fig. 3); and the oil and brine are collected in a graduated tube and centrifuged and measured.

Experimental Results and Discussions MMP Measurement The MMP of the reservoir oil with CO2 gas was measured in our lab at reservoir temperature of 195 oF using the RisingBubble Apparatus (RBA). The MMP of reservoir oil and CO2 gas is 2500 psi. The MMP of reservoir oil and CO2 gas also calculated using the Multiple Mixing Cell (MMC) approach (Teklu et al., 2012), and good match has been achieved with the experimental data. The MMP of crude oil with CO2 gas is determined using MMC approach as 2470 psia. The MMP of rich gas, nitrogen, mixture of rich gas and CO2, and mixture of rich gas and nitrogen gas with the reservoir oil was also determined using MMC approach. Table 5 is the MMP of the reservoir oil with different injection gas scenarios. The MMP numerical results in Table 5 show that NGL and mixture of NGL with CO2 or N2 gases can be used instead of CO2 gas in LSWAG EOR. IFT Measurements The effect of brine salinity on brine-oil IFT was investigated using a pendant drop IFT measurement at ambient conditions. As can be seen in Table 6, brine-oil IFT measurement increases with reduction in salinity. Hence, it is concluded that IFT reduction (as in case of surfactant or CO2) is not the mechanism by with additional oil recovery can be obtained in lowsalinity waterflood EOR as discussed in Alameri et al. 2014. However, for the case of combined low-salinity waterflood and CO2 EOR as continuous or alternate scheme, the effect of brine salinity reduction could have a positive impact on oil-brine IFT as discussed in the theory section. To investigate this idea, brine pH and oil-brine IFT measurements were performed where the brine was the SW+CO2 and LS1+CO2 mixtures after the pressure was released to atmospheric pressure and most of the CO2 were escaped from the solution. This was because our DSA-100 system is not applicable for high pressure IFT measurement. As shown in Table 7, at atmospheric pressure and room temperature, a moderate IFT and pH reduction due to CO2 solution in the mixture was observed as compared to the SW and LS 1 brines without CO2. Further brine-oil IFT reduction can be achieved as reported in study by Yang et al., (2005) for a case of crude oil-brine-CO2 system at high pressure and temperature. Contact Angle Measurements Surface condition captive oil droplet contact angle measurements of core-oil-brine system were performed for aged and unaged carbonate, Berea sandstone, and Three Forks core samples. Table 8, and Figs. 4, 5 and 6 are contact angle (CA) measurements of cleaned un-aged carbonate, Berea sandstone, and Three Forks discs; and Table 9, and Figs. 7, 8 and 9 are contact angle (CA) measurements of crude-aged carbonate, sandstone, and Three Forks core disc cases. Crude-aged core discs refers where cleaned cores were saturated with formation brine using desiccator, and then submersed in a crude oil and aged at reservoir temperature for eight weeks. Wettability alteration with low-salinity water was observed for the Carbonate, Berea sandstone and Three Forks core discs as shown in the figures and tables. The volume of the oil-droplets during the contact angle measurement is reported in the corresponding tables for scale purpose. Fig. 10 shows the photo of the core discs corresponding to measurement conditions A, B, C, and D. Measurement conditions B and C are where the effect of CO2 on wettability alteration was captured during a two day soaking the aged core samples at higher pressure prior to the surface condition contact angle measurements as discussed on the contact angle measurement procedure section. Figs.11 and 12, and Table 10 show the contact angle measurement conditions A, B, and C for carbonate, Berea sandstone and Three Forks core discs. As shown in Fig. 11, the wettability of carbonate, Berea sandstone, and Three Forks constantly changed towards water wet wettability state as we progressed from measurement condition A to D, and this implies that wettability alteration is one of the main mechanism in mobilizing residual oil in hybrid low-salinity and CO2 flooding EOR process. From these wettability measurements in addition to the oil removal process observed in processes B and C (Fig. 10), it can be concluded that – in addition to the EOR mechanism, CO2 injection can act as an effective matrix-fracture interface cleanup stimulation technique in sandstone, carbonate and shale reservoirs (Teklu 2015; Teklu et al., 2015c). This observation, we believe, is very significant as the proposed EOR can be applied as stimulation technique, especially when applied in multistage hydraulic fractured horizontal wells in ultra-low permeability reservoirs such as the Bakken, Eagle Ford, and Three Forks formations.

