Review of surfactant-assisted chemical enhanced oil recovery for carbonate reservoirs: challenges and future perspectives

Sreela Pal; M. Mushtaq; Fawzi Banat; Ali Al Sumaiti

doi:10.1007/s12182-017-0198-6

Review of surfactant-assisted chemical enhanced oil recovery for carbonate reservoirs: challenges and future perspectives

Pal, Sreela; Mushtaq, M.; Banat, Fawzi; Al Sumaiti, Ali 2017-11-04 00:00:00 Pet. Sci. (2018) 15:77–102 https://doi.org/10.1007/s12182-017-0198-6 REVIEW PAPER Review of surfactant-assisted chemical enhanced oil recovery for carbonate reservoirs: challenges and future perspectives 1 2 1 2 • • • Sreela Pal M. Mushtaq Fawzi Banat Ali M. Al Sumaiti Received: 26 April 2017 / Published online: 4 November 2017 The Author(s) 2017. This article is an open access publication Abstract A signiﬁcant fraction of the conventional oil Keywords Oil reserves Original oil in place Carbonate reserves globally is in carbonate formations which contain formations Surfactants Chemical enhanced oil recovery a substantial amount of residual oil. Since primary and secondary recovery methods fail to yield above 20%–40% of original oil in place from these reserves, the need for 1 Introduction enhanced oil recovery (EOR) techniques for incremental oil recovery has become imperative. With the challenges Approximately one-third of the original oil in place (OOIP) presented by the highly heterogeneous carbonate rocks, is believed to be recovered by primary and secondary evaluation of tertiary-stage recovery techniques including recovery processes worldwide, leaving behind around chemical EOR (cEOR) has been a high priority for 60%–70% as remaining oil in reservoirs (Xu et al. 2017). researchers and oil producers. In this review, the latest Most of the current world oil production comes from developments in the surfactant-based cEOR techniques mature ﬁelds which contain a high percentage of residual applied in carbonate formations are discussed, contem- oil. Increasing oil recovery from these aging resources is plating the future direction of existing methodologies. In the primary concern for oil companies and authorities connection with this, the characteristics of heterogeneous globally. More than 50% of the world’s discovered oil carbonate reservoirs are outlined. Detailed discussion on reserves are in carbonate reservoirs, a large number of surfactant-led oil recovery mechanisms and related pro- which have a high degree of heterogeneity and complex cesses, such as wettability alteration, interfacial tension pore structures (Masalmeh et al. 2014). According to BP reduction, microemulsion phase behavior, surfactant Statistical Review of World Energy 2015, around 48% of adsorption and mitigation, and foams and their applications the world’s proved conventional oil reserves are in the is presented. Laboratory experiments, as well as ﬁeld study Middle East (BP 2015) nearly 70% of which are in frac- data obtained using several surfactants, are also included. tured carbonate reservoirs. This extensive discussion on the subject aims to help It is also noteworthy that more than 40% of the daily researchers and professionals in the ﬁeld to understand the world oil production comes from these carbonate reservoirs current situation and plan future enterprises accordingly. of the Middle East which are mostly mature and contain a high percentage of residual oil (Ahmadi and Shadizadeh 2013b). Typically, the majority of the carbonate reservoirs & Fawzi Banat is characterized by the presence of high-permeability fbanat@pi.ac.ae fractures and low-permeability matrix. This contrast in permeability makes them challenging targets for chemical Department of Chemical Engineering, Khalifa University of Science and Technology, SAN Campus, Abu Dhabi, UAE ﬂooding. Also, some of these carbonate formations have high reservoir temperatures and contain high salinity for- Department of Petroleum Engineering, Khalifa University of Science and Technology, SAN Campus, Abu Dhabi, UAE mation brine (Lu et al. 2014b). These multiple attributes coupled with their complex wettability conditions, i.e., oil- Edited by Yan-Hua Sun 123 78 Pet. Sci. (2018) 15:77–102 wet/mixed-wet surfaces, complicate reservoir characteri- undoubtedly guide future researchers and practitioners in zation, production and management (Hirasaki and Zhang the ﬁeld toward identifying newer technologies and 2003). As a result, the oil recovery factors (ORF) in these upgrading existing methodologies for successful ﬁeld reservoirs are very low, probably below 30% on an average implementation. (Hognesen et al. 2005). Implementation of chemical enhanced oil recovery (cEOR) processes is highly dependent on the oil and 2 Heterogeneity and characteristics of carbonate chemical prices, and hence, research and investment in this reservoirs ﬁeld are decidedly governed by the economy of the country. Despite these challenges, extensive laboratory Carbonate reservoirs present a picture of extremes. Most of research along with some ﬁeld demonstration projects them are highly heterogeneous regarding their geological support the fact that there lies an enormous potential for and petrophysical features that clearly distinguish them chemicals in enhancing oil recovery from carbonate for- from sandstone reservoirs. They typically possess some mations. With cEOR, targeting more and more challenging distinct characteristics, which challenge oil recovery and reservoirs, especially using surfactants is becoming a extraction. Normally, carbonate rocks have a complex reality (Lu et al. 2014a). During the last two decades, a texture and pore network, emanating from their deposi- considerable number of EOR ﬁeld projects in carbonate tional history and later diagenesis. Most of the carbonate reservoirs have been documented (Alvarado and Manrique reservoirs are naturally fractured with extremes in fracture 2010) of which the Yates ﬁeld (Texas) is a good example length varying from small ﬁssures to kilometers. These where different EOR processes were successfully trialed at fractures may signiﬁcantly inﬂuence ﬂuid movement to different levels, from pilot to large-scale applications. speciﬁc paths and hugely impact on the production per- Several variations to conventional surfactant ﬂooding formance. For example, highly fractured reservoirs can methods, such as the combined surfactant–polymer (SP) experience early water or gas breakthrough due to chan- technologies and the alkali–surfactant–polymer (ASP) neling of ﬂuids along fractures. However, fractures are ﬂoods that boost oil production, especially in the mature beneﬁcial in tight formations where matrix permeability is water-ﬂooded carbonate ﬁelds, have been the subject of signiﬁcantly low, and most of the ﬂuid movement is only much introspection lately (Kiani et al. 2011). Due to through fractures. Therefore, characterization and under- technical difﬁculties, chemical-based EOR methods have standing the behavior of ﬂuid or gas ﬂow through fractures never been very popular for signiﬁcantly enhanced oil is essential for a successful ﬁeld development. production from carbonate reservoirs. Nevertheless, sur- Most carbonate rocks are formed by biological activity, factant-based cEOR technologies have been implemented developing from the biogenic sediments gathered during as chemical well stimulators, wettability altering agents, reef building and accumulation of the remains of organisms microemulsion, and foam-generating agents consistently on the seabed. Other types originate from evaporation of (Andrianov et al. 2012; Simjoo et al. 2013; Wang and water from shallow onshore basins or as precipitates from Mohanty 2013). Currently, this is an area of intense seawater (Akbar et al. 2000). They consist of limited research (Ahmadi and Shadizadeh 2012; Bera et al. 2012; groups of minerals predominantly calcite and dolomite. Zendehboudi et al. 2013; Bourbiaux et al. 2014; Santvoort Sometimes, minerals such as glauconite and secondary and Golombok 2015). minerals including quartz, clay, pyrite, siderite, ankerite, The present review is aimed at: anhydride and chert are also less commonly present (Lucia 2007). (a) Studying the heterogeneity and characteristics of Usually carbonate rocks are differentiated by factors carbonate reservoirs, such as depositional texture, grain or pore size, rock fabric (b) Discussing the current status of the different surfac- or diagenesis following some classiﬁcation schemes put tant-based cEOR methods applied in carbonate forward by different groups of scientists (Lucia 2007; reservoirs documenting several ﬁeld EOR projects Embry and Klovan 1971). Heterogeneity may exist at all in carbonate reservoirs, levels—in pores, grains and also in textures. The porosities (c) Summarizing the evolution of various surfactant of carbonate rocks are usually classiﬁed into three cate- types for application in different carbonate reservoirs gories: (a) connected porosity—this porosity lies between over the years and, ﬁnally, carbonate grains (b) vugs—they are unconnected pores that (d) Evaluating the challenges and debating the future of arise from the dissolution of calcite by water during dia- surfactant EOR technology for these reservoirs. genesis and ﬁnally (c) fracture porosity—stresses cause Since carbonate reservoirs are at the leading area of this subsequent texture. Together these porosities create a research currently, this comprehensive review will difﬁcult path for liquid ﬂow and precisely affect well 123 Pet. Sci. (2018) 15:77–102 79 productivity. Diagenesis of carbonate rocks signiﬁcantly concentration pure surfactants (such as ethoxylated alco- modiﬁes the pore spaces and permeability (Akbar et al. hols) in injected water was also seen to improve oil 2000). recovery in oil-wet carbonate reservoirs, presumably by Apart from porosities, wettability is another heteroge- enhancing imbibition through wettability alteration and neous characteristic in carbonate rocks. Most of the car- lowering of the interfacial tension (IFT). Such simple bonate reservoirs are found to be mixed-wet or oil-wet surfactant systems were considered viable due to low sur- (Chilingar and Yen 1983). At times, strongly oil-wet car- factant concentration requirement along with associated bonate formations leave behind a high water-ﬂooded low adsorption (Yang and Wadleigh 2000; Xie et al. 2004; residual oil saturation and have unfavorable mobility ratios. Seethepalli et al. 2004). Additionally, they exhibit capillary resistance to imbibition of water (Anderson 1987). Hence, oil remains adhered to 3.1 Foams, wettability alteration and lowering the surface of the carbonate rocks, and it becomes harder to of interfacial tension by surfactants recover the entrapped residual oil. Different surfactant- based cEOR technologies targeted primarily toward car- Surfactants play a leading role in foam generation, wetta- bonate reservoirs have been tried over the last two decades. bility alteration and lowering of oil–water interfacial ten- In the following sections, we will discuss some of the well- sion (IFT) processes. practiced surfactant-based EOR ﬂooding methodologies. Foams are employed for mobility control in situations where polymers, gas or water alternating gas injection schemes are not feasible due to unfavorable conditions, 3 Surfactant ﬂooding processes for chemical EOR such as low permeability, formation heterogeneity and high in carbonate reservoirs temperature–high salinity conditions beyond the polymer stability window. Foam injection has advantages over For decades, substantial efforts have been made to use simple gas injection, and it is demonstrated that the use of surfactant injection as a post-waterﬂood process for foam can mitigate gas channeling, improve apparent gas recovering entrapped oil from conventional mature reser- density and hinder gas escape through high-permeability voirs. Designing and optimizing suitable surfactant ﬂood zones to achieve good oil recovery (Julio and Emanuel for effective cEOR has always been very challenging and 1989; Huh and Rossen 2008; Lee et al. 1991; Schramm and forever evolving. It is one of the robust and high-perfor- Wassmuth 1994). Foams are reviewed in detail in mance cEOR methods, which has been widely studied in Sect. 3.4.3. the past decades because of its ability to alter wettability of 3.1.1 Wettability alteration carbonate reservoirs from the oil/mixed-wet to the water- wet surfaces, lower interfacial tension (IFT) and produce the oil entrapped in these formations (Hill et al. 1973; Yang Wettability is long recognized as an important factor that and Wadleigh 2000; Webb et al. 2005; Farajzadeh et al. strongly affects oil recovery in naturally hydrophobic car- 2010; Barnes et al. 2012; Ahmadi and Shadizadeh 2013a). bonate reservoirs implementing cEOR methods. Wettabil- The idea of adding surfactants to injected water for ity is deﬁned as the preferential tendency of a ﬂuid to reducing oil/water IFT and/or alter wettability thereby spread onto a solid phase in the presence of other immis- increasing oil recovery from reservoirs dates back to the cible ﬂuids. Generally, for an oil/water system, wettability early 1900s (Uren and Fahmy 1927). A similar long-held can be deﬁned according to the contact angle; if the contact concept for improving oil recovery was the in situ gener- angle is 0–75, the rock is water wet; if 75–115,it is ation of surfactants by injection of an alkaline solution intermediate and with an angle of 115–180, the rock will (Howard 1927). Though this method provided a compara- be oil wet (Anderson 1986). tively cheap in situ surfactant production technology by Wettability alteration is supremely important for natu- conversion of the naphthenic acids in crude oil to soaps, rally fractured carbonate reservoirs (NFCRs), where pri- this was not immediately accepted due to poorly under- mary and secondary processes usually fail to mobilize oil stood process mechanisms (Johnson 1976). that remains locked tightly due to capillarity. Moreover, From 1960 onwards, surfactant technology advanced most of the oil in NFCRs is contained in the low-perme- signiﬁcantly based on two different approaches. The sur- ability matrix. As the viscous forces in these heterogeneous factants were either synthesized by direct sulfonation of systems are inefﬁcient to sweep matrix oil, an imbibition aromatic groups present in reﬁnery streams/crude oils or by process remains as the most reliable mechanism to reach the organic synthesis of alkyl/aryl sulfonates with the aim for the oil. of manufacturing tailored surfactants for the reservoir of Depending upon their hydrophilic head charges (an- interest (Hirasaki et al. 2008). Similarly, use of low- ionic/cationic) and the charges on the rock surfaces, 123 80 Pet. Sci. (2018) 15:77–102 surfactants may alter the wettability of reservoir surfaces. surfactant double layer cannot be regarded as a permanent There are two mechanisms of wettability alteration by wettability alteration of the calcite, because due to the surfactants cited in the literature (Standnes and Austad weak hydrophobic bond between the surfactant and the 2000b). The ﬁrst is the removal of the oil-wet layer hydrophobic surface, the process is entirely reversible. exposing the underlying originally water-wet surfaces Nonionic surfactants, for example, ethoxylate C –C 9 11 (cationic), while the second is setting up of a water-wet linear primary alcohol was also tested for its ability to layer over the oil-wet layer (anionic). For carbonates, change the wettability of dolomite surfaces using contact cationic C TAB surfactants at concentrations equal or angle with Yates crude oil (Vijapurapu and Rao 2004). The greater than the critical micelle concentration (CMC) alter advancing contact angle reduction suggested that the non- wettability better than anionic surfactants (Standnes and ionic surfactant effectively altered the strongly oil-wet Austad 2000b). However, other researchers have stated that nature (advancing angle of 156) to the water-wet state no apparent correlation exists between oil recovery and (advancing angle of 39). CMC (Wu et al. 2008). From the works of Standnes and Austad (2003), it was 3.1.2 Interfacial tension found that ion pair interaction is a possible mechanism of wettability alteration by cationic surfactant type C TAB Interfacial tension (IFT) is one of the primary considera- (where n is the number of carbon atoms). According to tions in alkali–surfactant ﬂooding cEOR processes. In oil them, the mechanism of wettability alteration was ration- reservoirs, the interplay of three types of forces, capillary, ally attributed to the formation of ion pairs between the gravitational and viscous forces, controls the extent and cationic surfactant and the negatively charged carboxylates rate of oil recovery. To best describe the relationship in oil. In addition to the electrostatic forces, hydrophobic between these forces, there are two useful numbers—the interactions were also believed to stabilize this ion pair Bond number (N , which presents the ratio of gravitational complex. The ion pairs were insoluble in the water phase forces to capillary forces) and capillary number (N , which but were found to be soluble in the oil phase or the presents the ratio of viscous forces to capillary forces) as micelles. The ion pair solubility in oil causes water to outlined below: penetrate into the pore system, with the subsequent Gravitational forces N ¼ ð1Þ expulsion of oil from the pore through connected pores Capillary force with high oil saturation in a so-called counter-current ﬂow Viscous forces mode. Hence, as the adsorbed organic material released N ¼ ð2Þ Capillary forces from the calcite surface, it became more water-wet. Anionic surfactants, in general, do not possess the 2r cos h ow c Capillary forces F ¼ ð3Þ ability to alter the wettability of calcite surfaces, even though they can achieve a very low IFT. However, Gravitional forces F ¼ Dqgh ð4Þ ethoxylated sulfonates with high numbers of ethylene where r is the oil–water interfacial tension, N/m; r is the oxide (EO) units, displaced oil spontaneously in a slow ow pore radius; and h is the contact angle. process (Standnes and Austad 2003). The proposed The denominator in both of these numbers is the cap- mechanism in this case probably involves the formation of illary force, which is a function of the IFT between oil and a water-wet bilayer between the oil and the hydrophobic water, surface wettability represented by the contact angle calcite surface. An anionic surfactant with a large (h ) and the pore radius (r). Viscous forces cannot be hydrophobic group such as ethoxylated sulfonates of the c applied efﬁciently for heterogeneous oil-wet NFCRs due to type R-(EO) -SO (x = 3–15) supposedly adsorbed onto x 3 the hydrophobic calcite surface forming a double layer and a high-pore-volume matrix which possesses low perme- ability and a much lower volume fracture system that creating a hydrophilic surface. The water-soluble head group of the surfactant EO-group and the anionic sulfonate controls the ﬂow of viscous displacement. Fluid dynamics in this type of reservoir is controlled by the Bond number could decrease the contact angle below 90, forming a (N ). Depending upon the contact angle (h ) (wettability of small water layer between the oil and the organic coated B c rock), the value of the capillary forces may be reversed surface. As a result, weak capillary forces were created, from negative to positive ﬁgures. For oil-wet cores, the and some spontaneous imbibition of water could occur. contact angle of water with rock being greater than 115, From their experiments, Austad and Standnes showed that no capillary imbibition takes place. According to Morrow the ﬂuid distribution inside the core of the C –(EO) – 12–14 15 and Mason, the ratio of gravitational forces to capillary SO surfactant system was non-uniform, possibly due to force is signiﬁcantly important and lowering of IFT may some inhomogeneity in wetting or core properties (Stand- nes and Austad 2003). However, the formation of a positively or negatively affect imbibition (Morrow and 123 Pet. Sci. (2018) 15:77–102 81 Mason 2001). Even when lowering of IFT reduces capil- alteration by surfactant that enhanced capillary imbibition. lary imbibition, imbibition may occur due to the gravita- Cationic surfactants function to change wettability to the tional forces. Capillary imbibition can be initiated and extent that it induces capillary spontaneous imbibition maintained as long as the IFT is not reduced below certain (Standnes and Austad 2000b). On the other hand, alkaline critical values. The interplay between gravitational and anionic surfactants reduce the negative capillary forces capillary forces greatly depends on the IFT value. signiﬁcantly. Some anionic surfactants can lower IFT to For oil-wet carbonate systems, the capillary pressure is ultra-low values where the capillary pressure is nearly zero. usually negative, and as a result, water does not imbibe From the simulation results of a dynamic imbibition pro- spontaneously into the porous medium as oil is ﬁrmly cess study, it was found that the transverse pressure gra- attached to the rock surface by capillarity. By reducing the dients between the fracture and matrix at times pushed the IFT by the use of surfactants, the adhesive forces that retain surfactant further into the matrix (Asl et al. 2010). Hence, oil by capillarity are weakened. Due to lowering of IFT, gravitational forces became active, and oil was recovered capillary trapping is reduced, and this causes oil droplets to by gravity-induced imbibition (Hirasaki and Zhang 2003). ﬂow more smoothly through pore throats and merge with oil down the stream to form an oil bank (Sheng 2015). 