1.1. Background

Before the year of 2000, many research works on experimental and modeling study on WAG injection method for understanding the different parameters associated with the flood have been found in the literature but there are very few research works on CEWAG injection methods (Heller et al., 1983, Huang and Holm, 1988, Attanucci et al., 1993, Christensen et al., 1998). WAG injection is one of the successful EOR methods which involves three-phase fluid flow. The first reported WAG in 1957 in the North Pembina field, Canada produced successful results over separated injection methods by controlling the relative permeability, preventing early fingering and adjusting the mobility (Reza et al., 2016). This method was primarily proposed to improve the sweep efficiency of gas flooding by alternate injection of water to control the mobility ratio and to stabilize the front (Christensen et al., 1998). Simultaneously, different alternatives have been proposed to improve the efficiency of gas flooding by controlling the gas mobility like foam flooding (Patzek, 1996, Renkema and Rossen, 2007) and use of CO2 thickener (Heller et al., 1983, Salehi et al., 2013a, Salehi et al., 2013b). In spite of satisfying results of thickeners, conventional WAG techniques have gained advantages over injection of gas thickener to control gas mobility because of high operational cost associated with gas injection coupled with thickener process (Heller et al., 1983). In view of these advantages, it has become widespread in different points of the world, such as the US, Canada, North Sea, Russia, Turkey and Venezuela, particularly in the past two decades. The major part of the fields are located in Canada, USA and in the former USSR where the WAG process has been applied since the early 1960's (Christensen et al., 1998).

Chemical flooding techniques are one of the most efficacious EOR methods in depleted reservoirs even at low pressure. In 1992, Tsau and Heller (1992) have taken an attempt to improve the mobility of the gas in the presence of surfactant solution. They reported that, surfactant not only control the mobility of the gas, but also can act to correct the non-uniform flow problem. Despite of the advantages of surfactant flooding in EOR, surfactants alternating gas injection (SAG) have been used in the early of 20th century (Salehi et al., 2014, Skauge et al., 2002). SAG injection technique has gained advantages over WAG injection technique in various aspects and nowadays, successfully implemented in numerous fields to recover crude oil where it is less accessible (Salehi et al., 2014, Afsharpoor et al., 2010, Srivastava et al., 2011, Nangacovié, 2012). Apart from the several study on WAG, these are not applicably relevant enough to the current understanding of CEWAG injection method for their assessment especially for heterogeneous reservoir and where the crude oil was less accessible as well as less efficient to recover. Several research works on CEWAG like SAG, PAG, NWAG, ASPWAG etc. regarding experimental as well as modeling and simulation are available after 2000 (Skauge et al., 2002, Afsharpoor et al., 2010, Lane et al., 2013, Li et al., 2014).

However, recent studies show that most of the fields could not reach the expected recovery factor from the WAG/SAG process, especially for reservoirs with high-permeability zones or fractured zones (naturally) (Christensen et al., 2001, Li et al., 2014). This has resulted issues like the early breakthrough and gravity override. To overcome these issues, the new techniques named ‘polymer alternating gas’ (PAG) injection was proposed in the last decade. Zhang and Huang (2008) conducted a test for improving heavy oil recovery by coupling CO2 and polymer injection. They found very interesting thing that the coupled process consumed three times less CO2 than the CO2 WAG run to recover more oil. Several research studies have been done on PAG (Salehi et al., 2014, Zhang et al., 2010a, Zhang et al., 2010b, Li and Schechter, 2014, Kong et al., 2015). Majidaie et al. (2012) have carried out the similar study in presence of polymer for light oil and further expected that ASP slug would considerably improve the oil recovery which have been extensively experienced in mutually pilot and field operations aiming to the optimum chemistry for minimum cost (Li et al., 2014).