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Contact angle measurements may not capture the complex nature of wettability evolution in the investigated EOR process. Pore scale surface-fluid interaction studies using, for example, zeta potential experiments are recommended. Coreflood Experiments Coreflood Experiment 1: Fig. 13 shows oil recovery factor (RF) and pressure difference between injection and production end (∆P, psi) as a function pore volume injected (PV inj) of the first coreflood. A composite carbonate cores from facies A is used in this experiment (see Table 4). During waterflooding (WF), 61.2% oil was recovered. A decrease of ionic concentrations when the seawater was diluted twice (i.e. LS1) resulted in an incremental oil recovery of up to 6% with another additional 1.1% incremental recovery during the second low salinity waterflooding (LS 2). No additional recovery was obtained during the third low salinity flood cycle (LS3).The connate water saturation of this experiment was 29.6%, and the residual oil saturation after producing oil using the series of low-salinity water floods was 21.5%. Fourteen PV continuous CO2 gas flooding was performed at 0.3 cc/min following the three sets of low-salinity waterfloods. Incremental oil recovery of 14.2 % has been obtained during the miscible CO2 flooding. The injectivity to CO2 flood is observed to increase as witnessed by the reduction of pressure drop during the CO 2 flooding period. Total oil recovery during all injection sequences of this experiment is 81.9%. Table 11 shows effluent ionic analysis after approximately 3 pore volume injection of SW, LS 1, and LS2 flooding sequences. The following observation can be seen in this table: (a) Effluent carbonate and bi-carbonate ion concentration were observed to increase during waterflood sequences. This can be due to carbonate dissolution during seawater and low-salinity waterfloods. This is also consistent with the slight permeability improvement as depicted in reduction of pressure drops during the waterflooding sequences. (b) The total dissolved solids were observed to increase compared to their injection TDS values during SW and LS1 flooding sequences; i.e. 51,346 ppm vs. 55,044 ppm for seawater flooding, and 25,679 ppm (see Table 2 or half TDS of synthetic seawater in Table 11) vs. 29,358 ppm for LS1. This increase in TDS is due to mixing with the connate water saturation of the preceding waterfloods. It can also be deduced this assertion from the existent of potassium, iron, and strontium ions in the effluent samples, despite the fact that there was no such ions in the synthetic seawater or low-salinity water injected. (c) A slight decrease in TDS of LS2 effluent (i.e. 11,177 ppm) compared to its original TDS of 12,840 ppm (see Table 2 or one quarter TDS of synthetic seawater in Table 11) can be attributed to salt adsorption inside pores. Coreflood Experiment 2: Similar to first coreflood protocol was applied on the 2nd coreflood on another facies A composite cores from Reservoir I (see Table 4). In this experiment, 52.8% oil was recovered during waterflooding. 5.2 % additional oil was recovered during LS1 flooding; 0.4% and no additional oil was recovered during LS2 and LS3 flooding cycles respectively. Finally, 25 % additional oil was recovery during 10 PV continuous miscible CO 2 flooding. Fig. 14 shows oil recovery factor and pressure drop as a function pore volume injected. Similar to Coreflood Experiment 1, the injectivity to CO2 flood is observed to increase as witnessed by the reduction of pressure drop during the CO 2 flooding. Total oil recovery during all injection sequences of this experiment is 83.4%. Compared to Coreflood Experiment 1, a lower oil recovery was observed in this experiment during seawater flood (52.8% vs 61.2% for Coreflood Experiment 1). This significant difference of about 8.4% oil recovery during seawater flood is attributed to the difference in core quality (i.e. brine permeabilities of about 3.38 mD vs. 1.49 mD, see Table 4). Similarly, during first and second low-salinity waterflood sequences of Coreflood Experiment 2 yielded lower oil recovery compared to Coreflood Experiment 1. However, it was observed that the total oil recovery of all sequences (including CO2 flood), of the two experiments were very similar (81.9% for Coreflood Experiment 1 vs. 83.4% for Coreflood Experiment 2). This is mainly due to the higher efficiency of mobilizing residual oil during CO 2 flooding at miscible pressure. Coreflood Experiment 3: This core flood experiment was performed on low-permeability sandstone core (see Table 4). Flooding procedure similar to Coreflood Experiment 1 and 2 were used with the following exceptions: (a) injection rates were 0.05 cc/min, (b) two weeks of aging, (c) back pressure of 1,000 psi, and (d) confining pressure of 1,300 psi. Thus, this experiment was an immiscible CO2 flood. As shown in Fig. 15, 35.3% of oil was recovered during 5 PV seawater flooding (WF), additional 7.7% oil was recovered during 5 PV low-salinity water flooding (LS1), and during the 7 PV CO2 flooding another 38.5% oil was recovered. The total recovery of Coreflood Experiment 3 was 81.5% which is slightly lower than the oil recoveries in both Coreflood Experiment 1 and 2. The restored wettability of sandstone core was more favorable to seawater flood compared to the carbonate cores (see Figure 11 or Table 9). However, the low-permeability of this sandstone coreflood (kbrine = 0.55 mD, see Table 4) leads to very poor oil recovery of only 35.3% during seawater flood compared to the seawater flood performance of both Coreflood Experiment 1 and 2. The poor performance during seawater flooding of Coreflood Experiment 3 could also be partially attributed to the higher capillary end effect, as it was performed on short core and with low injection rate. On the other hand, better coreflood performance was observed during LS1 flood (oil recovery of 7.7%), compared to both Coreflood Experiment 1 and 2; this