3.2 Microemulsion phase behavior of surfactants Lowering of IFT between oil and brine and combination of speciﬁc conditions of temperature and salinity lead to the Microemulsions are thermodynamically stable, homoge- generation of microemulsions. Microemulsions play a vital neous dispersions of two immiscible ﬂuids, generally, role in chemical EOR and are reviewed in next section. hydrocarbons and water stabilized with surfactant mole- Recent spontaneous imbibition studies by Mohammed cules, either alone or mixed with a co-surfactant (Schwuger and Babadagli, for two limestone core samples exposed to et al. 1995). They possess the ability to reduce IFT between two different aqueous phases, distilled water, and 1.0wt% oil and water to an ultra-low value and also can alter the of cationic surfactant C TAB came up with some wettability of reservoir rocks (Zhu et al. 2003). The prin- notable results (Mohammed and Babadagli 2014). The cipal constituents of microemulsions are the surfactants spontaneous imbibition curve indicated the oil-wet nature adsorbed at the interphase rather than in the bulk phase. of the core samples and the negative capillary forces The IFT values between microemulsion and crude oil; and resisted the gravitational forces when the core samples between microemulsion and water are very low, typically -3 were exposed to distilled water. A similar trend was in the range of 10 mN/m. observed for a core sample exposed to the surfactant The IFT behavior of microemulsions is best described solution initially (for 10 days), indicating slow recovery. by examining the phase behavior of the surfactants/co- Nevertheless, after 10 days, a sudden hike in recovery was surfactant–brine–oil system. IFT behavior is believed to be observed, which was possibly due to the wettability a key factor in predicting the performance of oil recovery Surfactant HLB, oil ACN Oil 1 23 4 5 6 7 Microemulsion Water No emulsion Type I Type III Type II Salinity, temperature, co-surfactant, surfactant, surfactant molecular weight, brine-oil ratio Fig. 1 Microemulsion phase behavior of surfactants-water-oil as a function of different variables 123 82 Pet. Sci. (2018) 15:77–102 by the microemulsion ﬂooding process (Kayali et al. 2010). pure EO nonionic surfactants. Increasing the number of EO Essential concepts and details on the phase behavior of units in a surfactant molecule makes it more hydrophilic; microemulsion systems have been presented by Winsor and hence, it can withstand high salinity and temperature to later, others (Winsor 1956; Schwuger et al. 1995). achieve its optimum functionality, a character highly Depending on the surfactant type, the microemulsion phase desirable for high-temperature high-salinity carbonate behavior changes from Winsor I (lower phase) to Winsor reservoirs (Hussain et al. 1997). On the other hand, the III (middle phase) to Winsor II (upper phase) by varying addition of PO units will add mild hydrophobic character, the following conditions: (1) salinity increase, (2) alcohol which can help achieving high solubilization of oil and (co-surfactant) concentration increase, (3) surfactant brine phases. molecular weight increase, (4) oil chain length (alkane carbon number, ACN) decrease, (5) temperature change, 3.2.2 Effect of salinity and temperature on IFT behavior (6) total surfactant concentration increase, (7) surfactant solution/oil ratio increase, (8) surfactant hydrophile-lipo- Salinity has a strong inﬂuence over different microemul- phile balance (HLB) decrease, (9) brine/oil ratio increase, sion structures, which in turn affects the carbonate rock as depicted in Fig. 1 (Salager et al. 2005). wettability behavior. From the studies of Dantas et al. (2014), it is noticed that with an increase in salinity , there 3.2.1 Effect of surfactant structure on IFT behavior is a decrease in wettability inversion from oil-wet/mixed- wet to water-wet surfaces. However, due to the continuous Achieving ultra-low IFT is essential for mobilizing the oil phase of reverse microemulsions, they exhibit favorable residual oil in reservoir rocks and reducing the oil satura- interactions between the oil phase and the oil contained in tion toward zero under normal pressure gradients in oil carbonate rocks with better wettability results, reducing the reservoirs. Surfactants with large hydrophobes are not IFT and consequently enhancing oil displacement from the salinity tolerant. However, the addition of large ethylene rock pores. For bicontinuous microemulsions, an increase oxide and propylene oxide groups may help to achieve in salinity (within an acceptable range for bicontinuous required salinity tolerance. These surfactants with bulky emulsion phases) improved the limestone rock wettability hydrocarbon chains may form high solubilization ratios on water for anionic (SDS) and nonionic (UNT90) sur- when compared to similar counterparts with relatively factants and increased wettability for cationic (cetyl tri- shorter hydrocarbon chains in their structures. In general, methyl ammonium bromide, CTAB) surfactants. The when all other parameters are constant, the longer the wettability alteration to water-wet conditions inﬂuenced hydrocarbon tail in the surfactant structure, the lower will the oil recovery efﬁciency in the order of CTAB [ SD- S & UNT90 facilitating the oil displacement. be the optimum salinity. To transport surfactant solutions under low pressure The temperature of a reservoir is a signiﬁcant parameter gradients, a condition typical in carbonate reservoirs, when surfactant performance is evaluated. A high-tem- highly viscous phases must be avoided, because they result perature, high-salinity reservoir presents severe challenges in high surfactant retention and ultimately poor recovery. regarding surfactant compatibility and stability in brine. Using surfactants with branched hydrophobes could be a However, surfactant adsorption may decrease at high possible solution for abating this problem of viscosity. temperature conditions for highly soluble surfactants, and, Likewise, the addition of propylene oxide (PO) and ethy- on the other hand, poor solubility may lead to high lene oxide (EO) units to sulfate surfactant molecules helps adsorption values. Typically, the surfactants working at in increasing solubilization of the microemulsion phase higher temperature systems show high optimum salinity with a broader region of low IFT due to the interphase (Shah 1981). As longer surfactant hydrophobes require low afﬁnity of the groups. Improved calcium tolerance is an optimum salinity at a particular temperature, usually a additional beneﬁt (Salager et al. 2005). From the studies of heavy hydrocarbon surfactant is needed for high tempera- Hussain et al. (1997), it was found that the presence of an ture conditions and relatively low salinity situations. EO moiety in the surfactant molecule made the surfactant However, there are some exceptions also reported, where less sensitive to salinity than an anionic surfactant. Salinity surfactants (long chain IOS) show low optimum salinity at and surfactant concentration inﬂuence the surfactant high temperature conditions (Barnes et al. 2008). retention in reservoir rocks. Surfactant adsorption is pos- When all the other parameters are kept constant, under a sibly one of the most restrictive factors that affect the oil low water content, the microemulsion system is oil-exter- recovery efﬁciency by microemulsion ﬂooding (Glover nal (reversed), while under a high water content, the system et al. 1979; Hussain et al. 1997) and will be reviewed in is water-external (direct). As the mature carbonate reser- detail shortly. The carboxylic ionic head group-containing voirs of the Middle East are mostly water-ﬂooded, the surfactants are more stable to temperature changes than microemulsions designed for them are a water external 123 Pet. Sci. (2018) 15:77–102 83 system (Winsor Type I) with oil solubilized in the core of cases, are expensive chemicals. During chemical ﬂooding the micelles. However, as salinity plays a signiﬁcant role in process, surfactant loss is common which inevitably redu- reversing the structure of the microemulsion, with an ces the surfactant availability to mobilize trapped oil. increase in salinity, the direct microemulsion structure Different processes act simultaneously for this loss. One of changes to reverse microemulsion (water dispersed in oil) the main processes is surfactant adsorption onto the surface system (Sheng 2010). At lower temperature, the viscosity of the rock. Other processes include precipitation of sur- of the microemulsion system increases with increasing factants and phase trapping. water content, creating swollen micelles or other undesired Surfactant adsorption and loss have been studied structures. The magnitude of this viscosity change of the extensively (Ahmadall et al. 1993; Lv et al. 2011; Soma- microemulsion system (displacing ﬂuid) relative to the oil sundaran and Zhang 2006). Due to high surfactant costs, (displaced ﬂuid) may become important design variables surfactant adsorption is considered as one of the key pro- that affect the volumetric displacement efﬁciency, affect- cesses which deﬁne the overall chemical EOR performance ing the overall oil recovery efﬁciencies (Bera and Mandal and its economic feasibility by determining the total 2015). However, in general terms, microemulsions or amount of surfactant required for the EOR process (Le- emulsions are scarcely designed and used for viscosity- febvre et al. 2012; Tay et al. 2015). Many factors may based applications in reservoirs. The primary reason is the affect the adsorption process such as oil saturation, rock adverse effects of viscous phases, such as high surfactant mineralogy, especially clay contents, reservoir tempera- retention, high IFT, fragile structure and plugging tenden- ture, the salinity of formation water, divalent cations, ion cies under certain conditions. exchange process and surfactant structure. When the sur- factant adsorption control is considered, almost all other 3.2.3 Co-surfactants parameters are controlled by reservoir conditions, and only the surfactant structure is the available option to control The co-surfactants used in microemulsions are alkanols, with salinity of reservoir when using the salinity gradient which are medium chain alcohols such as propanol, buta- technique, which will be discussed shortly. nol, isoamyl alcohol, pentanol, hexanol and so forth Phase trapping, on the other hand, is the migration of (Barakat et al. 1983). It is considered that these co-solvents surfactants to the oil phase or in the microemulsion phase. have well-documented roles in microemulsion-based EOR The surfactant may transfer to the oil phase due to high applications (Pattarino et al. 2000; Zhou and Rhue 2000). temperature, high salinity, and high-divalent ions. Combine Some of the functions include: effect of these conditions may lead to surfactant loss, and ultra-low IFT conditions cannot be met. (a) Preventing the formation of gel-like or polymer-rich Surfactant adsorption may follow several mechanisms. phases, which may separate out from the surfactant Zhang and Somasundaran (2006) discussed several mech- solution. The alcohol used in these formulations act anisms for surfactant adsorption. Important are electrostatic as a co-solvent and partitions itself among the bulk interactions between the surfactant and the solid surface. oil and brine phases making the ﬁlms less rigid and These interactions are between the charged head (positive thereby preventing the formation of undesirable in cationic; and negative in anionic surfactants) and the viscous phases and emulsions (Sahni et al. 2010). rock surface. In addition to those, the lateral interactions of (b) Alteration of the viscosity of the system, hydrocarbon chains are also involved in surfactant (c) Increasing the mobility of the hydrocarbon tail, adsorption after the ﬁrst phase of surfactant head-rock thereby allowing for greater penetration of the oil surface adsorption is accomplished. Another important into the region. mechanism is the reduction of the solubility of surfactants (d) Modiﬁcation of the hydrophilic-lipophilic balance in the aqueous phase due to an increase in salinity or (HLB) values of the surfactants. However, a signif- temperature. icant disadvantage of using an alcohol co-solvent With an understanding of the mechanism of surfactant lies in the fact that it decreases solubilization of oil adsorption, several strategies were proposed and tried for and water in microemulsions, increasing the mini- surfactant adsorption control. These include the use of mum value of achievable IFT for a given surfactant. cationic surfactants, alkali, salinity gradient and adsorption inhibitors. 3.3 Surfactant adsorption process on carbonates As electrostatic interactions play a leading role in sur- and its mitigation and management factant adsorption (Somasundaran and Hanna 1977), it is suggested in the literature that cationic surfactant adsorp- In challenging conditions of carbonate reservoirs, high- tion is less compared to anionic surfactants (Ahmadall performance surfactants are required which, in most of the et al. 1993). However, Ma et al. (2013) reported that the 123 84 Pet. Sci. (2018) 15:77–102 adsorption of cationic surfactants might lead to signiﬁ- surfactants on carbonate and clay minerals while it was not cantly high levels when the rock contains other minerals as effective on sandstones (ShamsiJazeyi et al. 2014a, b). In well. They reported a stronger adsorption of hexadecyl another study, calcium lignosulfonate was evaluated for its pyridinium chloride on natural carbonates (containing sil- adsorption properties on limestones (Bai and Grigg 2005). icon and aluminum) than on synthetic carbonates (highly It was reported that calcium lignosulfonate followed pure calcite). In their study, they found sodium dodecyl pseudo-second-order kinetics and its adsorption increased sulfate (SDS) was adsorbed comparatively less than hex- with the salinity increase. Moreover, the desorption process adecyl pyridinium chloride on carbonate surfaces. Simi- was slow which makes it an excellent sacriﬁcial agent to larly, Rosen and Li explained the adsorption of double reduce surfactant adsorption. chain (Gemini) surfactants and conventional single chain surfactants on limestones (Rosen and Li 2001). The 3.4 Surfactant ﬂooding adsorption of Gemini surfactants was high, despite having a similar charge on the head group. They attributed this Historically, as well as in present-day research, the primary strong adsorption to the relatively high bulk of the carbon focus of surfactant use in EOR is their microemulsion- chain and hydrophobic interaction between the chains. In producing ability with crude oil in the presence of brine addition to that, they reported that molar absorption of and generating stable foams with gas. Recently, however, anionic surfactants was relatively lower than for cationic their capabilities of wettability alteration have also been surfactants (Rosen and Li 2001). These reports suggest that given much focus in EOR research. cationic surfactants are not the only solution to the problem As the microemulsion proceeds in the reservoir, it col- of high surfactant adsorption on carbonates. Moreover, the lects oil, forming an oil bank during the process. This oil adsorption on the carbonate surface is highly dependent on bank then pushed to the production well by using polymer the salinity and the presence of impurities on the surface of drive. Foams, on the other hand, are used as mobility the rock. control agents when polymers fail due to salinity, tem- In another proposed approach, a salinity gradient is perature or permeability limitations. suggested by Hirasaki et al. (1983). In this method, a slug of surfactant (S, SP or ASP) is injected and then followed 3.4.1 Alkali–surfactant ﬂooding by low salinity brine injection. Therefore, high salinity formation brine is ﬁrst replaced by optimum salinity brine, The concept of combined injection of alkali and surfactants and then, optimum salinity brine is replaced by low salinity was once thought to be one of the most promising ﬂooding brine. In the start of injection, a Type II microemulsion methods for enhanced oil recovery. Low-cost alkaline agents, such as sodium hydroxide and sodium carbonate, phase is generated which eventually changed to optimum Type III phase microemulsion due to the attaining of low were being used together with many kinds of surfactants to salinity conditions. In the last stage, low salinity brings the enhance the oil recovery efﬁciency. In an alkali–surfactant Type I microemulsion. It is suggested that both Type II and process, the primary role of the alkali is to reduce Type III show high retention while the following Type I adsorption of surfactant on the rock surface sequestering shows low adsorption thus completing the process. The divalent ions. Additionally, alkali injection also generates associated problems with this approach are the possibility in situ surfactants from the naphthenic acids of crude oil of inappropriate mixing of brines in the reservoir, avail- (Johnson 1976). However, application