Apart from the use of polymer along with WAG, an improved study (both experimental as well as numerical) was carried out by Majidaie et al. (2015)who showed that the use of the chemically enhanced water alternating gas injection (CEWAG) could further improve the efficiency of the flood. They used ASP slug instead of water, followed by CO2 in alternate manner which resulted incremental oil recovery more than twice in comparison to WAG and also provides an ultralow IFT system to minimize the water blocking effect (Farad et al., 2016). Dang et al. (2014) have worked on CEWAG with novelty and presented a comprehensive evaluation of ‘Low Salinity Water Alternating Gas’ (LSWAG) from a one-dimensional heterogeneous model into a full field simulation. It shows that CO2 LSWAG is an auspicious technique to improve oil recovery factor which not only combines the advantages of gas and low salinity water floods, but also indorses the synergism between these processes by geochemical interactions associated with CO2 injection, wettability alteration, IFT reduction and ion exchange capacity. Most of the works were undertaken in the last 5–10 years on design of suitable chemicals and their applicability in several reservoir conditions along with design of different reservoir parameters like injection ratio, slug size, life cycles, tapering, well pattern etc. (Darvishnezhad et al., 2010, Bhatia et al., 2011, Al Matroushi et al., 2015). The success of these study have shown their potential in numerous fields in last 5 years in different aspects (Ocampo et al., 2013, Al Matroushi et al., 2015, Li et al., 2014). In recent years, many companies and universities are working on the similar projects for better understanding and improvement of the process. Though individual works on WAG, SAG, PAG, LSWAG have been reported elsewhere, there is no comprehensive review article on CEWAG injection techniques for enhanced oil recovery. Thus an attempt has been taken to review the progress and application of CEWAG process, which will definitely be helpful for better understanding of the process.

1.2. Principles of enhanced oil recovery (EOR)

Oil recovery depends on the extents of fluid content within the reservoir rocks, their transmissibility through the rocks, and other related properties. Understanding of the physical properties of the rock and the formation fluids (gas, oil and water) is essential to evaluate the performance of a given reservoir and the distribution of hydrocarbons within the reservoir. Due to the presence of the multiphase system inside the reservoir, there exists a discontinuity in pressure between the two fluids which depends upon the curvature of the separating interface. This differential pressure across the interfaces results capillary pressure. Even if all the oil trapped in the reservoir are well contacted with the injected water during water flooding, still some oil remains in the reservoir due to the high interfacial tension (IFT) between water and oil or by high capillary forces. This entrapped oil can be swept-out by injecting displacing fluid having optimum surface and interfacial properties to dominate over the high IFT and capillary. This capillary pressure points the choice of oil recovery technique(s) and displacement mechanisms like imbibition and drainage.

The ultimate goal of EOR processes is to increase the overall oil displacement efficiency, which is a function of microscopic and macroscopic efficiency. The microscopic efficiency significantly depends on the relative permeability, interfacial tension, wettability, liquid viscosity and capillary pressure. Summarily, microscopic efficiency can be increased by reducing IFT of the displacing fluid and oil and capillary forces or by reducing the oil viscosity. Similarly the macroscopic or volumetric sweep efficiency depends on the injection well pattern, fractures in the reservoir, position of gas-oil and oil-water contacts, reservoir thickness, heterogeneity, mobility ratio, density difference between the displacing and the displaced fluid, and flow rate etc.

The two major dominating factors responsible in flooding process are capillary number and mobility ratio, which act simultaneously inside the reservoir during the oil recovery. The overall displacement efficiency of any oil recovery displacement process can be increased either by increasing the capillary number or by decreasing the mobility ratio or both, which are the focal points of most recovery methods (Ding and Kantzas, 2007).

2.1. Role of chemicals in CEWAG

Instead of only water in WAG, chemically enhanced water is composed of different types of chemicals as per the requirement such as surfactants, co-surfactants, polymers, alkalis, salts, nanoparticles, etc. All these different chemicals have different and particular properties which are used in EOR either separately or in combinations to improve the efficiency of the flood or oil recovery.