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might indicate that, generally, the performance of low-salinity waterflood for sandstones is better than carbonates, however, this observation needs further investigation performed on long core. Another observation from this experiment is that even though the CO2 flood of this experiment was performed at immiscible condition, higher than the previous two corefloods (recovery of 38.5%) was observed; this could be because the miscible or immiscible flood conditions imposed on these coreflood experiments are no more relevant to compare their performance once more than 1.2 PV CO2 is injected. Note that 1.2 PV injection criterion is used in slim-tube MMP experiments and simulations (see Yellig and Metcalfe, 1980; Metcalfe, et al., 1973; Teklu et al., 2012). Conclusions and Recommendations In this paper, we proposed a new EOR process to improve economics of low-salinity waterflooding, which involves lowsalinity water-alternating-CO2 (LS-WAG) injection. We conducted core flooding, IFT, and contact angle measurements. The following are our conclusions:  Low salinity waterflood after seawater flooding produced significant additional oil. Following the low-salinity flood with CO2 injection improved recovery further.  Injection of CO2 altered wettability of both carbonates and sandstones toward hydrophilic conditions.  The higher solubility of CO2 in low-salinity water (as compared to high salinity water) is the main reason for the improvement in residual oil mobilization as compared to conventional WAG. Higher CO2 solubility in brine can lead to stronger carbonated water in situ to alter wettability and reduce IFT and viscosity further.  Moderate oil-brine IFT and brine pH reduction was observed in the proposed EOR process at room conditions. Further IFT and brine pH reduction is anticipated at reservoir pressure.  Based on reservoir conditions CO2-brine IFT measurements from literature, CO2-brine IFT correlation that is dependent on temperature, pressure, and salinity (through CO 2 solubility calculation) has been developed. Even though our core flood experiments were designed as a continuous CO 2 flood after seawater and low-salinity waterfloods, low-salinity-water-alternate-CO2 gas (LS-WACO2 or LS-WAG) EOR scheme is recommended for field application. This is to minimize cost of CO2 injection as well as to achieve optimized sweep efficiency. In case economical and EOR scale natural or anthropogenic CO2 gas is not available from nearby sources, NGL or a mixture of nitrogen and NGL can be applied. Another observation from our coreflood is, diluting the seawater to salinity level half of the seawater (LS1) may be enough to achieve additional oil recovery by the proposed EOR process. Our third immiscible condition coreflood in sandstone core in conjunction with immiscible condition wettability measurement from literature (Al-Mutairi et al., 2014) suggests that, the new LS-WACO2 or LS-WAG EOR process can still be applied under immiscible pressure conditions. We also think that, the new proposed EOR, LS-WACO2 or LS-WAG, could be effective in cleaning the fracture-matrix interface in conventional and unconventional reservoir, which can promote improvement in oil recovery.

Nomenclature SW LS1 LS2 LS3 LS-WACO2 LS-WAG IFT

Seawater Low salinity with diluting the synthetic seawater 2 times Low salinity with diluting the synthetic seawater 4 times Low salinity with diluting the synthetic seawater 50 times Low-salinity water-alternate-CO2 gas Low-salinity water-alternate-gas, where the gas can be CO2, NGL, or mixture of NGL with CO2 / N2 Interfacial tension

Acknowledgment The authors are grateful to Abu Dhabi National Oil Company (ADNOC) and the Petroleum Institute (PI) at Abu Dhabi; Marathon Center of Excellence for Reservoir Studies (MCERS) and Center for Earth Materials, Mechanics, Characterization (CEMMC) at Colorado School of Mines (CSM) for their support of this study. We also would like to thank SURTEK and TIORCO companies and Ken Bensching at SURTEK for their advice on some of the experimental procedures; Our thanks also goes to Dr. Manika Prasad for providing Berea sandstone core sample that we used in wettability studies, and to Alyssa Franklin for providing unconventional reservoir core samples from The Three Forks formation including their geological