of alkali is not free ability of low-salinity brine in the ﬁeld and logistic issues. of problems and challenges such as scaling and production It is also important to note that the salinity gradient effect of highly stable emulsions (Zhu et al. 2012). has not been studied in carbonate rocks (Tay et al. 2015). Early work on surfactant–alkali ﬂooding was docu- More recently, adsorption inhibitors and sacriﬁcial mented in the literature (Mayer et al. 1983; McCafferty and agents are also proposed by many researchers to mitigate McClaﬁn 1992; Falls et al. 1994). However, this cEOR the adsorption problems (Tabary et al. 2012; ShamsiJazeyi technique was mostly carried out in sandstone reservoirs et al. 2014a, b; Delamaide et al. 2015; He et al. 2015; Tay for producing medium and light oils (Wang et al. 2010). et al. 2015). These are chemicals which preferentially From the review of Alvarado and Manrique 2010, it was adsorb on the surface thereby reducing the chances of seen that out of the 1507 international EOR projects; most adsorption of expensive surfactants. In recent studies, it is applications were in sandstone reservoirs. The recovery reported that polyelectrolytes such as polystyrene sulfonate factor of this process was mostly small, especially for and polyacrylate may preferentially bind the available sites fractured carbonate formations, probably due to unfavor- on the rock surface and reduce surfactant adsorption sig- able mobility ratios. niﬁcantly. ShamsiJazeyi et al. reported that sodium poly- Four proposed mechanisms of alkaline ﬂooding for acrylate successfully reduced the adsorption of anionic enhanced oil recovery were summarized by Johnsen and 123 Pet. Sci. (2018) 15:77–102 85 later by Sheng 2013. These are emulsiﬁcation-entrainment, approach came to be known as ‘‘alkali–surfactant–poly- emulsiﬁcation-entrapment, wettability reversal, and emul- mer’’ (ASP) ﬂooding or surfactant–polymer ﬂooding (SP) siﬁcation-coalescence, of which emulsiﬁcation is possibly depending on the contents of the injection slug. From its the most important mechanism (Sheng 2011, 2013). Dif- initiation, the ASP method has been identiﬁed as a cost- ferent types of emulsions are formed when residual oil effective cEOR process, yielding high recovery rate, comes into contact with the alkaline ﬂooding ﬂuid under mostly for sandstones and to a limited extent for carbonate different reservoir conditions (Bai et al. 2014). When low reservoirs (Olajire 2014). ASP for carbonate reservoirs viscosity direct (O/W) emulsion is formed, it can quickly received little focus until the last few years. Reasons ﬂood out through pore throats, consequently enhancing the include: the high-divalent-ion environment of the carbon- displacement efﬁciency, as observed in the works of Jen- ate reservoirs leads to the formation of calcium and mag- nings et al. (1974). A possible explanation for this obser- nesium sulfonates with the typical commercially available vation could be that the direct (O/W) emulsions dampened surfactants (alkyl/aryl sulfonates) that either precipitate or viscous ﬁngering and improved sweep efﬁciencies. Similar partition out into the oil phase (Liu et al. 2008). An observation was also reported in the works of Symonds exception to this observation was reported in the early et al., where depending upon the concentration of the works of Adams and Schievelbein 1987, who demonstrated NaOH solution, two different mechanisms (emulsiﬁcation- that oil could be displaced from a carbonate reservoir using entrainment and emulsiﬁcation-entrapment) for improved a mixture of petroleum sulfonates and alkyl ether sulfates oil recovery was noticed (Symonds et al. 1991). or alkyl/aryl ether sulfates. As stated earlier, surfactant plays a pivotal role in Use of cationic surfactants for promoting desorption of microemulsion formation, and among all surfactants, acids from carbonate rock surfaces and making the rock anionic surfactants are the most well-known and widely more water-wet was proposed by Standnes and Austad used surfactants in oil recovery (Liu et al. 2008). The (2003). Similarly, other researchers of the time (Xie et al. domain of cationic surfactant-based microemulsion meth- 2004; Chen et al. 2000) investigated the effectiveness of ods is still less explored, and this could be a future area of various other surfactants in altering wettability. Their research for scientists targeting enhanced oil recovery from studies suggested that ASP solutions could be injected into carbonate reservoirs. There are few literature reports carbonate formations to increase oil recovery. Related available on the application of cationic surfactant-based experimental approaches and simulations of the perfor- microemulsions in EOR. In a study, Zhu et al. 2009, mance of ASP under ﬁeld conditions were pursued reported the use of a mixture of Triton X 100 (nonionic) (Seethepalli et al. 2004; Adibhatia et al. 2005). Of late, and cetyl trimethyl ammonium bromide (CTAB) (cationic) other studies reported combination ﬂooding using polymers microemulsion in lowering IFT between crude oil and the and surfactants for high-temperature, high-salinity car- aqueous phase (brine) for additional oil recovery. Recent bonate reservoirs of Indonesia KS oilﬁelds (Zhu et al. investigations show that cationic surfactants, for example 2013). They used two competent polymers, namely CTAB, perform better than anionic surfactants in wetta- STARPAM and KYPAM with suitable viscosifying abili- bility alteration of carbonate rocks to more water wet ties along with two surfactants, AS-13 (amphoteric) and (Saleh et al. 2008). SPS1708 (anionic-nonionic) for a weak alkaline ASP sys- Again, when the reverse (W/O) emulsions are formed, tem. These systems could reduce the IFT to ultra-low -3 due to their high viscosity, they block the water channels levels (10 mN/m) within a wide range of alkalinity and pore throats in the process of migration (Kang et al. (0.2wt%–1.0wt% Na CO ). The addition of sodium car- 2 3 2011). This phenomenon is particularly relevant for heavy bonate as an alkali markedly reduced the adsorption of oil recovery as observed in the works of Pei et al. (2011), anionic surfactants over the calcite and dolomite surfaces, and later, by Dong et al. (2012). A bank of viscous (W/O) diminishing one of the very typical problems of surfactant emulsion forms when an acidic heavy oil is displaced by an adsorption and thus making the process applicable for alkaline solution prepared in a high-salinity brine in a carbonate formations (Hirasaki and Zhang 2003). They porous medium. This emulsion plugs the growing water also conﬁrmed that carbonate precipitates did not affect ﬁngers and channels and diverts the ﬂow to an initially permeability to a great extent, which was discussed in a unswept area resulting in a dramatic rise in the corre- previous study by Cheng (1986). In addition to that, car- sponding sweep efﬁciency (Ge et al. 2012). bonate/bicarbonate ions are potential determining ions on carbonate rocks and can shift the zeta potential to a more 3.4.2 Alkali–surfactant–polymer ﬂooding negative value. More negative zeta potential can inﬂuence the water wetness of rock which promotes oil displace- Adding a polymer to the surfactant solution or alkali–sur- ment. Furthermore, alkalis injected in ASP processes also factant solution improves its sweep efﬁciency. This generate soap in situ by reaction between the alkali and 123 86 Pet. Sci. (2018) 15:77–102 naphthenic acids in the crude oil, which forms an oil-rich streaks, and gravity override are frequent (Hanssen et al. colloidal dispersion as mentioned earlier (Johnson 1976). 1994). One of the strategies to meet these challenges is to The local ratio of this soap/surfactant determines the utilize foam, a dispersion of gas in a continuous liquid that optimal salinity for minimum IFT (Hirasaki et al. 2008). lowers the mobility ratio. Boud and Holbrook (1958) Core ﬂooding experiments revealed that more than 17%– demonstrated for the ﬁrst time that foam could be gener- 18% additional oil recovery over water ﬂooding could be ated in an oil reservoir by sequential injection of aqueous obtained with either ASP or SP ﬂooding in carbonate surfactant solution and both miscible and immiscible gas reservoirs. ASP processes utilized the beneﬁts of three drives to increase its sweep efﬁciency. However, due to ﬂooding methods, whereby oil recovery was signiﬁcantly lack of proper understanding of the mobility control enhanced, by decreasing IFT, increasing the capillary mechanism by foam, the concept was not adopted widely number, enhancing microscopic displacing efﬁciency and (Li et al. 2010). Nevertheless, as the understanding of foam improving mobility ratio (Shen et al. 2009). However, mobility control advanced, there have been many ﬁeld tests despite these advantages, the success of the ASP projects of foam application since then. One of the most successful was not without certain limitations. Problems of severe ﬁeld pilot tests of foam mobility control in the Snorre ﬁeld scaling in the injection lines with strong emulsiﬁcation of is a well-known example (Blaker et al. 1999). Le et al. the produced ﬂuid signiﬁcantly impeded the implementa- (2008) performed a successful series of experiments on tion of ASP ﬂooding technologies (Gao and Towler 2011; carbonate rocks to study the injection strategy for foam Wang et al. 2009). Also, polymers could not be efﬁciently generation and emphasized the potential of foam as a used under high salinity conditions, because high salt mobility control agent (Le et al 2008). conditions degraded their viscosity. Moreover, multicom- Mobil’s Slaughter and Greater Aneth ﬁeld trials ponent formulations always run the risk of chromato- (1991–1994) were initial successful attempts of foam uti- graphic separations in the reservoir, as demonstrated in the lization for enhanced oil recovery. In this case, out of the ASP project in the Daqing Oilﬁeld in China (Li et al. four CO -foam ﬁeld trials, two were performed at the 2009). Improving the status of these commercially avail- Greater Aneth ﬁeld in carbonate reserves (South Utah). The able viscosiﬁers by the incorporation of salt tolerant outcome of all of these trials highlighted a sharp decrease monomers, so that cheap alkalis such as sodium carbonate in CO injectivity and a signiﬁcant increase in oil are successfully used, and employing associative mecha- production. nisms that allow for lower molecular weight polymers with Earlier, foam injection strategies such as water alter- improved injectivity are still under way. nating with gas (WAG) were considered as the technology of choice for controlling CO gas mobility (Enick et al. 3.4.3 Surfactant foams 2012). However, even then, complications, for example, viscous instabilities and gravity segregation, especially for Currently, surfactant-aided CO ﬂooding is being tested in heterogeneous reservoirs could not be defeated (Rogers and Middle East carbonate reservoirs (Al-Mutairi and Kokal Grigg 2001). As a possible solution to these complications, 2011). Owing to its physical properties and established foam-assisted EOR, such as the alkali–surfactant–gas multiple interactions with oil over a wide range of pres- (ASG) process, is one of the newly introduced successful sures and temperatures, CO is considered to be one of the synergistic combination of chemical and gas EOR meth- most important displacing ﬂuids in gas-based EOR tech- ods, especially for carbonate reservoirs (Li et al. 2010; nology (Blunt et al. 1993; Mathiassen 2003). However, Srivastava et al. 2009). The ASG process exhibits lower there are several problems associated with the gas injection mobility in high-permeability layers and hence under- (Sagir et al. 2013). Among them, the greatest challenge standably blocks or hinders the ﬂow in these layers. with CO gas injection lays in its poor volumetric sweep Simultaneously, the ﬂow in low-permeability layers is efﬁciency owing to its low density and viscosity. Lighter reasonably favored with enhancing oil recovery (Fara- gas overrides gravity and a large portion of recoverable oil jzadeh et al. 2012). Since ASG processes combine both the in the lower permeability regions cannot be contacted. This concepts of IFT lowering and using foam as mobility poor sweep leaves behind an extensive amount of oil in the control agents, they are mostly encouraged for HTHS reservoir. Though the microscopic sweep efﬁciency of CO carbonate reservoirs, where the functioning of polymers is quite high, its viscosity (* 0.01 cP) is much lower than usually deteriorates (Lake 1989; Niu et al. 2001). In recent both water (* 1.0 cP) and most of the crude oils experimental studies as reported in the works of Nguyen, (0.6–10 cP for conventional oils) which leads to many 2010, a twin-tailed dioctylglycerine surfactant showed conformance and mobility concerns and instability in the excellent performance in signiﬁcantly reducing mobility displacement front. Problems of poor volumetric sweep and recovering oil remarkably from a carbonate rock core efﬁciency, gas channeling through high-permeability ﬂood experiment. Based on these experimental ﬁndings, it 123 Pet. Sci. (2018) 15:77–102 87 is summarized that ASG foams affect the oil recoveries in To overcome these limitations, ethoxylated nonionic to three ways when compared to gas or WAG ﬂooding (An- cationic switchable amine surfactants were designed and drianov et al 2012; Farajzadeh et al. 2010): introduced in a series of sand pack experiments (Chen et al. 2012, 2014). Ethoxylated amines are switchable from (a) By increasing the viscosity of the displacing ﬂuid being nonionic in brine to cationic in the presence of an (gas or foam), the displacement process is stabilized; acidic aqueous phase such as CO (Elhag et al. 2014a). (b) By blocking the high-permeability swept layers and Reactions between primary, secondary or tertiary amines diverting the ﬂuids into low-permeability unswept with an appropriate alkoxylation agent generated these zones; and ethoxylated amines. Relative to the size of a hydrophobic (c) By reducing the IFT with its present surfactants, chain of alkyl amines, the size of the hydrophilic group reducing the overall capillary force. increased with ethoxylation, which in turn increased the One of the major concerns that subdue the application of hydrophilicity (Chen et al. 2014). Because of the proper foam as an EOR method is its stability (longevity) concerns balance in the number of carbons in their alkyl chains and when in contact with crude oil. Many experiments per- the number of ethylene oxide (EO) groups attached to the formed to interpret foam stability in bulk, and porous tertiary nitrogen in their head groups, ethoxylated alkyl media have demonstrated the detrimental effect of oil on amines of the form C N(EO) were found to satisfy 12–14 x foam stability (Andrianov et al. 2012; Farajzadeh et al. several essential requirements for effective CO -EOR. This 2010; Vikingstad and Aarra 2009; Vikingstad et al. 2005). surfactant was highly soluble in the CO phase because the In many cases, the oil saturation must become low enough, nitrogen atom remained unprotonated in this phase. While before the gas mobility can be reduced by foams. Usually, in a low-pH aqueous phase due to dissolved CO , the two mechanisms of interaction between foam ﬁlms and oil positively charged protonated amine rendered the surfac- phase might occur when they come in contact with each tants more hydrophilic and raised the cloud point to other. Either the oil phase might probe into the foam ﬁlm 120 C. Further, in the presence of CO , the adsorption of and destabilize it, or the foam ﬁlm might slide over the ethoxylated alkyl amines (dissolved in brine) on limestone water phase covering the oil. The ﬁrst possibility is most surfaces was signiﬁcantly reduced due to the positively common and expected, while the latter case if raised will charged cationic head group. Thus, switchable ethoxylated generate a new oil/water interphase—a ‘‘pseudo-emulsion amine surfactants can be considered as a new generation or asymmetric’’ ﬁlm. Studies of these asymmetric ﬁlms are surfactant, which uniquely combine the high cloud point of supremely important in predicting and controlling the sta- ionic surfactants in water with high solubility in CO for bility of foam in the presence of oil. However, reports on nonionic surfactants, stabilizing foam formations at 120 C the pseudo-emulsion are very rare (Jones et al. 2016). with minimal adsorption on limestone (Elhag et al. 2014b). Sometimes, traditional commercial nonionic or anionic Nonetheless, switchable surfactant experiments are still in surfactants used in CO foam-based recovery are unsuit- the primary stage, and much in-depth exploration needs to able for application in the HTHS reserves. The cloud points be done for proper understanding and acceptance of this of ethoxylated nonionic surfactants are consistently way cEOR technique in actual ﬁeld applications. Some possible below 100 C (Adkins et al. 2010), and the solubility of problems may be the maintenance of a low enough pH to most nonionic surfactants decreases in brine as the salinity keep them protonated and in a dissolved state in brine. increases (Rosen and Kunjappu 2012). There are reports of There is the possibility of dissolving or corroding carbon- several laboratory scale tests and ﬁeld trials using anionic ate formation in low pH conditions. sulfate and sulfonate surfactants for high-salinity limestone reservoirs (Hirasaki et al. 2008; Levitt et al. 2006). How- 3.4.4 Biosurfactants from bacteria and renewable ever, due to the electrostatic force of attraction, they often resources adsorb strongly on the positively charged limestone sur- faces in the presence of dissolved acidic CO at high To improve the cost effectivity of surfactant ﬂooding, pressures (Lawson 1978, Wang et al. 2015). Cationic sur- many researchers have investigated oil displacement by factants, on the other hand, exhibit low adsorption on biosurfactants primarily produced from bacteria during the carbonate formations, due to the electrostatic repulsion past decade (Banat 1995; Youssef et al. 2007; Joshi et al. between the cationic head and the positive charge bearing 2008; Al-Sulaimani et al. 2010). Biosurfactants are claimed carbonate surface (Hirasaki et al. 2008; Ahmadall et al. to be eco-friendly, non-toxic and biodegradable compared 1993; Lawson 1978). Nevertheless, they are rarely soluble to synthetic and toxic chemicals that are dangerous for oil in CO , although there are reports of a few exceptions workers and the environment. The economy of the com- (Smith et al. 2007). mercial production of these materials is affected by the downstream processing costs which are about 60% of the 123 88 Pet. Sci. (2018) 15:77–102 total production cost of many biological products. Never- surfactants are very promising waterborne chemicals that theless, studies indicate that crude or impure biosurfactants combine the desirable properties of surfactants and water obtained at the initial stage of recovery can be efﬁciently viscosiﬁers. Similar to conventional surfactants, they are used for oil recovery applications (Ghojavand et al. 2012). also amphiphilic in nature with a hydrophilic and a Efﬁcient biosurfactants could be produced from inex- hydrophobic portion. However, unlike surfactants that form pensive and renewable sources such as sugar cane molasses spherical micelles of oil in