Surfactants have been considered as good enhanced oil recovery agents since the 1970s because it can significantly reduce the interfacial tensions (IFT) and alter wetting properties of reservoir rocks, lowers the capillary forces, facilitates oil mobilization, and enhances oil recovery (Kumar and Mandal, 2016, Kumar et al., 2016). In general IFT between oil and water varies typically in the range from 30 to 60 mN/m. Addition of surfactants to the immiscible system can decrease the IFT value significantly to an ultra-low value of 10−3 to 10−4 mN/m and the oil can be mobilized. This decrease in interfacial tension allows spontaneous emulsification and displacement of the oil (Bera and Mandal, 2015). When IFT is reduced to ultra-low value then the oil ganglia is deformed and it passes through the pore throat easily (Mandal, 2015, Samanta et al., 2011, Samanta et al., 2012, Zhang et al., 2004, Rosen et al., 2005).

It is recognized that use of polymer reduces relative permeability as well as increases the viscosity of the displacing fluid, allowing higher oil recovery (Wang et al., 2015). The objective of polymer flooding as a mobility controlagent is to provide better displacement and volumetric sweep efficiencies (Wang et al., 2015). Many factors and parameters could affect the efficiency of a polymer flooding process is the characteristics of the polymer solution itself, or could be related to the technical, economical and reservoir conditions. The parameters that affect the characteristics of polymer solution and its physio-chemical behavior include polymer molecular weight, concentration, degree of hydrolysis and viscoelastic properties of the polymer solution, salinity and pH of the make-up brine solution. The mechanisms of polymer flooding which lead to improved volumetric sweep efficiency over water flooding are outlined by Needham and Doe (1987).

As alkaline solution is injected into the reservoir, alkali reacts with long chain of carboxylic acids contained in the crude oil to form natural soap and surfactant which enables several benefits that include promoting crude oil emulsification, lowering interfacial tension (IFT) to ultra-low value, increasing ionic strength of aqueous phase leading to regulation of phase behavior of injected surfactant and strong wettability alteration including reduced surfactant adsorption, and balance the surfactant adsorption (Samanta et al., 2012). Alkaline flooding can be modified as AP (alkali-polymer), AS (alkali-surfactant), and ASP (alkali-surfactant-polymer) process as per the requirement. Alkaline-Surfactant-Polymer (ASP) flooding has been recognized to be one of the foremost EOR methods that can be effectively used for reservoir having light and medium oils (Olajire, 2014). The success of this method depends on the identification of the suitable alkali, surfactant, and polymer and their individual concentration in the ASP slug that results better surface and interfacial properties, good crude oil emulsification/mobilization, low chemical losses and good mobility control. Nasr-El-Din et al. (1992) have reported the different mechanisms of ASP flooding which are responsible for increased oil recovery.

2.2. Role of gas in CEWAG

Gas flooding is one of the preferred EOR methods for producing oil from matured fields because of its better microscopic sweep through the fine pores of the reservoir compared to water flood (Farajzadeh et al., 2012). The mechanisms responsible for the oil displacement by gas injection include oil swelling, viscosity reduction and IFT reduction at oil-gas interface as well as increasing the injectivity index due to the solubility of gas in water (Orr et al., 1982, Jarrell et al., 2002). Displacement efficiency associated with the gas flooding is also affected by wetting properties of the reservoir rock, injection and production rates, the density difference between the oil and gas, the viscosity ratio of fluids, and oil/gas relative permeabilities (Rojas et al., 1991). The use of CO2 for EOR is considered one of the most promising methods for commercial application. Almost pure CO2 has the ability of mixing with the oil properly, which results in oil swelling, viscosity reduction of the crude oil which further helps to detach the oil blob from the pores and providing the ease of oil mobilization (Van-Gool and Currie, 2008). The details of these mechanism which could be used to predict fluid transport properties have been studied by Bennion and Thomas (1993). They have also tried to correlate the experimental data using some numerical regression correlations for viscosity, density, solubility and swelling as a function of API gravity, CO2 saturation pressure and temperature. Along with these mechanism, subsequent reaction of carbonic acid with the minerals also affects the displacement of oil by CO2. Rather than WAG process, in CEWAG processes the dissolution of chemicals in CO2 plays an important role to improve their physiochemical properties like solubility and viscosity especially in presence of surfactant.