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Rao, N. D., Girard, M., Sayegh, S. G., 1992. Impact of Miscible Flooding on Wettability, Relative Permeability, and Oil Recovery. SPE Res. Eng., 7(02), 204-212, SPE 20522-PA. RezaeiDoust, A., Puntervold, T., Strand, S., Austad, T., 2009. Smart Water as Wettability Modifier in Carbonate and Sandstone: A Discussion of Similarities/Differences in the Chemical Mechanisms. Energy & Fuel Article, 23, 4479-4485. Riazi, M., Sohrabi, M., Jamiolahmady, M., 2011. Experimental study of pore-scale mechanisms of carbonated water injection. Transport in porous media, 86(1), 73-86. Rogers, J. D., Grigg, R. B., 2001. A Literature Analysis of the WAG Injectivity Abnormalities in the CO 2 Process. SPE Res Eval & Eng., 4 (05): 375 - 386, SPE 73830-PA. Sheng, J. J., 2015. Enhanced oil recovery in shale reservoirs by gas injection. Journal of Natural Gas Science and Engineering, 22, 252259. Shibasaki, T., Edwards, H. E., Qotb, M., Akatsuka, K., 2006. Identification of Key Fracture Effects on Fluid Flow and Iterative Approach for Effective Permeability Modeling of a Matrix-Dominated Carbonate Reservoir. SPE 101480, presented at the Abu Dhabi Petroleum Exhibition and Conference, Abu Dhabi U.A.E, 5-8 November. Srivastava, R. K., Huang, S. S., Dong, M., 2000. Laboratory Investigation of Weyburn CO2 Miscible Flooding. Journal of Canadian Petroleum Technology, 39(02), PETSOC-00-02-04. Stalkup, F. I., 1978. Carbon Dioxide Miscible Flooding: Past Present and Outlook for the Future. JPT, 30(08), 1-102. Stalkup, F. I., 1983. Miscible displacement. SPE Monograph Series, Richardson, TX (1983). Stalkup, F.I., 1987. Displacement Behavior of the Condensing/Vaporizing Gas Drive Process. SPE 16715, presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, September 27-30. Strand, S., Hogensen, E.J., Austad, T., 2006. Wettability alteration of Carbonates – Effects of potential determining ions (Ca2+ and SO42-) and temperature. Colloids and Surfaces A: Physicochemical Eng. Aspects, 275, Issues 1-3, 1-10. Strohmenger, C.J, Weber, L.J., Ghani, A., Al-Mehsin, K., Al-Jeelani, O., Al-Mansoori, A., Al-Dayyani, T., Vaughan, L., Khan, S.A., Mitchell, J.C., 2006. High Resolution Sequence Stratigraphy and Reservoir Characterization of Upper Thamama (Lower Cretaceous) Reservoirs of a Giant Abu Dhabi Oil Field, United Arab Emirates. AAPG Memoir 88/SEPM Spec. Publ., pp. 139-171. Tang, G. Q., Morrow, N.R. 1997. Salinity, temperature, oil composition, and oil recovery by waterflooding. SPE Reservoir Engineering, 12(04), 269-276. Tang G. Q., Morrow, N. 1999. Influence of brine composition and fines migration on crude oil / brine / rock interactions and oil recovery. Journal of Petroleum Science and Engineering, 24(2), 99-111. Teklu, T. W., Ghedan, S. G., Graves, R. M., Yin X., 2012. Minimum Miscibility Pressure Determination: Modified Multiple Mixing Cell Method. SPE 155454, presented at SPE EOR Conference Oil and Gas West Asia, Muscat, Oman, April 16-18. Teklu, T. W., Alharthy, N., Kazemi, H., Yin, X., Graves, R., 2014a. Hydrocarbon and Non-hydrocarbon Gas Miscibility with Light Oil in Shale Reservoirs. SPE 169123, presented at the SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April 12-16. Teklu, T. W., Alharthy, N., Kazemi, H., Yin, X., Graves, R., 2014b. Vanishing Interfacial Tension Algorithm for MMP Determination in Unconventional Reservoirs. SPE 169517, presented at the SPE Western North American and Rocky Mountain Joint Regional Meeting, Denver, Colorado, 16–18 April. Teklu, T. W., Alharthy, N., Kazemi, H., Yin, X., Graves, R., AlSumaiti, A., 2014c. Phase Behavior and Minimum Miscibility Pressure in Nanopores. SPE Res Eval & Eng, 17(03), 396-403. SPE 168865-PA. Teklu, T. W., 2015. Experimental and Numerical Study of Carbon Dioxide Injection Enhanced Oil Recovery in Low-Permeability Reservoirs. PhD Dissertation, Petroleum Engineering, Colorado School of Mines. Teklu, T. W., Alameri W., Kazemi, H., Graves, R., 2015a. Contact Angle Measurements on Conventional and Unconventional Reservoir Cores. URTeC 2153996, presented at the Unconventional Resources Technology Conference, San Antonio, Texas, USA, 20-22 July. Teklu, T. W., Alameri, W., Kazemi, H., Graves, R. M., AlSumaiti, A. M., 2015b. Low-salinity-water–surfactant–CO2 EOR: Theory and Experiments. DOI: 10.3997/2214-4609.201412104, presented at the 18th European Symposium on Improved Oil Recovery

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Appendix A: CO2 Solubility in Water and Brine under Reservoir Conditions Experimental and modeling study show that solubility of CO 2 in brine increases with decreasing salinity of water (Li and Nghiem 1986, Pollack et al, 1988; Enick and Klara 1990; Duan and Sun, 2003). To show this effect, we implemented Enick and Klara (1990) CO2-brine solubility model as follows and compared with Li and Nghiem (1986). The main reason of implementing the model in this study was that we want to show that the solubility model can be used in conjunction with a correlation developed here (Appendix B) to estimate CO2-brine IFT at reservoir conditions and given brine salinity. Li and Nghiem 1986 calculates solubility of CO2 in water and brine based on three phase (Oil-Gas-Water/Brine phases) flash calculation where the oil and gas are modeled by a cubic EOS and where the gas solubility in the aqueous phase (fresh water) is estimated from Henry’s law. Li and Nghiem use the scaled-particle theory (SPT) to modify Henry’s law constant to account the solubility reduction due to the presence of salt in the aqueous phase. Enick and Klara (1990) also use Henry’s law to estimate CO2 solubility in distilled water and provided a coloration of reference Henry’s constant for CO 2/H2O system. Enick and Klara also provided an empirical factor to account for a decrease in solubility due to dissolved solids or salinity in the water. The reference Henry’s constant and molar volume of CO2 at infinite dilution as a function of temperature correlations of Enick and Klara’s are generated based on 110 experimental solubility data for wide temperature and pressure ranges. Enick and Klara’s correlation to account the decrease in solubility of CO 2 in brine is developed from 167 solubility data of wider temperature, pressure, and total dissolved solid (TDS) concentrations. Henry’s law for a component sparingly soluble in the aqueous phase gives (Li and Nghiem 1986): fi , w  wi , w Hi , w iw