water, viscoelastic surfactants with a cost of lower than 0.5$ per liter (Oscar et al. 2007). aggregate to form large complex supramolecular structures Green, environment-friendly, non-toxic surfactants such as that have a high viscosity. A primary beneﬁt of these 0.5% alkyl polyglycoside (APG) derived from a sugar supramolecules is that they possess self-healing capability, source in a binary system with 0.5% NaHCO reduced the unlike polymers. Usually, the structure and size of these IFT, improved interface wettability, exhibited compatibil- viscoelastic surfactants are determined by the surfactant ity with injected and produced water and demonstrated low head group size, charge of the surfactant, temperature, adsorption on calcite plates derived from the G Oilﬁeld in salinity and ﬂow conditions. With an increase in concen- Kuwait (Yin and Zhang 2013). Results obtained from a tration, these surfactant molecules create ‘‘worm-like’’ recent experimental study by Ghojavand et al. showed that micelles when the surfactant molecule forms long aniso- a lipopeptide biosurfactant produced by Bacillus metric ﬂexible structures that are capable of entangling mojavensis PTCC 1696, isolated from an Iranian oilﬁeld, with other ‘‘worm’’ structures (Santvoort and Golombok could appreciably reduce the IFT in carbonate reservoirs 2015). One of the possible issues of implementing vis- even in the presence of high salinity (240 g/L-NaCl coelastic surfactants is adsorption on the carbonate surface, salinity) and thus enhance oil recovery from these low- which, however, can be managed in high-pH alkaline permeability reservoirs (Ghojavand et al. 2012). In another systems. Others may include their emulsiﬁcation with oil study by Sarafzadeh et al., the efﬁciency of two microbial and losing their viscosity, high cost and rather fragile biosurfactant-producing strains Enterobacter cloacae and nature of viscofying structures. Effects of shear, mainte- Bacillus stearothermophilus SUCPM#14 in EOR was tes- nance of viscosity during ﬂow, injectivity and industrial- ted (Sarafzadeh et al 2014). The core ﬂood experiments scale production and availability are also required to be investigated parameters such as cost effectivity, time and evaluated for commercial success. the ability of surfactants to lower IFT. It was found that of the strains, E. cloacae signiﬁcantly reduced the IFT of 3.5 Surfactant-based EOR projects water/crude oil system from 30 to 2.7 mN/m, modifying the capillary numbers and mobilizing trapped oil. A few surfactant-based EOR projects have been tried in carbonate ﬁelds, although many polymer projects were Sometimes, natural surfactants extracted from plant sources can also function as an effective chemical EOR conducted between the 1960s–1990s. Between 1990s and agent. Based on studies concerning its adsorption and 2000s, only few surfactant stimulation studies were economic aspects, saponin was found to be an important reported in carbonate reservoirs; including Yates ﬁeld in EOR agent, having very low cost and low adsorption val- Texas and the Cotton Wood Creek in Wyoming. The ues comparable to commercial, industrial surfactants for Baturaja Formation in the Semoga ﬁeld in Indonesia is a carbonate reservoirs (Ahmadi and Shadizadeh 2012; Shahri comparatively recent ﬁeld study. et al. 2012; Zendehboudi et al. 2013). In their studies, A list of published ﬁeld studies on surfactant-based Ahmadi and Shadizadeh systematically investigated the chemical EOR for carbonate reservoirs is summarized in implementation of a novel sugar-based surfactant derived Table 1. from the leaves of Z. spina christi for EOR applications in carbonate reservoirs (Ahmadi and Shadizadeh 2013b). Under the optimum conditions of 8 wt% surfactant con- 4 Surfactants employed for chemical EOR studies centrations and 15,000 ppm salinity, the proposed surfac- in carbonate reservoirs over the years tant exhibited 81% oil recovery. Although there are very few reported ﬁeld projects for 3.4.5 Viscoelastic surfactants cEOR in carbonate reservoirs, research activities about chemical methods have always been and are still in pro- Recently introduced viscoelastic surfactants are suggested gress through joint industrial projects and various academic as an alternative to polymers. They are known to effec- institution initiatives. Table 2 summarizes a list of pub- tively enhance oil recovery from carbonate reservoirs lished laboratory studies on cEOR by surfactants, alkaline under conditions of high temperature and salinity (Azad surfactants, and alkaline surfactant polymer mixtures. and Sultan 2010; Sultan et al. 2014). Viscoelastic Apart from this, some of the recently introduced surfactants 123 Pet. Sci. (2018) 15:77–102 89 Table 1 A selection of published surfactant-based chemical EOR ﬁeld projects for carbonate reservoirs Field Region Start Oil characteristics Oil Chemicals used Process References recovery, adopted/comments API Viscosity, %OOIP cP Wichita Texas 10/1/ 40.0 3.2 22.0 Surfactants: petroleum Micellar/polymer Leonard (1984) County 1975 sulfonates ? alkyl ether ﬂooding process Regular sulfate adopted Gunsight (secondary Polymers: polyacrylamide reservoir recovery) Reservoir temperature: 31.6 C Wesgum Arkansas 6/1980 21.0 11.0 26.7 Surfactants: petroleum Micellar/polymer Leonard (1986) ﬁeld, sulfonates ? alkyl ether ﬂooding process Smackover sulfate adopted reservoir (secondary Polymers: polyacrylamide recovery) Reservoir temperature: 85 C Bob Slaughter Texas 1980 31.4 1.3 12.0 Non-emulsion formulation: Two surfactant/ Adams and Block 1.5% solubilizer A polymer ﬂooding Schievelbein Lease, San (alkyl ether sulfates) and processes (1987) Andres 3.5% Witco petroleum adopted: non- reservoir sulfonate emulsion formulation and Emulsion formulation: emulsion 1.46% solubilizer B formulation (alkyl aryl ether sulfates), 3.6% Witco petroleum Reservoir sulfonate, 0.95% temperature: synthetic sulfonate, 4% 43 C gas oil, 4% slaughter crude oil Isenhour Wyoming, 1980 43.1 4.8 26.4 Na CO ? anionic Alkali/polymer Doll (1988) 2 3 USA polymers ﬂooding process adopted Reservoir temperature: 36.1 C Cambridge Wyoming, 1993 20.0 31.0 36.0 1.25wt% Na CO as Alkaline/surfactant/ Vargo et al. 2 3 Minnelusa USA alkali ? 0.1wt% polymer ﬂooding (2000) Petrostep B-100 as process adopted surfactant ? 1475 mg/L (secondary Alcoﬂood1175A as recovery) polymer Reservoir temperature: 55.6 C Yates ﬁeld, Texas 1998 30.0 6 15.0 0.3%–0.4% nonionic Surfactant well Yang and San Andres ethoxy alcohol (Shell stimulation Wadleigh reservoir 91–8) surfactant and processes (2000), 35% Stepan CS-460 adopted Mathiassen anionic ethoxy sulfate (2003) Single-well Huff-n- surfactant Puff dilute surfactant treatment Reservoir temperature: 28 C 123 90 Pet. Sci. (2018) 15:77–102 Table 1 continued Field Region Start Oil characteristics Oil Chemicals used Process References recovery, adopted/comments API Viscosity, %OOIP cP Mauddud Bahrain 1/1999 – 1.4–2.9 10–15 0.5% of surfactants in 200 Surfactant diesel Zubari and carbonate gallons per ft of diesel wash Sivakumar reservoir oil (2003) Surfactant xylene 1/2000 0.5% of surfactants in 55 wash gallons per ft of xylene Alkaline surfactant 1/2002 0.5% of surfactants ? 1% ﬂooding process sodium carbonate adopted alkaline solution Reservoir temperature: 60 C Cottonwood Wyoming, 1999 27 2.8 10.4 Nonionic polyoxyethylene Single-well Xie et al. Creek ﬁeld, USA alcohol (POA) surfactant (2004), Bighorn stimulation Weiss et al. Basin process adopted (2006) Reservoir temperature: 65.5 C Semoga ﬁeld, Indonesia 2009 38 0.84 58,000 bbl Nonionic surfactants Surfactant well Rilian et al. Baturaja over a stimulation via (2008) Formation period of Huff-n-Puff 3 months processes adopted Operation in 3 steps: (a) pre- ﬂush, (b) main ﬂush and (c) overﬂush Reservoir temperature: 83 C; salinity: 15,000 mg/L targeting speciﬁc carbonate reservoir conditions such as of hydrocarbon reserves, for studying ﬂuid ﬂow through high temperature, high salinity and the presence of natural porous media and for designing production equipment. The fractures have been discussed in detail. dead oil viscosity (0.6–33.7 cP), saturated oil viscosity (0.05–20.89 cP) and undersaturated oil viscosity 4.1 Surfactants targeted toward high-temperature (0.2–5.7 cP) having API gravity of 19.9–48, temperatures high-salinity (HTHS) reservoirs of the Middle of 38–150 C, bubble point pressure of 690–25,500 kPa East and pressure above bubble point (8875–69,000 kPa) were obtained from the Middle East crude oils. The high temperature of about 120 C in oil to mixed-wet For such challenging reservoirs, an approach using carbonate reservoirs around the Middle East and elsewhere tetraalkylammonium salt (TAS) type cationic surfactant is an important criterion to be considered when looking for was proposed for enhancing ORF from heavy oil-impreg- appropriate surfactants for cEOR. The high salinities such nated calcite cores (Saleh et al. 2008). It is commonly as 16%–22% TDS in Abu Dhabi along with the high observed that spontaneous water imbibition is not possible temperature in the range of 120 C are current challenges in oil-wet rock surfaces due to the presence of very small or in the implementation of cEOR in the United Arab Emi- negative capillary pressure. Initially, it was believed that rates (Quadri et al. 2015). The viscosities of dead crude oils wettability reversal by anionic ethoxylated sulfonate sur- and crude oils containing dissolved gasses (saturated and factants was capable of achieving spontaneous imbibition under saturated) from the Middle East were accurately of water by capillary forces in the new water-wetted sur- calculated using the Elsharkawy and Alikhan model (El- faces (Standnes and Austad 2000a). Nevertheless, low 20% sharkawy and Alikhan 1999) for the formation evaluation ORF values obtained from experiments using anionic 123 Pet. Sci. (2018) 15:77–102 91 Table 2 Chemical EOR laboratory studies for carbonate reservoirs by surfactants, alkaline surfactants and ASP mixed slugs Surfactant type and Materials Synthetic brine Comments/experimental Estimated References concentration outcomes ﬁnal recovery, Amphoteric Petrostep B-100 Cretaceous Formation brine (TDS- Experiments conducted at 45 Olsen et al. 2? 2? surfactant (0.2wt%– Upper 12,000 ppm, Ca ,Mg , reservoir temperature of (1990) 0.5wt%) ? Pusher 700E Edwards Na ) 42 C polymer reservoir Crude oil viscosity: 3 cP; (0.12wt%) ? sodium Carbonate API: 27 (light oil) tripolyphosphate (0.4%– formations ASP ﬂooding was adopted 0.5%) and sodium from Central carbonate (2%) alkali Texas Permeability: 75 mD Cationic surfactants of the Oil-wet low Three different brines with Two types of oil are used: Oil 10–75 Standnes type tetra alkyl ammonium permeability various dissolved solids A—acidic crude oil: n- and ? ? 2? (six) (2–7 mD) content (Na ,K ,Mg , heptane (60:40) and Oil Austad 2? - 2- - outcrop chalk Ca ,Cl ,SO , HCO ) B—pure n-heptane (2003) 4 3 Anionic surfactants (eight) from Stevns Imbibition tests run with 0.1wt% for each Klint cationic and anionic Copenhagen surfactants at different temperatures (40–70 C) Cationic surfactants have a higher potential to expel oil from oil-wet chalk material (irreversible wettability alteration) than anionic surfactants Surfactant concentration [ CMC Anionic (ethoxylated and Dolomite cores Formation brines (NaCl, KCl, Anionic surfactants and 40–50 Hirasaki propoxylated sulfate) CaCl , MgCl ,Na SO ) Na CO /NaHCO changed and 2 2 2 4 2 3 3 Permeability: surfactants ? sodium the wettability of oil-wet Zhang 40–122 mD carbonate alkali mixture dolomite cores to (2003) (0.05wt%–0.1wt%) preferentially water-wet as a function of the prior aging temp in crude oil Oil recovery from oil-wet dolomite cores was by spontaneous imbibition with an alkaline anionic surfactant solution Oil viscosity: 18.1–22.6 cP 123 92 Pet. Sci. (2018) 15:77–102 Table 2 continued Surfactant type and Materials Synthetic brine Comments/experimental Estimated References concentration outcomes ﬁnal recovery, Nonionic ethoxy alcohol Dolomite cores Actual Yates reservoir brine Nonionic ethoxy alcohol – Vijapurapu surfactants (\ 3500 ppm) (NaCl, KCl, CaCl , MgCl , surfactants decreased IFT and Rao 2 2 Na SO , NaHCO ) supplied between Yates crude oil (2004) 2 4 3 by Marathon Oil Company. and Yates brine, along with a simultaneous decrease in Synthetic brine (prepared as contact angle from 156 per the same composition) (strongly oil-wet) to 39 (water-wet) The experimental study identiﬁed two simple techniques of surfactant addition and brine dilution to beneﬁcially alter the wettability of oil-wet fractured cores and minimize capillary trapping of crude oil in reservoir rocks Anionic ethoxylated (EO) and Calcite Synthetic brine (Na CO ) The oil used was West Texas 35–55 Seethepalli 2 3 propoxylated (PO) sulfate lithographic fractured carbonate ﬁeld et al. surfactants limestone, crude oil (19.1 cP, API (2004) marble, 28.2-light) supplied by Cationic (CTAB) surfactants dolomite Marathon Oil Company 0.05wt% for each plates In the presence of Na CO , 2 3 anionic surfactants could change the calcite wettability of carbonate from oil-wet to water-wet, similar to or even better than cationic surfactants The adsorption of anionic sulfonate surfactants is signiﬁcantly suppressed by the addition of Na CO 2 3 Cationic C TAB surfactants Oil-wet low Artiﬁcial seawater Crude oil used was diluted 50–90 Hognesen permeability with 40vol% heptane et al. 0.6wt%–3.5wt% (1–3 mD) (2006) Oil viscosity: 2.5 cP (light outcrop chalk oil) from Stevns Oil production from different Klint surfaces of the core studied Copenhagen Comparison between the gravity and capillary force contribution Cationic C TAB surfactants Outcrop chalk Artiﬁcial seawater as Oil A: 60% crude and 40% 20–60 Strand et al. (1.0wt%) reference, 11 different brines heptane (2006) Permeability low with varying dissolved solid (2–5 mD) Ion pair interaction is the ? 2? contents (Na?,K ,Ca , probable wettability 2? - 2- - Mg , SCN ,SO ,Cl , alteration factor, thereby HCO ) increasing the capillary forces that facilitates spontaneous imbibition of oil The temperature range in the study was 90–130 C 123 Pet. Sci. (2018) 15:77–102 93 Table 2 continued Surfactant type and Materials Synthetic brine Comments/experimental Estimated References concentration outcomes ﬁnal recovery, Five anionic (sulfonate, Calcite plates Na CO and NaCl The oil used was West Texas 60–75 Gupta and 2 3 disulfonate and sulfate) limestone fractured carbonate ﬁeld Mohanty surfactants cores, crude oil (23.8 cP, API 2010 28.2-light) at 27 C Two nonionic (ethoxylates) Permeability: surfactants, 0.1wt% for each 15 mD The temperature ranges: 25–90 C Oil recovery rate increases with temperature increase for all anionic and nonionic surfactants studied up to 90 C Surfactant/brine imbibition was a gravity driven process Anionic (sulfonate, Calcite plates Synthetic brine (Na SO , Two oils used: (a) Model oil- 30–50 Gupta and 2 4 disulfonate and sulfate) Texas NaCl, Na CO , CaCl , 1.5wt% of cyclohexane Mohanty 2 3 2 surfactants, 0.1wt%–5wt% Cordova MgCl ) pentanoic acid ? n-decane. (2011) cream (b) West Texas fractured limestone core carbonate ﬁeld crude oil (23.8 cP, API 28.2-light) Permeability: at 27 C 15 mD Optimum surfactant concentration is directly linked with brine salinity Mixed with Na CO , anionic 2 3 surfactants desorb the naphthenic acid from carbonate surface, as at high pH, calcite charge is switched from positive to negative Wettability of oil-aged calcite altered by sulfate ions in the 2? 2? presence of Mg ,Ca at 90 C aiding in oil recovery Two anionic surfactants Limestone Formation brine (NaCl, The mixture of cationic and 70–80 Sharma and (ethoxylated sulfonate: MaCl ) nonionic surfactants is Mohanty AV-70, AV-150) stable at high temperatures (2013) (100 C) and high salinity Three nonionic surfactants (NP ethoxylate, 15-s- Effective in wettability ethoxylate, TDA 30EO) alteration of carbonate reservoirs with aging Four cationic surfactants 1–2 months (CTAB, DTAB, Arquad C-50, Arquad T-50) surfactants \ 0.2wt% for each 123 94 Pet. Sci. (2018) 15:77–102 Table 2 continued Surfactant type and Materials Synthetic brine Comments/experimental Estimated References concentration outcomes ﬁnal recovery, Anionic surfactants: alkyl Silurian Formation brine Crude oil viscosity: 22.5 cP; 26–80 Sagi et al. propoxy (PO) sulfates Dolomite (TDS = 9412–10,625 ppm, API: 28.2 (light oil) (2013) ? 2? 2? - (APS) and their blends with outcrop cores Na ,Mg ,Ca ,Cl , The experiments were 2- - internal oleﬁn sulfonates SO , HCO ) 4 3 Permeability: conducted at low (IOS), alkyl benzene 195 mD temperatures (* 25 C) sulfonate (ABS), alkyl and salinity of xylene sulfonate (AXS) * 11,000 ppm TDS 0.25wt%–2.0wt% The anionic surfactant blends produced optimal salinity close to reservoir salinity and achieved oil recovery efﬁciencies of [75% at 0.5wt% of surfactant concentration Two anionic and two Siliceous and Water Crude oil viscosity: – Alvarez nonionic surfactants [0.2, 1 carbonate 30–40.5 cP; API: 35.77– et al. and 2 gallons per thousand shale cores 37.74 (2014) gallons (gpt)] Both anionic and nonionic surfactants changed the wettability of carbonate shale cores Anionic surfactants performed better than nonionic surfactants in changing contact angles in oil shale samples Anionic Guerbet alkoxy Silurian dolomite Formation brine (TDS- Crude oil viscosity: 0.5 cP, 90–94.5 Lu et al. carboxylate (GAC) (478 mD) 23,800 ppm, divalent cation API: 34 (light oil) (2014a) surfactants (0.15wt%– Estaillade concentration 3700 ppm) The GAC surfactants reduced 1.0wt%) limestone core IFT signiﬁcantly (187 mD) The GAC can act as alternatives to sulfate surfactants for high-salinity, high-temperature reservoirs where alkali is not included in the formulation Nonionic branched SACROC CO , SACROC brine (NaCl, The surfactants are more – McLendon nonylphenol ethoxylates carbonate CaCl , MgCl ) soluble in CO , thus et al. 2 2 2 (Huntsman SURFONICS cores forming stable CO -in- (2014) N-120 & Huntsman brine foams which appear Permeability: SURFONICS N-150) and to be promising CO 13–16 mD branched isotridecyl additives for mobility ethoxylate (Huntsman control SURFONICS TDA-9) They can act as appropriate surfactants candidates for EOR * 0.07wt% applications surfactants indicated that the desired wettability alteration on calcite, wetted by either heavy or light oil. The mech- is not always achieved. This ﬁnding leads to considering anism of action of C TAC on the ORF for heavy oil pri- and testing of other surfactants of cationic nature. In their marily involved oil disaggregation followed by viscosity conjoint theoretical and experimental studies, Pons-Jime- decrease. Reduction in viscosity led to the release of oil nez et al. (2014) proposed a plausible chemical mechanism that is loosely adsorbed onto the rock. However, there was involved in 36% ORF increase by the cationic surfactant no detectable wettability alteration of the carbonate dicecyltrimethylammonium chloride (C TAC) at 150 C reserves, in this case, conﬁrming that both the asphaltenes 123 Pet. Sci. (2018) 15:77–102 95 and resins of crude oils remain strongly adsorbed on the some positive results from several experimental and pilot rock surfaces, thereby maintaining the oil-wet state of ﬁeld studies, actual trials at exploration sites in a com- carbonate rocks. mercial setting are very limited (Adibhatla and Mohanty Recently, surfactant-aided gravity drainage process of oil 2008). Lack of adequate practical knowledge about sur- recovery for water- as well as gas-ﬂooded HTHS carbonate factants used in dual-porosity fractured carbonate reser- reservoirs was also tested. Sometimes, water ﬂooding fails voirs, limits their performance to a great extent (Manrique to perform successfully in heavily fractured carbonate et al. 2007). In a few cases reported for surfactant-based rocks, where large viscous gradients cannot be imposed cEOR for carbonate reservoirs, which include the Mauddud (Adibhatla and Mohanty 2008). In such cases, gas-aided carbonate reservoir of Bahrain (Zubari and Sivakumar gravity drainage is a conventional oil recovery technique. 