Similar to CO2 injection, N2, hydrocarbon gas, acid gas, air, LPG, natural gas injection projects in both onshore and offshore reservoirs have made a relatively marginal contribution in terms of total oil recovered. Nitrogen gas with low solubility in water prevents the trapped gas saturation from changing significantly during these good injectivity even in low permeability reservoirand environment friendly (Alagorni et al., 2015). Hydrocarbon gases are also used in miscible gas injection or in WAG process. Hydrocarbon gas is usually readily available from the field itself and compatible to the reservoir rock and fluids (Muggeridge et al., 2006). Depending on the API gravity of the trapped crude oil, produced natural gas may be enriched with intermediate hydrocarbon to make it miscible with the oil (Alvarado and Manrique, 2010).

3.1. Water alternating gas injection (WAG)

The Water Alternating Gas (WAG) injection techniques is nothing but the alternate injection gas followed by the water for some period of time or several cycles as needed. An extensive literature review of WAG field applications found in the literature was done by Christensen et al. (2001). They reviewed a lot of WAG field cases on the basis of their reservoir properties (heterogeneity, fractured and wettability etc.), oil type (heavier or lighter) and miscible or immiscible conditions. In the WAG process the gas is a responsible candidate for improving the microscopic displacement, whereas; water for macroscopic sweep. Moreover, compositional exchange between the gas and the oil may further improve the oil recovery efficiencies (horizontal and vertical sweep). The horizontal sweep efficiency depends on the stability of the displacement front which is defined by the mobility ratio. The vertical sweep efficiency is important when there is gravity segregation of the fluids during WAG. Generally, gas tends to sweep the oil present in the upper part of the reservoir owing to gravitational forces, whereas; water tends to sweep the lower part. Another mechanism of recovery is the reduction in interfacial tension (IFT). The fact that gas-oil IFT is lower than water-oil IFT enables the gas to dispel more oil from the pore spaces that may not be accessible by the water. This improves the microscopic displacement efficiency. Ramachandran et al. (2010) investigated the laboratory study on hydrocarbon WAG in a western Indian onshore field. Due to the presence of natural gas in deep reservoirs of the field, they also have carried out the field study to demonstrate the potential of WAG. Various critical parameters were examined or evaluated using laboratory and simulation study on WAG injection. They mentioned that the WAG results an additional oil recovery of 14.5% over the water flood. The effectiveness of WAG injection may be improved further, according to the injection approach, which includes: SWAG (simultaneous), HWAG (hybrid), SSWAG (selective), MWAG (miscible) and IWAG (immiscible) (Christensen et al., 1998, Foroozanfar and Aminshahidy, 2013). Christensen et al. (1998) have also reported the feasibility of another type of WAG, ‘simultaneous water alternating gas injection’ (SWAG) method along with the field application and a brief comparission with WAG. In this process either water and gas are mixed at the surface or Gas and water are injected together through a single well bore. Stephenson et al. (1993) have compared two projects, a standard WAG and a SWAG. They concluded that the SWAG gave the best recovery. Recently the optimization of the SWAG process and the efficiency comparission with WAG rpocess have been reported by Kamali et al. (2017). The GOR during the SWAG injection is generally more stable due to no such alteration of water and gas like during WAG injection. Whereas injection of gas and water are carried out separately (without mixing) using dual completion injector then the process is referred to as selective simultaneous water alternating gas (SSWAG). Injection of a large slug of gas prior to the injection of a number of alternate small slugs of water and gas is preferred to as hybrid WAG (HWAG).