(A.1)

where wi , w is mole fraction of component i in aqueous (water) phase, the bold subscript w denotes the water component and the regular subscript w denotes the aqueous phase. H i , w is the Henry’s law constant of component i in the aqueous phase. The variation of Henry’s law constant with respect to pressure and temperature follows the differential equation: V h  h (A.2) d (ln H i , w )  i , w dp  i ,v 2 i , w dT RT RT where Vi ,w is the partial molar volume of component i in the aqueous phase at infinite dilution, hi , v is the enthalpy of component i in gas phase, and hi, w is the enthalpy of component i in the aqueous phase at infinite dilution. The term hi ,v  hi, w depends strongly on temperature, and no general correlation describing its change with respect to temperature is available. It has also been found that Vi ,w is usually not very sensitive to pressure. Therefore, for a given temperature T , integration of Eq.

15

(A.2) from p 0 to p gives: ln H i , w  ln H i*, w 

Vi ,w p RT

(A.3)

where ln H i*, w  ln H i0, w 

Vi ,w p 0 RT

(A.4)

Eq. (A.1) and (A.3) gives:

 f  V p ln  i , w   ln H i*, w  i , w (A.5) w  RT  i,w  Eqs. (A.6) and (A.7) below are empirical correlation of H i*, w and Vi ,w for CO2/H2O system (Enick and Klara 1990): * HCO  5032.99  30.74113T  0.052667T 2  2.630218 105 T 3 2 ,w

(A.6)

 vCO  1799.36  17.8218T  0.0659297T 2  1.05786  104 T 3  6.200275108 T 4 2 ,w

(A.7)

*  where H CO is in MPa, vCO is in cc/mole, and T is in K. 2 ,w 2 ,w

For a given pressure p , once fugacity of CO2 in aqueous phase, which is equal to fugacity of CO2 in liquid and vapor phases ( fCO2 , w  fCO2 ,v  fCO2 , L ), is determine using EOS, Eq. (A.5) can be rearranged as Eq. (A.8) to calculate the mole fraction of CO2 in aqueous phase, wCO2 , w .   VCO p  * 2 ,w wCO2 , w  exp ln fCO2 , w  ln H CO   2 ,w RT   In Eq. (A.8), fugacity of CO2 can be calculated from Peng Robinson EOS using Eq. (A.9).

(A.8)

A Z  B (1  2 ) f ln (A.9)   Z  1  ln( Z  B)   p 2 2 B Z  B (1  2 ) Solubility of CO2 in aqueous phase in molar basis, wCO2 , w , can be converted to weight or mass fraction basis solubility, ln( )  ln 

M CO2 , w , as follows: M CO2 , w 

wCO2 , w /18 [(1  wCO2 , w ) / 44]  ( wCO2 , w /18)

(A.10)

Eq. (A.10) is derived from Eq. (A.11): wCO2 , w 

M CO2 , w / MWCO2 ( M CO2 , w / MWCO2 ) + [(1-M CO2 , w ) / MWw ]

(A.11)

where MWCO2  44 [lb/lb-mole or gm/gm-mole] and MWw  18 [lb/lb-mole or gm/gm-mole] . Eq. (A.12) is required to calculate the solubility of CO2 in aqueous reduction due to total dissolved solids (TDS) in brine using the following equation (Enick and Klara 1990): (A.12) M CO2 ,b  M CO2 , w  1.0  4.893414 102 CTDS  1.302838 103 (CTDS )2  1.871199  105 (CTDS )3  where M CO2 , w is solubility of CO2 in fresh water, and M CO2 ,b is solubility of CO2 in brine of total dissolved solids weight percent concentration CTDS . Both M CO2 ,b and M CO2 , w are on weight (mass) basis. The mole fraction basis solubility value, wCO2 ,b , can be back calculated as follows: wCO2 ,b 

M CO2 ,b / MWCO2 ( M CO2 ,b / MWCO2 ) + [(1-M CO2 ,b ) / MWb ]

(A.13)

where MWCO2  44 lb/lb-mole , and the molecular weight of brine, MWb , as a function of TDS weight percentage, CTDS , is calculated as follows:

16

MWb  MW( water  NaCl ) 

1051.2 58.4  0.404CTDS

(A.14)