2003), Yates ﬁeld in Texas (Yang and Wadleigh 2000), However, again when the permeability is low, the remain- Cottonwood Creek ﬁeld in Wyoming (Xie et al. 2004) and ing oil saturation in such anticline-shaped reservoirs can be the Baturaja Formation in the Semoga ﬁeld of Indonesia quite high and recovery annoyingly slow (Wang and (Rilian et al. 2008), the temperature was about 45 C and Mohanty 2013). Herein comes the surfactant (anionic, never higher. Therefore, much work remains to be nonionic and cationic) enhanced gravity drainage technique accomplished for HTHS carbonate oil reserves to establish (Srivastava and Nguyen 2010; Ren et al. 2011; Guo et al. credible production baselines and successfully capture the 2012). Cationic surfactants of the type alkyl trimethylam- recovered mobilized oil (Kiani et al. 2011). monium bromide (C TAB) efﬁciently recovered approxi- Surfactant injection EOR for an oil-wet carbonate mately 70% of OOIP by imbibing water into originally oil- reservoir might not always be successful because of several wet chalks (Standnes and Austad 2000a, b, 2003). They reasons as outlined in the works of Kiani and coworkers. were believed to form ion pairs with adsorbed organic Their experimental ﬁndings suggested that in contrast to carboxylates of the crude oil, solubilizing them into the oil the homogeneous unfractured reservoirs, the pressure gra- and thereby changing the mixed/oil-wet rock surfaces to dient in fractured formations may be too small to displace water-wet. This wettability alteration assisted in counter- oil from the matrix. At times, several high-permeable current imbibition of brine and led to increased oil recovery. fracture areas can act like ‘‘thief zones’’ and may bypass However, the major drawbacks of this method are still the smaller fractures. To overcome such challenges, use of high surfactant concentration requirement along with its mobility control agents, for example foam, may be con- cost which leads to searches for newer cheaper cationic sidered (Talebian et al. 2014, 2015). However, issues surfactants of the form C NH (Adibhatla and Mohanty similar to foam stability in the presence of oil are still a 10 2 2008). Another example of less expensive surfactants is the challenge which requires much attention. More experi- several bioderivatives of the coconut palm, termed Arquad ments on pseudo-emulsion physics and chemistry should and Dodigen (Strand et al. 2003). Several anionic surfac- be undertaken soon, where increased efforts should be tants under the commercial name Alfoterra and those made in the collection of more and more experimental data mentioned in the works of Adibhatla and Mohanty (2008) and correlating them with the stability of foams in oil- were considered for gravity-aided methods in fractured saturated carbonate reservoirs. Other parameters, such as carbonate formations. Anionic surfactants were known to salinity, temperature and wettability, must also be taken diffuse into the matrix, lower the IFT and contact angle, into account while designing future experiments. Another which in turn decreases the capillary pressure and increase important parameter, which is very often neglected in the oil relative permeability. The high relative permeability analyzing foam stability in the presence of oil, is the dis- of oil helps the gravitational force in pulling the oil out of joining pressure, which exists in very thin foam layers. For matrix (Hirasaki and Zhang 2003; Seethepalli et al 2004). optimization of foam properties in contact with the oil As usual, the adsorption of anionic surfactants on the sur- phase, studies of the disjoining pressure in the pseudo- face of calcite was suppressed with an increase in pH and a emulsion ﬁlms and its control are crucial, which remains a decrease in salinity. challenge. Some of the typical problems encountered when poly- mers are used, especially during combined ﬂooding 5 Overcoming challenges in EOR: future strategies such as ASP ﬂooding, include low injectivity or perspectives complete plugging of injection wells, degradation of polymers, incomplete polymer dissolution, and pump fail- Over the last decade, a good number of technologies have ures. Additionally, alkali and surfactant may cause corro- been advanced to overcome many of the past failures and sion, the formation of a persistent and stable emulsion unlock new areas of research for challenging carbonate between injected chemicals and oil and, most importantly, reservoirs. Nonetheless, it should be noted that despite scaling (Bataweel and Nasr-El-Din 2011; Stoll et al 2010). 123 96 Pet. Sci. (2018) 15:77–102 Mineral scales are formed by deposition from aqueous scientists studying adsorption behavior of both anionic solution of brine when they become supersaturated due to a (Ahmadall et al. 1993) and cationic surfactants (Rosen change in their thermodynamic and chemical equilibrium and Li 2001) over the calcite and dolomite surfaces i.e., ionic composition, pH, pressure and temperature arrived at the conclusion that the source of carbonate (Mackay et al. 2005). In oilﬁeld operations, scaling is material seems to have a substantial impact on surfactant principally formed by a decrease in pressure and/or an adsorption. Nevertheless, the search for newer cheaper increase in temperature of brine, which leads to the surfactants and alkalis should be taken up. Efﬁcient sur- reduction in the solubility of salts. The alkalis react with factant screening should be done for selecting the opti- 2? 2- 2- ions (Ca ,CO ,SO ) of the carbonate minerals in the mum surfactant for a system. Sometimes when a single 3 4 rock forming scales. Sometimes mixing of two incompat- surfactant fails to perform successfully for HTHS reser- ible brines (formation water rich in cations such as barium, voirs, a dual-surfactant system may be a workable calcium, strontium and sulfate-rich seawater) leads to strategy. precipitation of sulfate scales (BaSO ) (Zahedzadeh et al. Based on the recent analysis on the impact of water 2014). Scales damage well productivity by reducing per- softening on the economics of cEOR, it was found that meability, plugging production lines, and fouling equip- chemical cost can be decreased signiﬁcantly by using soft ment, which leads to production-equipment failure, sea water. Improved technologies are expected to come up emergency shutdown with increased maintenance costs and in the near future which can reduce several operational and decrease in overall production efﬁciency (Mackay and logistic issues of cEOR for carbonate reservoirs. There has Jordan 2005). A traditional commercial approach to alle- to be a life-cycle approach to cEOR, and the concept of viate scaling in the oil and gas industry is by applying energizing the reservoir deserves attention from the earliest conventional hydrophilic scale inhibitors, for example, stages of ﬁeld planning and development. PPCA (polyphosphonocarboxylic acid) and DETPMP (di- ethylenetriaminepenta (methylene phosphonic acid)) (Bezemer and Bauer 1969). However, many of these 6 Summary organic phosphates and phosphonates that are widely used as scale inhibitors are highly toxic and unacceptable envi- Fractured low-permeability carbonate reservoirs long ronmentally. Currently, new generation green scale inhi- drained by water and gas injections can have high bitors which minimize pollution associated with the remaining oil saturation. Surfactant EOR technologies manufacture and application of hazardous materials are targeted toward such reserves are considered versatile ter- being considered (Kumar et al. 2010). This study seems tiary oil recovery techniques to maximize total oil pro- promising, and future investigations in optimizing favor- duction. Presently there are an increasing number of able environment-friendly inhibitors should be encouraged ongoing and planned cEOR evaluations at pilot scales for successful elimination of this challenging problem of globally. Though several publications on surfactant-as- carbonate formations. sisted polymer, ASP, foam, microemulsions ﬂooding Another signiﬁcant difﬁculty for implementing surfac- experimental results on carbonate formations are available, tant EOR lies in its high adsorption on reservoir forma- there are very few ﬁeld cases reported. Due to very chal- tions which needs continuous surfactant re-injection, lenging conditions of temperature and salinity, the avail- rendering the designed EOR process inefﬁcient and eco- ability of proper surfactants and polymers is severe nomically infeasible. The surface chemistry of most of the limitation. Although switchable alkyl amine surfactants carbonate rocks signiﬁcantly inﬂuences surfactant show promising results in laboratory tests for foam EOR, adsorption. Complex dissolution behavior is observed in their application to ﬁeld level still requires substantial certain minerals in carbonate rocks such as dolomite effort. Surfactants and polymers for ASP, SP and polymer (CaMg (CO ) ), calcite (CaCO ) and magnesite (MgCO ) EOR applications are still not available to cater for the 3 2 3 3 (Hiorth et al. 2010). Interestingly, the isoelectric point of needs for HSHT carbonate reservoirs, though a few catio- calcite is known to be dependent on the pH and sources nic surfactants showed promising results in wettability of materials, equilibrium time and ionic strength in alteration experiments at laboratory scale. In addition to aqueous solutions (Ma et al. 2013). From their experi- that, a laboratory and a ﬁeld test show promising results but mental simulations, Vdovic and Biscan stated that under injection water used was of low salinity which seriously -3 3 the same ionic strength (10 mol/dm NaCl) within the questions the application where low-salinity injection pH range of 7–11, natural calcite (Polycarb, ECC Inter- water is not available. As polymers are the primary national) was more negatively charged than synthetic requirement for mobility control in ASP and SP schemes, calcite (Socal-U1, Solvay, UK) (Vdovic and Biscan even if the surfactants become available, unavailability of 1998). Experiments conducted by various groups of suitable polymers is also a drawback in the development of 123 Pet. Sci. (2018) 15:77–102 97 conference at oil & gas West Asia, April 11–13, Muscat, Oman, EOR projects and development of suitable polymers should 2010. doi:10.2118/129228-MS. be considered as well. 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Publisher: Springer Journals
Copyright: Copyright © 2017 by The Author(s)
Subject: Earth Sciences; Mineral Resources; Industrial Chemistry/Chemical Engineering; Industrial and Production Engineering; Energy Economics
ISSN: 1672-5107
eISSN: 1995-8226
DOI: 10.1007/s12182-017-0198-6
Publisher site: See Article on Publisher Site

Abstract

Pet. Sci. (2018) 15:77–102 https://doi.org/10.1007/s12182-017-0198-6 REVIEW PAPER Review of surfactant-assisted chemical enhanced oil recovery for carbonate reservoirs: challenges and future perspectives 1 2 1 2 • • • Sreela Pal M. Mushtaq Fawzi Banat Ali M. Al Sumaiti Received: 26 April 2017 / Published online: 4 November 2017 The Author(s) 2017. This article is an open access publication Abstract A signiﬁcant fraction of the conventional oil Keywords Oil reserves Original oil in place Carbonate reserves globally is in carbonate formations which contain formations Surfactants Chemical enhanced oil recovery a substantial amount of residual oil. Since primary and secondary recovery methods fail to yield above 20%–40% of original oil in place from these reserves, the need for 1 Introduction enhanced oil recovery (EOR) techniques for incremental oil recovery has become imperative. With the challenges Approximately one-third of the original oil in place (OOIP) presented by the highly heterogeneous carbonate rocks, is believed to be recovered by primary and secondary evaluation of tertiary-stage recovery techniques including recovery processes worldwide, leaving behind around chemical EOR (cEOR) has been a high priority for 60%–70% as remaining oil in reservoirs (Xu et al. 2017). researchers and oil producers. In this review, the latest Most of the current world oil production comes from developments in the surfactant-based cEOR techniques mature ﬁelds which contain a high percentage of residual applied in carbonate formations are discussed, contem- oil. Increasing oil recovery from these aging resources is plating the future direction of existing methodologies. In the primary concern for oil companies and authorities connection with this, the characteristics of heterogeneous globally. More than 50% of the world’s discovered oil carbonate reservoirs are outlined. Detailed discussion on reserves are in carbonate reservoirs, a large number of surfactant-led oil recovery mechanisms and related pro- which have a high degree of heterogeneity and complex cesses, such as wettability alteration, interfacial tension pore structures (Masalmeh et al. 2014). According to BP reduction, microemulsion phase behavior, surfactant Statistical Review of World Energy 2015, around 48% of adsorption and mitigation, and foams and their applications the world’s proved conventional oil reserves are in the is presented. Laboratory experiments, as well as ﬁeld study Middle East (BP 2015) nearly 70% of which are in frac- data obtained using several surfactants, are also included. tured carbonate reservoirs. This extensive discussion on the subject aims to help It is also noteworthy that more than 40% of the daily researchers and professionals in the ﬁeld to understand the world oil production comes from these carbonate reservoirs current situation and plan future enterprises accordingly. of the Middle East which are mostly mature and contain a high percentage of residual oil (Ahmadi and Shadizadeh 2013b). Typically, the majority of the carbonate reservoirs & Fawzi Banat is characterized by the presence of high-permeability fbanat@pi.ac.ae fractures and low-permeability matrix. This contrast in permeability makes them challenging targets for chemical Department of Chemical Engineering, Khalifa University of Science and Technology, SAN Campus, Abu Dhabi, UAE ﬂooding. Also, some of these carbonate formations have high reservoir temperatures and contain high salinity for- Department of Petroleum Engineering, Khalifa University of Science and Technology, SAN Campus, Abu Dhabi, UAE mation brine (Lu et al. 2014b). These multiple attributes coupled with their complex wettability conditions, i.e., oil- Edited by Yan-Hua Sun 123 78 Pet. Sci. (2018) 15:77–102 wet/mixed-wet surfaces, complicate reservoir characteri- undoubtedly guide future researchers and practitioners in zation, production and management (Hirasaki and Zhang the ﬁeld toward identifying newer technologies and 2003). As a result, the oil recovery factors (ORF) in these upgrading existing methodologies for successful ﬁeld reservoirs are very low, probably below 30% on an average implementation. (Hognesen et al. 2005). Implementation of chemical enhanced oil recovery (cEOR) processes is highly dependent on the oil and 2 Heterogeneity and characteristics of carbonate chemical prices, and hence, research and investment in this reservoirs ﬁeld are decidedly governed by the economy of the country. Despite these challenges, extensive laboratory Carbonate reservoirs present a picture of extremes. Most of research along with some ﬁeld demonstration projects them are highly heterogeneous regarding their geological support the fact that there lies an enormous potential for and petrophysical features that clearly distinguish them chemicals in enhancing oil recovery from carbonate for- from sandstone reservoirs. They typically possess some mations. With cEOR, targeting more and more challenging distinct characteristics, which challenge oil recovery and reservoirs, especially using surfactants is becoming a extraction. Normally, carbonate rocks have a complex reality (Lu et al. 2014a). During the last two decades, a texture and pore network, emanating from their deposi- considerable number of EOR ﬁeld projects in carbonate tional history and later diagenesis. Most of the carbonate reservoirs have been documented (Alvarado and Manrique reservoirs are naturally fractured with extremes in fracture 2010) of which the Yates ﬁeld (Texas) is a good example length varying from small ﬁssures to kilometers. These where different EOR processes were successfully trialed at fractures may signiﬁcantly inﬂuence ﬂuid movement to different levels, from pilot to large-scale applications. speciﬁc paths and hugely impact on the production per- Several variations to conventional surfactant ﬂooding formance. For example, highly fractured reservoirs can methods, such as the combined surfactant–polymer (SP) experience early water or gas breakthrough due to chan- technologies and the alkali–surfactant–polymer (ASP) neling of ﬂuids along fractures. However, fractures are ﬂoods that boost oil production, especially in the mature beneﬁcial in tight formations where matrix permeability is water-ﬂooded carbonate ﬁelds, have been the subject of signiﬁcantly low, and most of the ﬂuid movement is only much introspection lately (Kiani et al. 2011). Due to through fractures. Therefore, characterization and under- technical difﬁculties, chemical-based EOR methods have standing the behavior of ﬂuid or gas ﬂow through fractures never been very popular for signiﬁcantly enhanced oil is essential for a successful ﬁeld development. production from carbonate reservoirs. Nevertheless, sur- Most carbonate rocks are formed by biological activity, factant-based cEOR technologies have been implemented developing from the biogenic sediments gathered during as chemical well stimulators, wettability altering agents, reef building and accumulation of the remains of organisms microemulsion, and foam-generating agents consistently on the seabed. Other types originate from evaporation of (Andrianov et al. 2012; Simjoo et al. 2013; Wang and water from shallow onshore basins or as precipitates from Mohanty 2013). Currently, this is an area of intense seawater (Akbar et al. 2000). They consist of limited research (Ahmadi and Shadizadeh 2012; Bera et al. 2012; groups of minerals predominantly calcite and dolomite. Zendehboudi et al. 2013; Bourbiaux et al. 2014; Santvoort Sometimes, minerals such as glauconite and secondary and Golombok 2015). minerals including quartz, clay, pyrite, siderite, ankerite, The present review is aimed at: anhydride and chert are also less commonly present (Lucia 2007). (a) Studying the heterogeneity and characteristics of Usually carbonate rocks are differentiated by factors carbonate reservoirs, such as depositional texture, grain or pore size, rock fabric (b) Discussing the current status of the different surfac- or diagenesis following some classiﬁcation schemes put