3.2. Surfactant alternating gas injection (SAG)

The additional increase in recovery by reduction in IFT and contact angle together with foam generation arises the need of surfactants in WAG injection process and this mechanism is named as surfactant alternating gas (SAG). SAG injection is one of the methods commonly used to enhance the possibility of WAG process. Foam has the potential to relieve numerous common issues through improved sweep, less gravity overrides, less viscous fingering and entertainment of gas from high permeable (or previously swept) layers. The foam may be administrated by continuous co-injection of gas and surfactant slug or by alternate injection of surfactant slug and gas which is later known as SAG. The alternate imbibition and drainage during SAG injection generates foam in the reservoir. SAG injection has assured advantages over continuous foam injection and consequently it has grown significant attraction among researchers. Unlike foam injection, SAG injection minimizes contact between gas and water in the injection facilities which can reduce corrosion. Gravity overrides in foam mobility-control process results from the antagonism between gravity and lateral pressure gradient. Therefore, overcoming gravity override with continuous foam injection needs raising injection-well pressure, probably imperilling fracturing the formation. Foam processes employing surfactant-alternating-gas (SAG) injection at a fixed injection-well pressure, however, can overcome gravity override without excessive injection pressures(Shi and Rossen, 1998). SAG injection can thus lead to improved oil recovery due to improved microscopic displacement efficiency, mobility control, communication in un-swept zone, and oil vaporization due to mass transfer across crude oil and injected gas. Fortunately, the use of foam can reduce gas mobility and the effect of heterogeneity and therefore increase sweep efficiency. In the view of this, Renkema and Rossen (2007) have proposed an optimal design strategy and tested in a homogeneous reservoir and in two layered rectangular reservoirs (Renkema and Rossen, 2007). They also have generated a simulated results for both the homogeneous and heterogeneous reservoirs. The results demonstrated the grater oil recovery by SAG over WAG for both the homogeneous and heterogeneous reservoirs. A study was carried out to evaluate the feasibility of immiscible Surfactant-Alternate-Gas (SAG) injection at laboratory scale in the Limbodara field of Ahmedabad Asset, ONGC, Ahmedabad (Srivastava et al., 2011). It is observed that in immiscible single cycle & two cycle SAG process an incremental displacement efficiency of 27.79% & 29.01% were achieved over and above water flooding, indicating the feasibility of additional oil recovery by SAG process in areas in the field where early breakthrough of the ongoing injection water occurs. Salehi et al. (2014) carried out some experimental study to optimize the oil recovery by SAG using SDS surfactant and made an attractive appraisal with water flooding, gas flooding, and WAG flooding. As water is displaced from the near the well region during SAG injection, gas mobility rises which further increases the injectivity (Shi and Rossen, 1998, Shan and Rossen, 2002). A possible advantage of SAG over WAG in contrast to improvement in mobility is higher gas saturation (over 85%–95% gas) i.e., small amount of water is needed to decrease the gas mobility (Salehi et al., 2013a, Salehi et al., 2013b). Fig. 2 compares the oil recovery efficiency of the SAG injection techniques with WAG, water and gas flooding. This figure summarizes the effectiveness of SAG injection and results indicates that SAG recovers the maximum of oil about 87% whereas, WAG injection, water flooding, and gas flooding can able to recover only 70%, 66% and 59% oil of OOIP respectively.

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Fig. 2. Comparison of oil recovery for SAG, WAG, gas flooding and water flooding (Salehi et al., 2013a, Salehi et al., 2013b; modified).