Appendix B: CO2 – Brine IFT model Analysis of experimental data of Bennion and Bachu (2008) show that IFT between CO 2 and brine directly related with temperature and salinity, whereas inversely related with pressure and CO 2 solubility in brine (Fig. B.1). Note that, the direct relationship of brine-CO2 IFT and salinity implies that, IFT reduction is possible by reducing the brine salinity, hence this effect can have a favorable implication for improved oil recovery in the EOR process. Taking in to account the relationship of CO2–brine IFT with temperature, pressure, salinity and solubility, we developed a new correlation of CO2–brine IFT. Eq. B.1 is the correlation developed in this study using the 163 CO2-brine IFT data from Bennion and Bachu (2008) and mole of CO2 solubilized at in-situ conditions calculated as in Appendix A. Bennion and Bachu’s IFT experimental data encompasses wide range of salinity and reservoir conditions: 0 ppm to 334,008 ppm brine salinity, at 100 oF to 257 oF, and 290 psi to 4,000 psi. By analyzing the plot of ln( IFT ) vs. ln(T / ( p wCO2 ,b )) of all the 163 Bennion and Bachu’s experimental data (Fig. B.2), a clear change in slope was noticed at ln(T / ( p wCO2 ,b ))  4.5 , hence, the correlation developed here accounts this observation. 0.2369   T   T 22.178  ; if ln    pw  CO , b  p wCO ,b      0.0576  T   T  47.7128 ; if ln     pw CO , b  p wCO , b    2

IFTco2 brine

2

2

2

   4.5  (B.1)

   4.5 

where IFTco2 brine is in dynes/cm, wCO2 ,b is mole fraction of CO2 in aqueous phase of corresponding salinity at in-situ condition of T in oF, and P in psi. Note that the salinity effect on IFT is accounted in the solubility calculation. In addition of better accuracy, the salient feature of this correlation is, it can be easily integrated in compositional reservoir simulators since it is based on in-situ CO2 mole solubility. IFTco2 brine calculated from the correlation (Eq. B.1) agrees with the Bennion and Bachu’s experimental data very well as shown in Fig. B.3. The mean absolute percentage error of the correlation is 4.9%. Fig. B.4 shows an example of IFTco2 brine calculated using Eq. B.1 for a CO2 and synthetic oil mixture with the following mole fractions [CO2 =0.5, C1=0.1, C2=0.1, n-C4=0.1, C10=0.1, C20=0.1] and a brine of varying salinity (from 0 ppm to 100,000 ppm TDS) at a reservoir temperature of 195 oF. This figure show that the brine-CO2 IFT decreases with decrease in salinity of the brine which is caused due to increase in CO2 solubility as discussed in Appendix A. Highlights  By combining low-salinity waterflood EOR and gas injection EOR, a new EOR process is proposed. The proposed EOR process is low-salinity water-alternate-gas/CO2 (LS-WACO2 or LS-WAG) injection.  Coreflood in carbonate reservoir core and sandstone core were performed.  Contact angle, Interfacial Tension (IFT), and minimum miscibility pressure (MMP) measurements were performed on carbonate, sandstone, and shale reservoirs.  Thermodynamic modeling indicated that CO2-brine IFT decreases with decreasing brine salinity.  Improved wettability alteration towards hydrophilic and IFT reduction are among the possible mechanisms by which LS-WACO2 or LS-WAG EOR mobilizes additional residual oil.

1

Figures: 0.03

Solubility of CO2 with water or brine, mole fraction

Temperature = 160 oF

0.025

0.02

0.015

0.01 with water, Li and Nghiem (1986) with water, Enick and Klara (1990)

0.005

with 100,000 ppm brine, Li and Nghiem (1986) with 100,000 ppm brine, Enick and Klara (1990)

0 0

1000

2000

3000 4000 5000 6000 Pressure, psia o Fig. 1 – CO2 solubility in fresh and 100,000 ppm salinity brine at 160 F, using Enick & Klara and Li & Nghiem models.

Fig. 2 – Petrography of geologic facies A, B, and C of cores used in the experiments (Jobe, 2013).

2

Separator ∆P

GFM GAS

Reservoir Temperature

OIL

Core Inside Core Holder

BPR G A S

O I L

W A T E R

WATER

Graduated Tube Confining Pressure Pressure Gauge High Pressure Pump

Fraction Collector

BPR = Back Pressure Regulator GFM = Gas Flow Meter

Fig. 3 – Schematic diagram of a three phase core flooding experiment setup. During seawater or low-salinity water flooding, the production fluids are collected in fraction collector. For the case of gas flooding, the separator is used to collect the production fluid; and the produced gas is measured using the gas flow meter (GFM); and the oil /water are collected in a graduated tube and centrifuged and measured.

Θ

Formation Brine

SW

LS2

LS3

LS1

Deionized water

3

Fig. 4 – Contact angle (CA) between cleaned un-aged carbonate discs and oil-droplets in variable brine salinity.

Fig. 5 – Contact angle between cleaned un-aged Berea sandstone discs and oil-droplets in variable brine salinity.

4

Fig. 6 – Contact angle between cleaned un-aged Three Forks discs and oil-droplets in variable brine salinity.

Fig. 7 – Contact angle between crude-aged carbonate discs and oil-droplets in variable salinity brine.

5

Fig. 8 – Contact angle between crude-aged Berea sandstone discs and oil-droplets in variable brine salinity.

Fig. 9 – Contact angle between crude-aged Three Forks discs and oil-droplets in variable brine salinity.

6

Measurement conditions

Carbonate

Berea sandstone

Three Forks

Water wetness increases

A

B

C D

Fig. 10 – Pictures of the carbonate, Berea sandstone, and Three Forks discs used for contact angle measurement at measurement conditions A, B, C and D. Note that measurement conditions A, B and C are performed on the same discs whereas D is performed on adjacent discs (scale: 0.5 cm by 0.5 cm square paper).