tant-based cEOR methods applied in carbonate forward by different groups of scientists (Lucia 2007; reservoirs documenting several ﬁeld EOR projects Embry and Klovan 1971). Heterogeneity may exist at all in carbonate reservoirs, levels—in pores, grains and also in textures. The porosities (c) Summarizing the evolution of various surfactant of carbonate rocks are usually classiﬁed into three cate- types for application in different carbonate reservoirs gories: (a) connected porosity—this porosity lies between over the years and, ﬁnally, carbonate grains (b) vugs—they are unconnected pores that (d) Evaluating the challenges and debating the future of arise from the dissolution of calcite by water during dia- surfactant EOR technology for these reservoirs. genesis and ﬁnally (c) fracture porosity—stresses cause Since carbonate reservoirs are at the leading area of this subsequent texture. Together these porosities create a research currently, this comprehensive review will difﬁcult path for liquid ﬂow and precisely affect well 123 Pet. Sci. (2018) 15:77–102 79 productivity. Diagenesis of carbonate rocks signiﬁcantly concentration pure surfactants (such as ethoxylated alco- modiﬁes the pore spaces and permeability (Akbar et al. hols) in injected water was also seen to improve oil 2000). recovery in oil-wet carbonate reservoirs, presumably by Apart from porosities, wettability is another heteroge- enhancing imbibition through wettability alteration and neous characteristic in carbonate rocks. Most of the car- lowering of the interfacial tension (IFT). Such simple bonate reservoirs are found to be mixed-wet or oil-wet surfactant systems were considered viable due to low sur- (Chilingar and Yen 1983). At times, strongly oil-wet car- factant concentration requirement along with associated bonate formations leave behind a high water-ﬂooded low adsorption (Yang and Wadleigh 2000; Xie et al. 2004; residual oil saturation and have unfavorable mobility ratios. Seethepalli et al. 2004). Additionally, they exhibit capillary resistance to imbibition of water (Anderson 1987). Hence, oil remains adhered to 3.1 Foams, wettability alteration and lowering the surface of the carbonate rocks, and it becomes harder to of interfacial tension by surfactants recover the entrapped residual oil. Different surfactant- based cEOR technologies targeted primarily toward car- Surfactants play a leading role in foam generation, wetta- bonate reservoirs have been tried over the last two decades. bility alteration and lowering of oil–water interfacial ten- In the following sections, we will discuss some of the well- sion (IFT) processes. practiced surfactant-based EOR ﬂooding methodologies. Foams are employed for mobility control in situations where polymers, gas or water alternating gas injection schemes are not feasible due to unfavorable conditions, 3 Surfactant ﬂooding processes for chemical EOR such as low permeability, formation heterogeneity and high in carbonate reservoirs temperature–high salinity conditions beyond the polymer stability window. Foam injection has advantages over For decades, substantial efforts have been made to use simple gas injection, and it is demonstrated that the use of surfactant injection as a post-waterﬂood process for foam can mitigate gas channeling, improve apparent gas recovering entrapped oil from conventional mature reser- density and hinder gas escape through high-permeability voirs. Designing and optimizing suitable surfactant ﬂood zones to achieve good oil recovery (Julio and Emanuel for effective cEOR has always been very challenging and 1989; Huh and Rossen 2008; Lee et al. 1991; Schramm and forever evolving. It is one of the robust and high-perfor- Wassmuth 1994). Foams are reviewed in detail in mance cEOR methods, which has been widely studied in Sect. 3.4.3. the past decades because of its ability to alter wettability of 3.1.1 Wettability alteration carbonate reservoirs from the oil/mixed-wet to the water- wet surfaces, lower interfacial tension (IFT) and produce the oil entrapped in these formations (Hill et al. 1973; Yang Wettability is long recognized as an important factor that and Wadleigh 2000; Webb et al. 2005; Farajzadeh et al. strongly affects oil recovery in naturally hydrophobic car- 2010; Barnes et al. 2012; Ahmadi and Shadizadeh 2013a). bonate reservoirs implementing cEOR methods. Wettabil- The idea of adding surfactants to injected water for ity is deﬁned as the preferential tendency of a ﬂuid to reducing oil/water IFT and/or alter wettability thereby spread onto a solid phase in the presence of other immis- increasing oil recovery from reservoirs dates back to the cible ﬂuids. Generally, for an oil/water system, wettability early 1900s (Uren and Fahmy 1927). A similar long-held can be deﬁned according to the contact angle; if the contact concept for improving oil recovery was the in situ gener- angle is 0–75, the rock is water wet; if 75–115,it is ation of surfactants by injection of an alkaline solution intermediate and with an angle of 115–180, the rock will (Howard 1927). Though this method provided a compara- be oil wet (Anderson 1986). tively cheap in situ surfactant production technology by Wettability alteration is supremely important for natu- conversion of the naphthenic acids in crude oil to soaps, rally fractured carbonate reservoirs (NFCRs), where pri- this was not immediately accepted due to poorly under- mary and secondary processes usually fail to mobilize oil stood process mechanisms (Johnson 1976). that remains locked tightly due to capillarity. Moreover, From 1960 onwards, surfactant technology advanced most of the oil in NFCRs is contained in the low-perme- signiﬁcantly based on two different approaches. The sur- ability matrix. As the viscous forces in these heterogeneous factants were either synthesized by direct sulfonation of systems are inefﬁcient to sweep matrix oil, an imbibition aromatic groups present in reﬁnery streams/crude oils or by process remains as the most reliable mechanism to reach the organic synthesis of alkyl/aryl sulfonates with the aim for the oil. of manufacturing tailored surfactants for the reservoir of Depending upon their hydrophilic head charges (an- interest (Hirasaki et al. 2008). Similarly, use of low- ionic/cationic) and the charges on the rock surfaces, 123 80 Pet. Sci. (2018) 15:77–102 surfactants may alter the wettability of reservoir surfaces. surfactant double layer cannot be regarded as a permanent There are two mechanisms of wettability alteration by wettability alteration of the calcite, because due to the surfactants cited in the literature (Standnes and Austad weak hydrophobic bond between the surfactant and the 2000b). The ﬁrst is the removal of the oil-wet layer hydrophobic surface, the process is entirely reversible. exposing the underlying originally water-wet surfaces Nonionic surfactants, for example, ethoxylate C –C 9 11 (cationic), while the second is setting up of a water-wet linear primary alcohol was also tested for its ability to layer over the oil-wet layer (anionic). For carbonates, change the wettability of dolomite surfaces using contact cationic C TAB surfactants at concentrations equal or angle with Yates crude oil (Vijapurapu and Rao 2004). The greater than the critical micelle concentration (CMC) alter advancing contact angle reduction suggested that the non- wettability better than anionic surfactants (Standnes and ionic surfactant effectively altered the strongly oil-wet Austad 2000b). However, other researchers have stated that nature (advancing angle of 156) to the water-wet state no apparent correlation exists between oil recovery and (advancing angle of 39). CMC (Wu et al. 2008). From the works of Standnes and Austad (2003), it was 3.1.2 Interfacial tension found that ion pair interaction is a possible mechanism of wettability alteration by cationic surfactant type C TAB Interfacial tension (IFT) is one of the primary considera- (where n is the number of carbon atoms). According to tions in alkali–surfactant ﬂooding cEOR processes. In oil them, the mechanism of wettability alteration was ration- reservoirs, the interplay of three types of forces, capillary, ally attributed to the formation of ion pairs between the gravitational and viscous forces, controls the extent and cationic surfactant and the negatively charged carboxylates rate of oil recovery. To best describe the relationship in oil. In addition to the electrostatic forces, hydrophobic between these forces, there are two useful numbers—the interactions were also believed to stabilize this ion pair Bond number (N , which presents the ratio of gravitational complex. The ion pairs were insoluble in the water phase forces to capillary forces) and capillary number (N , which but were found to be soluble in the oil phase or the presents the ratio of viscous forces to capillary forces) as micelles. The ion pair solubility in oil causes water to outlined below: penetrate into the pore system, with the subsequent Gravitational forces N ¼ ð1Þ expulsion of oil from the pore through connected pores Capillary force with high oil saturation in a so-called counter-current ﬂow Viscous forces mode. Hence, as the adsorbed organic material released N ¼ ð2Þ Capillary forces from the calcite surface, it became more water-wet. Anionic surfactants, in general, do not possess the 2r cos h ow c Capillary forces F ¼ ð3Þ ability to alter the wettability of calcite surfaces, even though they can achieve a very low IFT. However, Gravitional forces F ¼ Dqgh ð4Þ ethoxylated sulfonates with high numbers of ethylene where r is the oil–water interfacial tension, N/m; r is the oxide (EO) units, displaced oil spontaneously in a slow ow pore radius; and h is the contact angle. process (Standnes and Austad 2003). The proposed The denominator in both of these numbers is the cap- mechanism in this case probably involves the formation of illary force, which is a function of the IFT between oil and a water-wet bilayer between the oil and the hydrophobic water, surface wettability represented by the contact angle calcite surface. An anionic surfactant with a large (h ) and the pore radius (r). Viscous forces cannot be hydrophobic group such as ethoxylated sulfonates of the c applied efﬁciently for heterogeneous oil-wet NFCRs due to type R-(EO) -SO (x = 3–15) supposedly adsorbed onto x 3 the hydrophobic calcite surface forming a double layer and a high-pore-volume matrix which possesses low perme- ability and a much lower volume fracture system that creating a hydrophilic surface. The water-soluble head group of the surfactant EO-group and the anionic sulfonate controls the ﬂow of viscous displacement. Fluid dynamics in this type of reservoir is controlled by the Bond number could decrease the contact angle below 90, forming a (N ). Depending upon the contact angle (h ) (wettability of small water layer between the oil and the organic coated B c rock), the value of the capillary forces may be reversed surface. As a result, weak capillary forces were created, from negative to positive ﬁgures. For oil-wet cores, the and some spontaneous imbibition of water could occur. contact angle of water with rock being greater than 115, From their experiments, Austad and Standnes showed that no capillary imbibition takes place. According to Morrow the ﬂuid distribution inside the core of the C –(EO) – 12–14 15 and Mason, the ratio of gravitational forces to capillary SO surfactant system was non-uniform, possibly due to force is signiﬁcantly important and lowering of IFT may some inhomogeneity in wetting or core properties (Stand- nes and Austad 2003). However, the formation of a positively or negatively affect imbibition (Morrow and 123 Pet. Sci. (2018) 15:77–102 81 Mason 2001). Even when lowering of IFT reduces capil- alteration by surfactant that enhanced capillary imbibition. lary imbibition, imbibition may occur due to the gravita- Cationic surfactants function to change wettability to the tional forces. Capillary imbibition can be initiated and extent that it induces capillary spontaneous imbibition maintained as long as the IFT is not reduced below certain (Standnes and Austad 2000b). On the other hand, alkaline critical values. The interplay between gravitational and anionic surfactants reduce the negative capillary forces capillary forces greatly depends on the IFT value. signiﬁcantly. Some anionic surfactants can lower IFT to For oil-wet carbonate systems, the capillary pressure is ultra-low values where the capillary pressure is nearly zero. usually negative, and as a result, water does not imbibe From the simulation results of a dynamic imbibition pro- spontaneously into the porous medium as oil is ﬁrmly cess study, it was found that the transverse pressure gra- attached to the rock surface by capillarity. By reducing the dients between the fracture and matrix at times pushed the IFT by the use of surfactants, the adhesive forces that retain surfactant further into the matrix (Asl et al. 2010). Hence, oil by capillarity are weakened. Due to lowering of IFT, gravitational forces became active, and oil was recovered capillary trapping is reduced, and this causes oil droplets to by gravity-induced imbibition (Hirasaki and Zhang 2003). ﬂow more smoothly through pore throats and merge with oil down the stream to form an oil bank (Sheng 2015). 3.2 Microemulsion phase behavior of surfactants Lowering of IFT between oil and brine and combination of speciﬁc conditions of temperature and salinity lead to the Microemulsions are thermodynamically stable, homoge- generation of microemulsions. Microemulsions play a vital neous dispersions of two immiscible ﬂuids, generally, role in chemical EOR and are reviewed in next section. hydrocarbons and water stabilized with surfactant mole- Recent spontaneous imbibition studies by Mohammed cules, either alone or mixed with a co-surfactant (Schwuger and Babadagli, for two limestone core samples exposed to et al. 1995). They possess the ability to reduce IFT between two different aqueous phases, distilled water, and 1.0wt% oil and water to an ultra-low value and also can alter the of cationic surfactant C TAB came up with some wettability of reservoir rocks (Zhu et al. 2003). The prin- notable results (Mohammed and Babadagli 2014). The cipal constituents of microemulsions are the surfactants spontaneous imbibition curve indicated the oil-wet nature adsorbed at the interphase rather than in the bulk phase. of the core samples and the negative capillary forces The IFT values between microemulsion and crude oil; and resisted the gravitational forces when the core samples between microemulsion and water are very low, typically -3 were exposed to distilled water. A similar trend was in the range of 10 mN/m. observed for a core sample exposed to the surfactant The IFT behavior of microemulsions is best described solution initially (for 10 days), indicating slow recovery. by examining the phase behavior of the surfactants/co- Nevertheless, after 10 days, a sudden hike in recovery was surfactant–brine–oil system. IFT behavior is believed to be observed, which was possibly due to the wettability a key factor in predicting the performance of oil recovery Surfactant HLB, oil ACN Oil 1 23 4 5 6 7 Microemulsion Water No emulsion Type I Type III Type II Salinity, temperature, co-surfactant, surfactant, surfactant molecular weight, brine-oil ratio Fig. 1 Microemulsion phase behavior of surfactants-water-oil as a function of different variables 123 82 Pet. Sci. (2018) 15:77–102 by the microemulsion ﬂooding process (Kayali et al. 2010). pure EO nonionic surfactants. Increasing the number of EO Essential concepts and details on the phase behavior of units in a surfactant molecule makes it more hydrophilic; microemulsion systems have been presented by Winsor and hence, it can withstand high salinity and temperature to later, others (Winsor 1956; Schwuger et al. 1995). achieve its optimum functionality, a character highly Depending on the surfactant type, the microemulsion phase desirable for high-temperature high-salinity carbonate behavior changes from Winsor I (lower phase) to Winsor reservoirs (Hussain et al. 1997). On the other hand, the III (middle phase) to Winsor II (upper phase) by varying addition of PO units will add mild hydrophobic character, the following conditions: (1) salinity increase, (2) alcohol which can help achieving high solubilization of oil and (co-surfactant) concentration increase, (3) surfactant brine phases. molecular weight increase, (4) oil chain length (alkane carbon number, ACN) decrease, (5) temperature change, 3.2.2 Effect of salinity and temperature on IFT behavior (6) total surfactant concentration increase, (7) surfactant solution/oil ratio increase, (8) surfactant hydrophile-lipo- Salinity has a strong inﬂuence over different microemul- phile balance (HLB) decrease, (9) brine/oil ratio increase, sion structures, which in turn affects the carbonate rock as depicted in Fig. 1 (Salager et al. 2005). wettability behavior. From the studies of Dantas et al. (2014), it is noticed that with an increase in salinity , there 3.2.1 Effect of surfactant structure on IFT behavior is a decrease in wettability inversion from oil-wet/mixed- wet to water-wet surfaces. However, due to the continuous Achieving ultra-low IFT is essential for mobilizing the oil phase of reverse microemulsions, they exhibit favorable residual oil in reservoir rocks and reducing the oil satura- interactions between the oil phase and the oil contained in tion toward zero under normal pressure gradients in oil carbonate rocks with better wettability results, reducing the reservoirs. Surfactants with large hydrophobes are not IFT and consequently enhancing oil displacement from the salinity tolerant. However, the addition of large ethylene rock pores. For bicontinuous microemulsions, an increase oxide and propylene oxide groups may help to achieve in salinity (within an acceptable range for bicontinuous required salinity tolerance. These surfactants with bulky emulsion phases) improved the limestone rock wettability hydrocarbon chains may form high solubilization ratios on water for anionic (SDS) and nonionic (UNT90) sur- when compared to similar counterparts with relatively factants and increased wettability for cationic (cetyl tri- shorter hydrocarbon chains in their structures. In general, methyl ammonium bromide, CTAB) surfactants. The when all other parameters are constant, the longer the wettability alteration to water-wet conditions inﬂuenced hydrocarbon tail in the surfactant structure, the lower will the oil recovery efﬁciency in the order of CTAB [ SD- S & UNT90 facilitating the oil displacement. be the optimum salinity. To transport surfactant solutions under low pressure The temperature of a reservoir is a signiﬁcant parameter gradients, a condition typical in carbonate reservoirs, when surfactant performance is evaluated. A high-tem- highly viscous phases must be avoided, because they result perature, high-salinity reservoir presents severe challenges in high surfactant retention and ultimately poor recovery. regarding surfactant compatibility and stability in brine. Using surfactants with branched hydrophobes could be a However, surfactant adsorption may decrease at high possible solution for abating this problem of viscosity. temperature conditions for highly soluble surfactants, and, Likewise, the addition of propylene oxide (PO) and ethy- on the other hand, poor solubility may lead to high lene oxide (EO) units