3.3. Polymer alternating gas injection

There are a lot of doubts that need to be responded which is essential in order to optimize the process efficiency in case of heavy oil reservoir rather than the success of SAG and WAG as discussed above. The adverse viscosity ratio of gas to the heavy oils results in gravity override and gas fingering through more permeable zones. This further leads to an early gas breakthrough and ultimately hampers the oil recovery efficiency. Due to the limitation of WAG and SAG techniques to overcome the issues of gas breakthrough and gravity segregation for the production of heavy oil novel techniques have been proposed in the last few years. This new method termed as PAG that combines features of CO2flooding with polymer flooding to produce heavy oil. Coupling of polymer with CO2 is expected to improve the efficiency of the current WAG. The main feature of PAG is that polymer is injected with water in the whole WAG process. Zhang et al., 2010a, Zhang et al., 2010bconducted the polymer injection chased with gas alternative water (PGAW) experiment based on Saskatchewan's crude (heavy oil, 18.3°API). They also compared the coupled CO2 and polymer injection with the water-alternating-gas (CO2 WAG) injection and polymer alone flood. Their results demonstrated that, coupled CO2 and polymer injection gave better recovery and efficiency than WAG and polymer flooding (in Fig. 3). They also reported in their work that the gas utilization factor for all three mode of EOR process which further indicates the economic feasibility of the PGAW technique. Because of the higher gas utilization factor in WAG injection, only a small portion of the reservoir is contacted by injected CO2 gas which results in poor sweep efficiency, huge gas requirement and lower EOR recovery.

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Fig. 3. The enhanced oil recoveries and gas utilization factors in different EOR processes (Zhang et al., 2010a, Zhang et al., 2010b; modified).

The tertiary oil recovery by immiscible CO2 WAG injection was 15.3% OOIP with 6.16 MSCF/STB gas utilization. One more important outcomes of the work that lower polymer concentration is sufficient for PGAW process which further reduce the chemical cost compared to polymer flooding. A similar work have been reported by Li et al. (2014) on oil recovery of North Burbank Unit which is highly permeable and heterogeneous. They compared PAG performance with WAG and continuous gas injection (CGI) by validating the pseudo-miscible model. In view of the reservoir permeability, they compared the percentage of water injected into each zone for WAG and PAG and concluded that more water is injected into middle and lower permeability zones in PAG (40%) than in WAG (27%). An optimum polymer concentration is needed to optimize the recovery factor because of reduced water injectivity at higher polymer concentration. From Fig. 4, it can be clearly seen that, PAG has minimum and approximately constant gas-oil ratio which further results in higher oil rate than other methods. It can also be seen that, the oil rate by CGI is lower than WAG and PAG mainly due to gas breakthrough and gas override which results in lower recovery factor than others. The optimal parameters (operational) for selection of a PAG injection method have been discussed by Jamal et al. (2016) in detail using global optimization algorithms.

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Fig. 4. Recovery factor of different EOR processes (Li et al. (2014); modified).

3.4. ASP alternating gas (ASPAG) injection

The concept of ASPAG injection process is relatively novel with very little theoretical and experimental studies available. In view of this, Srivastava et al. (2009) have carried out alkali surfactant gas (ASG) injection techniques by ignoring the use of polymer because some reservoir conditions are not favorable for the use of polymers due to low permeability or other unfavorable conditions. They reported that the generated foam during ASG flooding can control the mobility which is often done by injecting polymer during ASP flooding. They also reported the high-performance chemicals, designed for both foaming and strong IFT reduction performance to improve the recovery of ASG injection techniques. Majidaie et al. (2012) have reported the importance of CEWAG on the basis of IFT reduction, mobility control, reducing water blocking effect, oil viscosity reduction due to the CO2 dissolution and oil swelling. Their work reflects the necessity of the optimization of the concentration of the surfactant, alkali, and polymer to optimize the oil recovery factor of ASP alternate gas injection. To improve the recovery efficiency of the WAG process for Saskatchewan (Canada) heavy oil reservoirs, Luo et al. (2013) have carried out a laboratory study to assess an improved WAG practise that amplifies the injection water with chemicals (alkali/surfactant/polymer) referred to as chemical-alternating-gas (CAG) injection techniques (in Fig. 5). The techniques have been referred to an integrated approach for both the IFT reduction and mobility control or combination of SAG and PAG another way. They have also carried out the phase behavior studies which indicates that CO2 could be dissolved readily into the reservoir heavy oil at moderate pressures resulting in significant oil swelling and viscosity reduction. They also have compared the effect of flue gas (70 mol% N2 + 30 mol% CO2) with CO2. However, flue gas resulted in much lower gas solubility compared to CO2, causing negligible oil swelling and viscosity reduction at the reservoir pressure (Luo et al., 2013).