7

Contact angle, degrees

180 Carbonate Berea Sandstone Three Forks Shale

150 120 90 60

30 0 A

B C Measurement conditions

D

Fig. 11 – Contact angle between carbonate / sandstone / Three Forks discs and oil-droplets at measurement conditions A, B, C and D.

8

Fig. 12 – Contact angle between carbonate / sandstone / Three Forks discs and oil-droplet at measurement conditions A, B, and C. The first, second, and third row corresponds to carbonate, Berea sandstone, and The Three Forks core disc cases respectively. And the first, second, and third columns correspond to measurement condition A, B, and C respectively. The volume of oil droplets range from 4 to 15 µ liters.

9

1

250

LS1

WF

0.9

LS2

CO2

LS3

0.8

200

RF

0.6

150

0.5 0.4

100

∆P, psi

0.7

0.3 0.2

50 RF ∆P (psi)

0.1 0

0 0

5

10

15

20

25

30

35

40

PV inj Fig. 13 – Oil recovery factor and pressure difference across core vs pore volume injected in experiment 1. 1

80

WF

0.9

LS1

LS2

LS3

CO2

70

0.8 60 0.7

RF

0.5

40

0.4

∆P, psi

50

0.6

30

0.3 20

RF

0.2

∆P (psi) 10

0.1 0

0

0

5

10

15

20

25

30

35

PV inj Fig. 14 – Oil recovery factor and pressure difference across core vs pore volume injected in experiment 2.

10

1.0

60

WF

0.9

LS1

CO2 50

0.8

0.7

RF

0.5

30

0.4

∆P, psi

40

0.6

20

0.3

0.2

RF ∆P (psi)

0.1

10

0.0

0 0

2

4

6

8

10

12

14

16

PV inj Fig. 15 – Oil recovery factor and pressure difference across core vs pore volume injected in experiment 3.

Fig. B.1 – Variable salinity brine-CO2 IFT – (a) and (b) direct relationship with temperature and salinity, (c) and (d) inverse relationship with pressure and solubility. Analysis was done on experimental data from Bennion and Bachu (2008), except the CO2 solubility in brine (in mole fraction) was calculated as discussed in Appendix A.

11

Fig. B.2 – ln( IFT ) vs. ln(T / ( p wCO2 ,b )) plot analyzed in development of the correlation. 80 70

Calculated IFT, dynes/cm

60 50

40 30 20 10 0

0

10

20

30 40 50 60 Experimental IFT, dynes/cm

70

80

Fig. B.3 – Comparison of calculated and experimental CO2-brine IFT.

12

32 Fresh water 25,000 ppm 50,000 ppm 100,000 ppm

31

29 28 27

2

Brine-CO IFT, dynes/cm

30

26 25 24 23 22 500

1000

1500

2000 2500 Pressure, psi

3000

3500

4000

Fig. B.4 – Brine-CO2 IFT at variable salinity and pressure for the CO2 and synthetic oil mixture [CO2 =0.5, o C1=0.1, C2=0.1, n-C4=0.1, C10=0.1, C20=0.1] at T=195 F calculated using Eq. 3.1.

13

Tables: Table 1 – Crude oil composition

Components

Mole %

CO2

1.05

N2

0.00

C1

13.78

C2

5.46

C3

6.58

C4*

5.72

C5*

5.27

C9*

33.63

C21*

21.94

C47*

6.57

* Lumped components

Table 2 – Composition of the synthetic seawater and low-salinity water

Brine

Compound (in 1000 ppm) Na2SO4

CaCl2

MgCl2

NaCl

TDS

SW

4.891

1.915

13.55

30.99

51.346

LS1

2.446

0.958

6.775

15.5

25.679

LS2

1.223

0.479

3.388

7.75

12.84

LS3

0.098

0.038

0.271

0.62

1.027

Table 3 – Filtered Reservoir I Formation Brine ionic composition used in the experiment

Na+

Ionic concentration, ppm 32,439.52

Ca2+

6,118.10

Mg2+

1,229.72

Ions

+

429.98

2+

661.61

K

Cations

Sr

Ba

2+

2+

Fe or Fe

1.36 3+

0.95

-

Cl Anions

65,202.00

2-

SO4 2-

CO3 or HCO3

869.56 -

Total Dissolved Solids (TDS)

61 107,013.80

14

Table 4 – Rock properties and description of the core flood experiments

Exp. #

Core Type

1

Facies A, Carbonate core (composite core)

2

Facies A, Carbonate core (composite core)

3

Low permeability Sandstone core, (short core)

L in. 1.88 1.82 1.896 1.7 1.88 1.881

1.903

D in.

PV cm3

1.5

29.98

1.5

34.864

1.5

5.88

ф % 26.9 21.1 14.5 18.23 21.35 26.95

kair* (mD) 3.38 1.16 0.76 1.49 7.04 3.81

kbrine (mD)

12

0.634

0.55

Miscible CO2 flooding following seawater and lowsalinity water floooding (LS1, LS2 and LS3) on composite carbonate cores. Eight weeks of aging applied. Immiscible CO2 flooding following seawater and lowsalinity water floooding (LS1) on low permeability sandstone core. Two weeks of aging applied.