to sulfate surfactant molecules helps adsorption values. Typically, the surfactants working at in increasing solubilization of the microemulsion phase higher temperature systems show high optimum salinity with a broader region of low IFT due to the interphase (Shah 1981). As longer surfactant hydrophobes require low afﬁnity of the groups. Improved calcium tolerance is an optimum salinity at a particular temperature, usually a additional beneﬁt (Salager et al. 2005). From the studies of heavy hydrocarbon surfactant is needed for high tempera- Hussain et al. (1997), it was found that the presence of an ture conditions and relatively low salinity situations. EO moiety in the surfactant molecule made the surfactant However, there are some exceptions also reported, where less sensitive to salinity than an anionic surfactant. Salinity surfactants (long chain IOS) show low optimum salinity at and surfactant concentration inﬂuence the surfactant high temperature conditions (Barnes et al. 2008). retention in reservoir rocks. Surfactant adsorption is pos- When all the other parameters are kept constant, under a sibly one of the most restrictive factors that affect the oil low water content, the microemulsion system is oil-exter- recovery efﬁciency by microemulsion ﬂooding (Glover nal (reversed), while under a high water content, the system et al. 1979; Hussain et al. 1997) and will be reviewed in is water-external (direct). As the mature carbonate reser- detail shortly. The carboxylic ionic head group-containing voirs of the Middle East are mostly water-ﬂooded, the surfactants are more stable to temperature changes than microemulsions designed for them are a water external 123 Pet. Sci. (2018) 15:77–102 83 system (Winsor Type I) with oil solubilized in the core of cases, are expensive chemicals. During chemical ﬂooding the micelles. However, as salinity plays a signiﬁcant role in process, surfactant loss is common which inevitably redu- reversing the structure of the microemulsion, with an ces the surfactant availability to mobilize trapped oil. increase in salinity, the direct microemulsion structure Different processes act simultaneously for this loss. One of changes to reverse microemulsion (water dispersed in oil) the main processes is surfactant adsorption onto the surface system (Sheng 2010). At lower temperature, the viscosity of the rock. Other processes include precipitation of sur- of the microemulsion system increases with increasing factants and phase trapping. water content, creating swollen micelles or other undesired Surfactant adsorption and loss have been studied structures. The magnitude of this viscosity change of the extensively (Ahmadall et al. 1993; Lv et al. 2011; Soma- microemulsion system (displacing ﬂuid) relative to the oil sundaran and Zhang 2006). Due to high surfactant costs, (displaced ﬂuid) may become important design variables surfactant adsorption is considered as one of the key pro- that affect the volumetric displacement efﬁciency, affect- cesses which deﬁne the overall chemical EOR performance ing the overall oil recovery efﬁciencies (Bera and Mandal and its economic feasibility by determining the total 2015). However, in general terms, microemulsions or amount of surfactant required for the EOR process (Le- emulsions are scarcely designed and used for viscosity- febvre et al. 2012; Tay et al. 2015). Many factors may based applications in reservoirs. The primary reason is the affect the adsorption process such as oil saturation, rock adverse effects of viscous phases, such as high surfactant mineralogy, especially clay contents, reservoir tempera- retention, high IFT, fragile structure and plugging tenden- ture, the salinity of formation water, divalent cations, ion cies under certain conditions. exchange process and surfactant structure. When the sur- factant adsorption control is considered, almost all other 3.2.3 Co-surfactants parameters are controlled by reservoir conditions, and only the surfactant structure is the available option to control The co-surfactants used in microemulsions are alkanols, with salinity of reservoir when using the salinity gradient which are medium chain alcohols such as propanol, buta- technique, which will be discussed shortly. nol, isoamyl alcohol, pentanol, hexanol and so forth Phase trapping, on the other hand, is the migration of (Barakat et al. 1983). It is considered that these co-solvents surfactants to the oil phase or in the microemulsion phase. have well-documented roles in microemulsion-based EOR The surfactant may transfer to the oil phase due to high applications (Pattarino et al. 2000; Zhou and Rhue 2000). temperature, high salinity, and high-divalent ions. Combine Some of the functions include: effect of these conditions may lead to surfactant loss, and ultra-low IFT conditions cannot be met. (a) Preventing the formation of gel-like or polymer-rich Surfactant adsorption may follow several mechanisms. phases, which may separate out from the surfactant Zhang and Somasundaran (2006) discussed several mech- solution. The alcohol used in these formulations act anisms for surfactant adsorption. Important are electrostatic as a co-solvent and partitions itself among the bulk interactions between the surfactant and the solid surface. oil and brine phases making the ﬁlms less rigid and These interactions are between the charged head (positive thereby preventing the formation of undesirable in cationic; and negative in anionic surfactants) and the viscous phases and emulsions (Sahni et al. 2010). rock surface. In addition to those, the lateral interactions of (b) Alteration of the viscosity of the system, hydrocarbon chains are also involved in surfactant (c) Increasing the mobility of the hydrocarbon tail, adsorption after the ﬁrst phase of surfactant head-rock thereby allowing for greater penetration of the oil surface adsorption is accomplished. Another important into the region. mechanism is the reduction of the solubility of surfactants (d) Modiﬁcation of the hydrophilic-lipophilic balance in the aqueous phase due to an increase in salinity or (HLB) values of the surfactants. However, a signif- temperature. icant disadvantage of using an alcohol co-solvent With an understanding of the mechanism of surfactant lies in the fact that it decreases solubilization of oil adsorption, several strategies were proposed and tried for and water in microemulsions, increasing the mini- surfactant adsorption control. These include the use of mum value of achievable IFT for a given surfactant. cationic surfactants, alkali, salinity gradient and adsorption inhibitors. 3.3 Surfactant adsorption process on carbonates As electrostatic interactions play a leading role in sur- and its mitigation and management factant adsorption (Somasundaran and Hanna 1977), it is suggested in the literature that cationic surfactant adsorp- In challenging conditions of carbonate reservoirs, high- tion is less compared to anionic surfactants (Ahmadall performance surfactants are required which, in most of the et al. 1993). However, Ma et al. (2013) reported that the 123 84 Pet. Sci. (2018) 15:77–102 adsorption of cationic surfactants might lead to signiﬁ- surfactants on carbonate and clay minerals while it was not cantly high levels when the rock contains other minerals as effective on sandstones (ShamsiJazeyi et al. 2014a, b). In well. They reported a stronger adsorption of hexadecyl another study, calcium lignosulfonate was evaluated for its pyridinium chloride on natural carbonates (containing sil- adsorption properties on limestones (Bai and Grigg 2005). icon and aluminum) than on synthetic carbonates (highly It was reported that calcium lignosulfonate followed pure calcite). In their study, they found sodium dodecyl pseudo-second-order kinetics and its adsorption increased sulfate (SDS) was adsorbed comparatively less than hex- with the salinity increase. Moreover, the desorption process adecyl pyridinium chloride on carbonate surfaces. Simi- was slow which makes it an excellent sacriﬁcial agent to larly, Rosen and Li explained the adsorption of double reduce surfactant adsorption. chain (Gemini) surfactants and conventional single chain surfactants on limestones (Rosen and Li 2001). The 3.4 Surfactant ﬂooding adsorption of Gemini surfactants was high, despite having a similar charge on the head group. They attributed this Historically, as well as in present-day research, the primary strong adsorption to the relatively high bulk of the carbon focus of surfactant use in EOR is their microemulsion- chain and hydrophobic interaction between the chains. In producing ability with crude oil in the presence of brine addition to that, they reported that molar absorption of and generating stable foams with gas. Recently, however, anionic surfactants was relatively lower than for cationic their capabilities of wettability alteration have also been surfactants (Rosen and Li 2001). These reports suggest that given much focus in EOR research. cationic surfactants are not the only solution to the problem As the microemulsion proceeds in the reservoir, it col- of high surfactant adsorption on carbonates. Moreover, the lects oil, forming an oil bank during the process. This oil adsorption on the carbonate surface is highly dependent on bank then pushed to the production well by using polymer the salinity and the presence of impurities on the surface of drive. Foams, on the other hand, are used as mobility the rock. control agents when polymers fail due to salinity, tem- In another proposed approach, a salinity gradient is perature or permeability limitations. suggested by Hirasaki et al. (1983). In this method, a slug of surfactant (S, SP or ASP) is injected and then followed 3.4.1 Alkali–surfactant ﬂooding by low salinity brine injection. Therefore, high salinity formation brine is ﬁrst replaced by optimum salinity brine, The concept of combined injection of alkali and surfactants and then, optimum salinity brine is replaced by low salinity was once thought to be one of the most promising ﬂooding brine. In the start of injection, a Type II microemulsion methods for enhanced oil recovery. Low-cost alkaline agents, such as sodium hydroxide and sodium carbonate, phase is generated which eventually changed to optimum Type III phase microemulsion due to the attaining of low were being used together with many kinds of surfactants to salinity conditions. In the last stage, low salinity brings the enhance the oil recovery efﬁciency. In an alkali–surfactant Type I microemulsion. It is suggested that both Type II and process, the primary role of the alkali is to reduce Type III show high retention while the following Type I adsorption of surfactant on the rock surface sequestering shows low adsorption thus completing the process. The divalent ions. Additionally, alkali injection also generates associated problems with this approach are the possibility in situ surfactants from the naphthenic acids of crude oil of inappropriate mixing of brines in the reservoir, avail- (Johnson 1976). However, application of alkali is not free ability of low-salinity brine in the ﬁeld and logistic issues. of problems and challenges such as scaling and production It is also important to note that the salinity gradient effect of highly stable emulsions (Zhu et al. 2012). has not been studied in carbonate rocks (Tay et al. 2015). Early work on surfactant–alkali ﬂooding was docu- More recently, adsorption inhibitors and sacriﬁcial mented in the literature (Mayer et al. 1983; McCafferty and agents are also proposed by many researchers to mitigate McClaﬁn 1992; Falls et al. 1994). However, this cEOR the adsorption problems (Tabary et al. 2012; ShamsiJazeyi technique was mostly carried out in sandstone reservoirs et al. 2014a, b; Delamaide et al. 2015; He et al. 2015; Tay for producing medium and light oils (Wang et al. 2010). et al. 2015). These are chemicals which preferentially From the review of Alvarado and Manrique 2010, it was adsorb on the surface thereby reducing the chances of seen that out of the 1507 international EOR projects; most adsorption of expensive surfactants. In recent studies, it is applications were in sandstone reservoirs. The recovery reported that polyelectrolytes such as polystyrene sulfonate factor of this process was mostly small, especially for and polyacrylate may preferentially bind the available sites fractured carbonate formations, probably due to unfavor- on the rock surface and reduce surfactant adsorption sig- able mobility ratios. niﬁcantly. ShamsiJazeyi et al. reported that sodium poly- Four proposed mechanisms of alkaline ﬂooding for acrylate successfully reduced the adsorption of anionic enhanced oil recovery were summarized by Johnsen and 123 Pet. Sci. (2018) 15:77–102 85 later by Sheng 2013. These are emulsiﬁcation-entrainment, approach came to be known as ‘‘alkali–surfactant–poly- emulsiﬁcation-entrapment, wettability reversal, and emul- mer’’ (ASP) ﬂooding or surfactant–polymer ﬂooding (SP) siﬁcation-coalescence, of which emulsiﬁcation is possibly depending on the contents of the injection slug. From its the most important mechanism (Sheng 2011, 2013). Dif- initiation, the ASP method has been identiﬁed as a cost- ferent types of emulsions are formed when residual oil effective cEOR process, yielding high recovery rate, comes into contact with the alkaline ﬂooding ﬂuid under mostly for sandstones and to a limited extent for carbonate different reservoir conditions (Bai et al. 2014). When low reservoirs (Olajire 2014). ASP for carbonate reservoirs viscosity direct (O/W) emulsion is formed, it can quickly received little focus until the last few years. Reasons ﬂood out through pore throats, consequently enhancing the include: the high-divalent-ion environment of the carbon- displacement efﬁciency, as observed in the works of Jen- ate reservoirs leads to the formation of calcium and mag- nings et al. (1974). A possible explanation for this obser- nesium sulfonates with the typical commercially available vation could be that the direct (O/W) emulsions dampened surfactants (alkyl/aryl sulfonates) that either precipitate or viscous ﬁngering and improved sweep efﬁciencies. Similar partition out into the oil phase (Liu et al. 2008). An observation was also reported in the works of Symonds exception to this observation was reported in the early et al., where depending upon the concentration of the works of Adams and Schievelbein 1987, who demonstrated NaOH solution, two different mechanisms (emulsiﬁcation- that oil could be displaced from a carbonate reservoir using entrainment and emulsiﬁcation-entrapment) for improved a mixture of petroleum sulfonates and alkyl ether sulfates oil recovery was noticed (Symonds et al. 1991). or alkyl/aryl ether sulfates. As stated earlier, surfactant plays a pivotal role in Use of cationic surfactants for promoting desorption of microemulsion formation, and among all surfactants, acids from carbonate rock surfaces and making the rock anionic surfactants are the most well-known and widely more water-wet was proposed by Standnes and Austad used surfactants in oil recovery (Liu et al. 2008). The (2003). Similarly, other researchers of the time (Xie et al. domain of cationic surfactant-based microemulsion meth- 2004; Chen et al. 2000) investigated the effectiveness of ods is still less explored, and this could be a future area of various other surfactants in altering wettability. Their research for scientists targeting enhanced oil recovery from studies suggested that ASP solutions could be injected into carbonate reservoirs. There are few literature reports carbonate formations to increase oil recovery. Related available on the application of cationic surfactant-based experimental approaches and simulations of the perfor- microemulsions in EOR. In a study, Zhu et al. 2009, mance of ASP under ﬁeld conditions were pursued reported the use of a mixture of Triton X 100 (nonionic) (Seethepalli et al. 2004; Adibhatia et al. 2005). Of late, and cetyl trimethyl ammonium bromide (CTAB) (cationic) other studies reported combination ﬂooding using polymers microemulsion in lowering IFT between crude oil and the and surfactants for high-temperature, high-salinity car- aqueous phase (brine) for additional oil recovery. Recent bonate reservoirs of Indonesia KS oilﬁelds (Zhu et al. investigations show that cationic surfactants, for example 2013). They used two competent polymers, namely CTAB, perform better than anionic surfactants in wetta- STARPAM and KYPAM with suitable viscosifying abili- bility alteration of carbonate rocks to more water wet ties along with two surfactants, AS-13 (amphoteric) and (Saleh et al. 2008). SPS1708 (anionic-nonionic) for a weak alkaline ASP sys- Again, when the reverse (W/O) emulsions are formed, tem. These systems could reduce the IFT to ultra-low -3 due to their high viscosity, they block the water channels levels (10 mN/m) within a wide range of alkalinity and pore throats in the process of migration (Kang et al. (0.2wt%–1.0wt% Na CO ). The addition of sodium car- 2 3 2011). This phenomenon is particularly relevant for heavy bonate as an alkali markedly reduced the adsorption of oil recovery as observed in the works of Pei et al. (2011), anionic surfactants over the calcite and dolomite surfaces, and later, by Dong et al. (2012). A bank of viscous (W/O) diminishing one of the very typical problems of surfactant emulsion forms when an acidic heavy oil is displaced by an adsorption and thus making the process applicable for alkaline solution prepared in a high-salinity brine in a carbonate formations (Hirasaki and Zhang 2003). They porous medium. This emulsion plugs the growing water also conﬁrmed that carbonate precipitates did not affect ﬁngers and channels and diverts the ﬂow to an initially permeability to a great extent, which was discussed in a unswept area resulting in a dramatic rise in the corre- previous study by Cheng (1986). In addition to that, car- sponding sweep efﬁciency (Ge et al. 2012). bonate/bicarbonate ions are potential determining ions on carbonate rocks and can shift the zeta potential to a more 3.4.2 Alkali–surfactant–polymer ﬂooding negative value. More negative zeta potential can inﬂuence the water wetness of rock which promotes oil displace- Adding a polymer to the surfactant solution or alkali–sur- ment. Furthermore, alkalis injected in ASP processes also factant solution improves its sweep efﬁciency. This generate soap in situ by reaction between the alkali and 123 86 Pet. Sci. (2018) 15:77–102 naphthenic acids in the crude oil, which forms an oil-rich streaks, and gravity override are frequent (Hanssen et al. colloidal dispersion as mentioned earlier (Johnson 1976). 