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Fig. 5. Core flood recovery performance versus pore volume injected (Luo et al., 2013).

Farad et al. (2016) have carried out the similar study to see the effect of pH on ASP-gas injection process. The optimum recovery eventually was found by injection of the ASP slug with pH of 11 and slug ratio of 1:1. Recently Farad et al. (2016) have conducted the similar work to improve the effectiveness of WAG by minimizing the water blocking and gas mobility by adjusting the pH and the slug ratio of the ASP system. They found an improved additional oil recovery (15.4%) by injection of the slug which consisted of 0.1%wt polymer, 0.1% surfactant and alkaline with pH 11 and a slug ratio of 1:1. The schematic diagram of typical flooding setup for CEWAG injection technique is shown in Fig. 6.

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Fig. 6. Schematic diagram of the core flooding apparatus (Luo et al., 2013).

3.5. Miscellaneous CEWAG injection

Many oil and gas fields produce large volumes of lean gas and the reinjection of this gas leads to a loss of reserves. In view of alternative gas management solutions, Beare and Cockin (1999) have carried out an investigation on lean alternating rich horizontal gas flood scheme, using separator streams to reuse the lean gas where it is available in large volumes.

In particular, a lean alternating rich gas enhanced recovery scheme (LARGER) and a water lean alternating rich gas enhanced recovery scheme (WLARGER) were carried out as replacement of the conventional WAG techniques in such oil fields. A schematic illustrating these two schemes is shown in Fig. 7. This approach was being considered as an important aspect of offshore fields, due to the ease of separation of components than cryogenic facilities at lower cost and also requires little additional space.

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Fig. 7. Schematic of LARGER & WLARGER (Beare and Cockin, 1999).

A new approach have been developed and implemented by many researchers, ‘Carbonated water injection’ (CWI) in contrast to synergistic behavior of the CEWAG process (Foroozesh et al., 2016, Foroozesh and Jamiolahmady, 2016; Mosavat et al., 2014). CWI injection techniques have shown their potential in the field of EOR because large amounts of CO2 can be dissolved in water and later transferred to oil compared to other gases improving the oil mobility. CWI can be applied particularly in offshore reservoirs, where the supply of CO2 is limited. Compared to immiscible CO2 flooding, CWI is more beneficial recovery strategy because it eliminates the problem of mobility contrast between CO2and oil, reduces the gravity segregation and gas fingering, improves the sweep efficiency, and delays the break-through of CO2 (Mosavat et al., 2014). Zolotukhin and Ursin (2000) have reported the beneficial effect and suggested to prefer the low salinity water injection because increasing salinity causes reduction in electrical double layer so reduction in IFT will be low and hence more difficult to recover oil. In view of the success of low salinity water flooding (LSW) and carbonated water flood (CFW) (Dong et al., 2011), Dang et al. (2014)have proposed a novel and effective scheme which comprises low salinity water and CO2 injection alternatively (CO2 LSWAG) under miscible displacementconditions. The results indicate that it improves the oil recovery by wettability alteration, ion exchange process and geochemical reactions among different phases including CO2. Shu et al. (2014) have studied the effect of pre-flushing the reservoir using ‘active carbonated water’ (ACW) before a CO2 flood to improve the efficiency of conventional WAG injection process and on doing so, the oil recovery was increased by 35.5%, compared to 16.6% from injecting CO2alone. This is due to the mass transfer of CO2 from the water phase to the oil phase which improves CO2 tertiary oil recovery in the low interfacial tension displacement process. Apart from the use of conventional foam flooding; recently, alternate injection of high strength foam (HSF) and ultra-low interfacial tension foam (ULT) has been used as a novel techniques to improve the efficiency of EOR. HSF foam generates large and stable bubbles which lead to blocking of high permeability zones (Cao et al., 2015). Whereas, ULT foam generates small bubbles which reduce the oil-water IFT to ultra-low-grade. Therefore, alternate injection of these types of foam results increase in both the displacement efficiency as well as sweep efficiency. Accordingly, this method of injection has been considered a potential approach, especially in the heterogeneous reservoir. The injection order is depicted in Fig. 8 which shows that the bubble radius changes while bubble flowing from pore to throat, and to next pore. They have carried out this study for different permeability zones by simultaneous injection of the slug into the three sand-pack of different permeabilities connected in parallel. They first improve the sweep efficiency and then the displacement efficiency by reducing the difference of flow resistance between the high and low permeable areas in a heterogeneous reservoir. Results indicate that as the permeability of sand-pack increases the oil recovery increases and comparatively higher than WAG, ULT and HSF alone flooding as shown in Fig. 9. They have also suggested that the oil recovery may be improved significantly by injection of small sized slugs for a same total volume of foam with increased number of stages. Jia et al. (2015) investigated a conventional cyclic solvent injection (CSI) process for heavy oil (dead oil) that used a solvent injector as an oil producer alternately. This technique has a great potential to produce more of crude oil by combining both the solution gas driveand foamy oil flow methods.