3.38

1.49

* kair is air permeability corrected for gas slippage (Klinkenberg effect).

Table 5 – MMP of the reservoir oil with different injection gas scenarios

Gas injection cases

MMP, psia

100 % CO2

2,470

100% NGLs

830

50 % CO2 and 50% NGL

1,615

100 % N2

14,000

50 % N2 and 50% NGL

4,860

20 % N2 and 80% NGL

1,400

[0.61 C2, 0.22 C3, 0.095 C4, 0.065 C5 and 0.01 C6] is the composition of NGL (natural gas liquids) used in this numerical MMP determination.

Table 6 – IFT between oil and brine, pH of the brine

Brine

IFT between oil and brine, dynes/cm

pH

~107,000

8.26

7.17

SW

51,346

16.62

6.60

LS1

25,679

18.85

6.53

LS2

12,840

20.75

6.31

LS3

1,027

21.93

6.00

~0

22.09

7.06

Name

Salinity, ppm

Formation Brine (FB) Synthetic brine

Deionized water (DI)

Description of EOR flooding experiment

15

Table 7 – IFT between oil and brine, pH of the brine

Brine

IFT between oil and brine, dynes/cm

pH

SW

16.62

6.60

SW+CO2 mixture *

11.96

5.50

LS1

18.85

6.53

12.34

5.29

LS1+CO2 mixture

*

*

at atmospheric conditions (brine mixtures used in contact angle measurement conditions B and C).

Table 8 – Contact angle between cleaned un-aged carbonate / Berea sandstone / Three Forks core discs and oil-droplet in variable brine salinity

Brine

Name Formation Brine (FB) Synthetic brine

Carbonate Salinity, ppm

Contact Angle, Θ, in degrees

Berea Sandstone

Volume of oil droplets, µl

Three Forks

Contact Angle, Θ, in degrees

Volume of oil droplets, µl

Contact Angle, Θ, in degrees

Volume of oil droplets, µl

~107,000

33.3

6.50

6.3

10

33.8

7.5

SW

51,346

21.0

10.66

20.4

15

27.0

7.0

LS1

25,679

17.1

10.38

18.9

15

26.5

6.5

LS2

12,840

14.8

13.17

12.0

15

15.0

10.0

LS3

1,027

11.1

5.40

12.9

12

13.7

10.0

~0

6.7

10.10

10.2

15

13.1

14.0

Deionized water (DI)

Table 9 – Contact angle between crude-aged carbonate / sandstone / Three Forks core discs and oil-droplet in variable brine salinity

Brine

Carbonate

Berea Sandstone

Three Forks

Name

Salinity, ppm

Contact Angle, Θ, in degrees

Volume of oil droplets, µl

Contact Angle, Θ, in degrees

Volume of oil droplets, µl

Contact Angle, Θ, in degrees

Volume of oil droplets, µl

Formation Brine (FB)

~107,000

110.9

4.2

126.1

4

57.4

4.5

SW

51,346

133.6

3.19

94.6

4

116.6

6.0

LS1

25,679

127.0

3.6

89.3

3

114.6

6.0

LS2

12,840

117.0

4.91

84.9

5

100.0

4.5

LS3

1,027

114.2

2.88

80.9

4

98.0

4.0

~0

110.0

1.75

53.8

4

81.3

4.0

Synthetic brine

Deionized water (DI)

16

Table 10 – Contact angle between carbonate / sandstone / Three Forks discs and oil-droplets at measurement conditions A, B, C and D

Contact Angle, Θ, in degrees Contact angle measurement condition

Carbonate

Berea Sandstone

Three Forks

A

133.6

94.6

116.6

B

36.1

60.0

40.8

C

31.2

46.5

36.6

D

21.0

20.4

27.0

Table 11 – Effluent ionic analysis after approximately 3 pore volume injection of SW, LS1, and LS2 for coreflood experiment 1 in comparison with the filtered formation brine and synthetic seawater ions

Filtered Formation Brine (ppm)

Ions

SW (ppm)

LS1 (ppm)

LS2 (ppm)

Na+

32,439.52

16,676.08

16,917.07

9,157.64

3,181.36

2+

6,118.10

671.98

1,036.13

566.47

273.47

2+

Mg

1,229.72

1,764.94

1,822.42

995.17

389.27

+

429.98

0.00

4.26

0.00

0.00

2+

661.61

0.00

27.93

5.06

1.33

1.36

0.00

0.00

0.00

0.00

0.95

0.00

1.03

1.07

1.15

65,202.00

29,249.06

31,570.00

16,411.93

6,063.47

SO4

869.56

2,983.95

3,272.87

1,770.87

759.44

CO32- or HCO3-

61.00

0.00

391.86

449.91

507.97

107,013.80

51,346.00

55,043.57

29,358.12

11,177.45

Ca K

Cations

Sr

Ba

2+

2+

Fe or Fe

3+

-

Cl Anions

Synthetic Seawater (ppm)

Effluent Sample Ionic Concentrations

2-

Total Dissolved Solids (TDS)