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Fig. 8. Injection order of alternate foam flooding and flow behavior of ULT and HSF through pores (Cao et al. (2015)).

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Fig. 9. Water cut and oil recovery of each sand pack of HSF and ULT foam alternate flooding (test P-4). The foam slug was 0.125 PV HSF foam (GINF-1/air) + 0.125 PV HSF foam (LINF-2/air) + 0.125 PV HSF foam + 0.125 PV HSF foam (Cao et al. (2015)).

3.6. Miscible and immiscible injection

Based on the reservoir properties and requirements, the gas flooding can follow either miscible or immiscible to sweep the crude oil. Whether the displacement is miscible or immiscible depends upon the minimum miscibility pressure(MMP). For pressures below MMP, immiscible displacement of oil takes place. Miscible CO2 displacement is only attained under a precise combination of circumstances, which are established by four variables: reservoir pressure, reservoir temperature, injected gas composition, and crude oil chemical composition. The miscible process is best applicable to light and medium gravity crude oils, and the immiscible process, may apply to heavy oils. Kulkarni & Rao in 2005 have carried out the experimental study on WAG for both the miscible and immiscible injection of CO2 (Kulkarni and Rao, 2005). They have calculated the MMP using different empirical correlations then compared with commercial PVT simulation and conducted the immiscible floods at 3.45 MPa (500 psi) and the miscible floods at 17.24 MPa (2500 psi). A zero (or tends to zero) interfacial tension value is essential and adequate for accomplishment of miscibility which further leads to increase in capillary number and subsequently improves or attains nearly perfect microscopic displacement efficiency. Batruny & Babadagli investigated the fully miscible WAG using reservoir core investigation to eventually provide optimum application circumstances (Batruny and Babadagli, 2015). They conducted a “water alternating solvent” injection techniques using heptane as a solvent to achieve perfect miscibility. The majority of WAG injections have been classified as miscible and are mostly applied in onshore with a closed well spacing manner. Many authors have investigated the immiscible WAG (IWAG) techniques to improve the CGI and conventional water flooding (Zhang et al., 2010a, Zhang et al., 2010b, Laochamroonvorapongse et al., 2014, Salehi et al., 2013a, Salehi et al., 2013b, Dong et al., 2005). Zhang et al., 2010a, Zhang et al., 2010b have carried out the effect of coupled immiscible CO2 and polymer injection to optimize the efficiency of flood for heavy oil recovery. The superior performance of immiscible PGAW injection over WAG injection suggests an imperative mechanism for the success of an EOR method by having more favorable mobility control which greatly improves the sweep efficiency.