1994). One of the strategies to meet these challenges is to The local ratio of this soap/surfactant determines the utilize foam, a dispersion of gas in a continuous liquid that optimal salinity for minimum IFT (Hirasaki et al. 2008). lowers the mobility ratio. Boud and Holbrook (1958) Core ﬂooding experiments revealed that more than 17%– demonstrated for the ﬁrst time that foam could be gener- 18% additional oil recovery over water ﬂooding could be ated in an oil reservoir by sequential injection of aqueous obtained with either ASP or SP ﬂooding in carbonate surfactant solution and both miscible and immiscible gas reservoirs. ASP processes utilized the beneﬁts of three drives to increase its sweep efﬁciency. However, due to ﬂooding methods, whereby oil recovery was signiﬁcantly lack of proper understanding of the mobility control enhanced, by decreasing IFT, increasing the capillary mechanism by foam, the concept was not adopted widely number, enhancing microscopic displacing efﬁciency and (Li et al. 2010). Nevertheless, as the understanding of foam improving mobility ratio (Shen et al. 2009). However, mobility control advanced, there have been many ﬁeld tests despite these advantages, the success of the ASP projects of foam application since then. One of the most successful was not without certain limitations. Problems of severe ﬁeld pilot tests of foam mobility control in the Snorre ﬁeld scaling in the injection lines with strong emulsiﬁcation of is a well-known example (Blaker et al. 1999). Le et al. the produced ﬂuid signiﬁcantly impeded the implementa- (2008) performed a successful series of experiments on tion of ASP ﬂooding technologies (Gao and Towler 2011; carbonate rocks to study the injection strategy for foam Wang et al. 2009). Also, polymers could not be efﬁciently generation and emphasized the potential of foam as a used under high salinity conditions, because high salt mobility control agent (Le et al 2008). conditions degraded their viscosity. Moreover, multicom- Mobil’s Slaughter and Greater Aneth ﬁeld trials ponent formulations always run the risk of chromato- (1991–1994) were initial successful attempts of foam uti- graphic separations in the reservoir, as demonstrated in the lization for enhanced oil recovery. In this case, out of the ASP project in the Daqing Oilﬁeld in China (Li et al. four CO -foam ﬁeld trials, two were performed at the 2009). Improving the status of these commercially avail- Greater Aneth ﬁeld in carbonate reserves (South Utah). The able viscosiﬁers by the incorporation of salt tolerant outcome of all of these trials highlighted a sharp decrease monomers, so that cheap alkalis such as sodium carbonate in CO injectivity and a signiﬁcant increase in oil are successfully used, and employing associative mecha- production. nisms that allow for lower molecular weight polymers with Earlier, foam injection strategies such as water alter- improved injectivity are still under way. nating with gas (WAG) were considered as the technology of choice for controlling CO gas mobility (Enick et al. 3.4.3 Surfactant foams 2012). However, even then, complications, for example, viscous instabilities and gravity segregation, especially for Currently, surfactant-aided CO ﬂooding is being tested in heterogeneous reservoirs could not be defeated (Rogers and Middle East carbonate reservoirs (Al-Mutairi and Kokal Grigg 2001). As a possible solution to these complications, 2011). Owing to its physical properties and established foam-assisted EOR, such as the alkali–surfactant–gas multiple interactions with oil over a wide range of pres- (ASG) process, is one of the newly introduced successful sures and temperatures, CO is considered to be one of the synergistic combination of chemical and gas EOR meth- most important displacing ﬂuids in gas-based EOR tech- ods, especially for carbonate reservoirs (Li et al. 2010; nology (Blunt et al. 1993; Mathiassen 2003). However, Srivastava et al. 2009). The ASG process exhibits lower there are several problems associated with the gas injection mobility in high-permeability layers and hence under- (Sagir et al. 2013). Among them, the greatest challenge standably blocks or hinders the ﬂow in these layers. with CO gas injection lays in its poor volumetric sweep Simultaneously, the ﬂow in low-permeability layers is efﬁciency owing to its low density and viscosity. Lighter reasonably favored with enhancing oil recovery (Fara- gas overrides gravity and a large portion of recoverable oil jzadeh et al. 2012). Since ASG processes combine both the in the lower permeability regions cannot be contacted. This concepts of IFT lowering and using foam as mobility poor sweep leaves behind an extensive amount of oil in the control agents, they are mostly encouraged for HTHS reservoir. Though the microscopic sweep efﬁciency of CO carbonate reservoirs, where the functioning of polymers is quite high, its viscosity (* 0.01 cP) is much lower than usually deteriorates (Lake 1989; Niu et al. 2001). In recent both water (* 1.0 cP) and most of the crude oils experimental studies as reported in the works of Nguyen, (0.6–10 cP for conventional oils) which leads to many 2010, a twin-tailed dioctylglycerine surfactant showed conformance and mobility concerns and instability in the excellent performance in signiﬁcantly reducing mobility displacement front. Problems of poor volumetric sweep and recovering oil remarkably from a carbonate rock core efﬁciency, gas channeling through high-permeability ﬂood experiment. Based on these experimental ﬁndings, it 123 Pet. Sci. (2018) 15:77–102 87 is summarized that ASG foams affect the oil recoveries in To overcome these limitations, ethoxylated nonionic to three ways when compared to gas or WAG ﬂooding (An- cationic switchable amine surfactants were designed and drianov et al 2012; Farajzadeh et al. 2010): introduced in a series of sand pack experiments (Chen et al. 2012, 2014). Ethoxylated amines are switchable from (a) By increasing the viscosity of the displacing ﬂuid being nonionic in brine to cationic in the presence of an (gas or foam), the displacement process is stabilized; acidic aqueous phase such as CO (Elhag et al. 2014a). (b) By blocking the high-permeability swept layers and Reactions between primary, secondary or tertiary amines diverting the ﬂuids into low-permeability unswept with an appropriate alkoxylation agent generated these zones; and ethoxylated amines. Relative to the size of a hydrophobic (c) By reducing the IFT with its present surfactants, chain of alkyl amines, the size of the hydrophilic group reducing the overall capillary force. increased with ethoxylation, which in turn increased the One of the major concerns that subdue the application of hydrophilicity (Chen et al. 2014). Because of the proper foam as an EOR method is its stability (longevity) concerns balance in the number of carbons in their alkyl chains and when in contact with crude oil. Many experiments per- the number of ethylene oxide (EO) groups attached to the formed to interpret foam stability in bulk, and porous tertiary nitrogen in their head groups, ethoxylated alkyl media have demonstrated the detrimental effect of oil on amines of the form C N(EO) were found to satisfy 12–14 x foam stability (Andrianov et al. 2012; Farajzadeh et al. several essential requirements for effective CO -EOR. This 2010; Vikingstad and Aarra 2009; Vikingstad et al. 2005). surfactant was highly soluble in the CO phase because the In many cases, the oil saturation must become low enough, nitrogen atom remained unprotonated in this phase. While before the gas mobility can be reduced by foams. Usually, in a low-pH aqueous phase due to dissolved CO , the two mechanisms of interaction between foam ﬁlms and oil positively charged protonated amine rendered the surfac- phase might occur when they come in contact with each tants more hydrophilic and raised the cloud point to other. Either the oil phase might probe into the foam ﬁlm 120 C. Further, in the presence of CO , the adsorption of and destabilize it, or the foam ﬁlm might slide over the ethoxylated alkyl amines (dissolved in brine) on limestone water phase covering the oil. The ﬁrst possibility is most surfaces was signiﬁcantly reduced due to the positively common and expected, while the latter case if raised will charged cationic head group. Thus, switchable ethoxylated generate a new oil/water interphase—a ‘‘pseudo-emulsion amine surfactants can be considered as a new generation or asymmetric’’ ﬁlm. Studies of these asymmetric ﬁlms are surfactant, which uniquely combine the high cloud point of supremely important in predicting and controlling the sta- ionic surfactants in water with high solubility in CO for bility of foam in the presence of oil. However, reports on nonionic surfactants, stabilizing foam formations at 120 C the pseudo-emulsion are very rare (Jones et al. 2016). with minimal adsorption on limestone (Elhag et al. 2014b). Sometimes, traditional commercial nonionic or anionic Nonetheless, switchable surfactant experiments are still in surfactants used in CO foam-based recovery are unsuit- the primary stage, and much in-depth exploration needs to able for application in the HTHS reserves. The cloud points be done for proper understanding and acceptance of this of ethoxylated nonionic surfactants are consistently way cEOR technique in actual ﬁeld applications. Some possible below 100 C (Adkins et al. 2010), and the solubility of problems may be the maintenance of a low enough pH to most nonionic surfactants decreases in brine as the salinity keep them protonated and in a dissolved state in brine. increases (Rosen and Kunjappu 2012). There are reports of There is the possibility of dissolving or corroding carbon- several laboratory scale tests and ﬁeld trials using anionic ate formation in low pH conditions. sulfate and sulfonate surfactants for high-salinity limestone reservoirs (Hirasaki et al. 2008; Levitt et al. 2006). How- 3.4.4 Biosurfactants from bacteria and renewable ever, due to the electrostatic force of attraction, they often resources adsorb strongly on the positively charged limestone sur- faces in the presence of dissolved acidic CO at high To improve the cost effectivity of surfactant ﬂooding, pressures (Lawson 1978, Wang et al. 2015). Cationic sur- many researchers have investigated oil displacement by factants, on the other hand, exhibit low adsorption on biosurfactants primarily produced from bacteria during the carbonate formations, due to the electrostatic repulsion past decade (Banat 1995; Youssef et al. 2007; Joshi et al. between the cationic head and the positive charge bearing 2008; Al-Sulaimani et al. 2010). Biosurfactants are claimed carbonate surface (Hirasaki et al. 2008; Ahmadall et al. to be eco-friendly, non-toxic and biodegradable compared 1993; Lawson 1978). Nevertheless, they are rarely soluble to synthetic and toxic chemicals that are dangerous for oil in CO , although there are reports of a few exceptions workers and the environment. The economy of the com- (Smith et al. 2007). mercial production of these materials is affected by the downstream processing costs which are about 60% of the 123 88 Pet. Sci. (2018) 15:77–102 total production cost of many biological products. Never- surfactants are very promising waterborne chemicals that theless, studies indicate that crude or impure biosurfactants combine the desirable properties of surfactants and water obtained at the initial stage of recovery can be efﬁciently viscosiﬁers. Similar to conventional surfactants, they are used for oil recovery applications (Ghojavand et al. 2012). also amphiphilic in nature with a hydrophilic and a Efﬁcient biosurfactants could be produced from inex- hydrophobic portion. However, unlike surfactants that form pensive and renewable sources such as sugar cane molasses spherical micelles of oil in water, viscoelastic surfactants with a cost of lower than 0.5$ per liter (Oscar et al. 2007). aggregate to form large complex supramolecular structures Green, environment-friendly, non-toxic surfactants such as that have a high viscosity. A primary beneﬁt of these 0.5% alkyl polyglycoside (APG) derived from a sugar supramolecules is that they possess self-healing capability, source in a binary system with 0.5% NaHCO reduced the unlike polymers. Usually, the structure and size of these IFT, improved interface wettability, exhibited compatibil- viscoelastic surfactants are determined by the surfactant ity with injected and produced water and demonstrated low head group size, charge of the surfactant, temperature, adsorption on calcite plates derived from the G Oilﬁeld in salinity and ﬂow conditions. With an increase in concen- Kuwait (Yin and Zhang 2013). Results obtained from a tration, these surfactant molecules create ‘‘worm-like’’ recent experimental study by Ghojavand et al. showed that micelles when the surfactant molecule forms long aniso- a lipopeptide biosurfactant produced by Bacillus metric ﬂexible structures that are capable of entangling mojavensis PTCC 1696, isolated from an Iranian oilﬁeld, with other ‘‘worm’’ structures (Santvoort and Golombok could appreciably reduce the IFT in carbonate reservoirs 2015). One of the possible issues of implementing vis- even in the presence of high salinity (240 g/L-NaCl coelastic surfactants is adsorption on the carbonate surface, salinity) and thus enhance oil recovery from these low- which, however, can be managed in high-pH alkaline permeability reservoirs (Ghojavand et al. 2012). In another systems. Others may include their emulsiﬁcation with oil study by Sarafzadeh et al., the efﬁciency of two microbial and losing their viscosity, high cost and rather fragile biosurfactant-producing strains Enterobacter cloacae and nature of viscofying structures. Effects of shear, mainte- Bacillus stearothermophilus SUCPM#14 in EOR was tes- nance of viscosity during ﬂow, injectivity and industrial- ted (Sarafzadeh et al 2014). The core ﬂood experiments scale production and availability are also required to be investigated parameters such as cost effectivity, time and evaluated for commercial success. the ability of surfactants to lower IFT. It was found that of the strains, E. cloacae signiﬁcantly reduced the IFT of 3.5 Surfactant-based EOR projects water/crude oil system from 30 to 2.7 mN/m, modifying the capillary numbers and mobilizing trapped oil. A few surfactant-based EOR projects have been tried in carbonate ﬁelds, although many polymer projects were Sometimes, natural surfactants extracted from plant sources can also function as an effective chemical EOR conducted between the 1960s–1990s. Between 1990s and agent. Based on studies concerning its adsorption and 2000s, only few surfactant stimulation studies were economic aspects, saponin was found to be an important reported in carbonate reservoirs; including Yates ﬁeld in EOR agent, having very low cost and low adsorption val- Texas and the Cotton Wood Creek in Wyoming. The ues comparable to commercial, industrial surfactants for Baturaja Formation in the Semoga ﬁeld in Indonesia is a carbonate reservoirs (Ahmadi and Shadizadeh 2012; Shahri comparatively recent ﬁeld study. et al. 2012; Zendehboudi et al. 2013). In their studies, A list of published ﬁeld studies on surfactant-based Ahmadi and Shadizadeh systematically investigated the chemical EOR for carbonate reservoirs is summarized in implementation of a novel sugar-based surfactant derived Table 1. from the leaves of Z. spina christi for EOR applications in carbonate reservoirs (Ahmadi and Shadizadeh 2013b). Under the optimum conditions of 8 wt% surfactant con- 4 Surfactants employed for chemical EOR studies centrations and 15,000 ppm salinity, the proposed surfac- in carbonate reservoirs over the years tant exhibited 81% oil recovery. Although there are very few reported ﬁeld projects for 3.4.5 Viscoelastic surfactants cEOR in carbonate reservoirs, research activities about chemical methods have always been and are still in pro- Recently introduced viscoelastic surfactants are suggested gress through joint industrial projects and various academic as an alternative to polymers. They are known to effec- institution initiatives. Table 2 summarizes a list of pub- tively enhance oil recovery from carbonate reservoirs lished laboratory studies on cEOR by surfactants, alkaline under conditions of high temperature and salinity (Azad surfactants, and alkaline surfactant polymer mixtures. and Sultan 2010; Sultan et al. 2014). Viscoelastic Apart from this, some of the recently introduced surfactants 123 Pet. Sci. (2018) 15:77–102 89 Table 1 A selection of published surfactant-based chemical EOR ﬁeld projects for carbonate reservoirs Field Region Start Oil characteristics Oil Chemicals used Process References recovery, adopted/comments API Viscosity, %OOIP cP Wichita Texas 10/1/ 40.0 3.2 22.0 Surfactants: petroleum Micellar/polymer Leonard (1984) County 1975 sulfonates ? alkyl ether ﬂooding process Regular sulfate adopted Gunsight (secondary Polymers: polyacrylamide reservoir recovery) Reservoir temperature: 31.6 C Wesgum Arkansas 6/1980 21.0 11.0 26.7 Surfactants: petroleum Micellar/polymer Leonard (1986) ﬁeld, sulfonates ? alkyl ether ﬂooding process Smackover sulfate adopted reservoir (secondary Polymers: polyacrylamide recovery) Reservoir temperature: 85 C Bob Slaughter Texas 1980 31.4 1.3 12.0 Non-emulsion formulation: Two surfactant/ Adams and Block 1.5% solubilizer A polymer ﬂooding Schievelbein Lease, San (alkyl ether sulfates) and processes (1987) Andres 3.5% Witco petroleum adopted: non- reservoir sulfonate emulsion formulation and Emulsion formulation: emulsion 1.46% solubilizer B formulation (alkyl aryl ether sulfates), 3.6% Witco petroleum Reservoir sulfonate, 0.95% temperature: synthetic sulfonate, 4% 43 C gas oil, 4% slaughter crude oil Isenhour Wyoming, 1980 43.1 4.8 26.4 Na CO ? anionic Alkali/polymer Doll (1988) 2 3 USA polymers ﬂooding process adopted Reservoir temperature: 36.1 C Cambridge Wyoming, 1993 20.0 31.0 36.0 1.25wt% Na CO as Alkaline/surfactant/ Vargo et al. 2 3 Minnelusa USA alkali ? 0.1wt% polymer ﬂooding (2000) Petrostep B-100 as process adopted surfactant ? 1475 mg/L (secondary Alcoﬂood1175A as recovery) polymer Reservoir temperature: 55.6 C Yates ﬁeld, Texas 1998 30.0 6 15.0 0.3%–0.4% nonionic Surfactant well Yang and San Andres ethoxy alcohol (Shell stimulation Wadleigh reservoir 91–8) surfactant and processes (2000), 35% Stepan CS-460 adopted Mathiassen anionic ethoxy sulfate (2003) Single-well Huff-n- surfactant Puff dilute surfactant treatment Reservoir temperature: 28 C 123 90 Pet. Sci. (2018) 15:77–102 Table 1 continued Field Region Start Oil characteristics Oil Chemicals used Process References recovery, adopted/comments API Viscosity, %OOIP cP Mauddud Bahrain 1/1999 – 1.4–2.9 10–15 0.5% of surfactants in 200 Surfactant diesel Zubari and carbonate gallons per ft of diesel wash Sivakumar reservoir oil (2003) Surfactant xylene 1/2000 0.5% of surfactants in 55 wash gallons per ft of xylene Alkaline surfactant 1/2002 0.5% of surfactants ? 1% ﬂooding process sodium carbonate adopted alkaline solution Reservoir temperature: 60 C Cottonwood Wyoming, 1999 27 2.8 10.4 Nonionic polyoxyethylene Single-well Xie et al. Creek ﬁeld, USA alcohol (POA) surfactant (2004), Bighorn stimulation Weiss et al. Basin process adopted (2006) Reservoir temperature: 65.5 C Semoga ﬁeld, Indonesia 2009 38 0.84 58,000 bbl Nonionic surfactants Surfactant well Rilian et al. Baturaja over a stimulation via (2008) Formation period of Huff-n-Puff 3 months processes adopted Operation in 3 steps: (a) pre- ﬂush, (b) main ﬂush and (c) overﬂush Reservoir temperature: 83 C; salinity: 15,000 mg/L targeting speciﬁc carbonate reservoir conditions such as of hydrocarbon reserves, for studying ﬂuid ﬂow through high temperature, high salinity and the presence of natural porous media and for designing production equipment. The fractures have been discussed in detail. dead oil viscosity (0.6–33.7 cP), saturated oil viscosity (0.05–20.89 cP) and undersaturated oil viscosity 4.1 Surfactants targeted toward high-temperature (0.2–5.7 cP) having API gravity of 19.9–48, temperatures high-salinity (HTHS) reservoirs of the Middle of 38–150 C, bubble point pressure of 690–25,500 kPa East and pressure above bubble point (8875–69,000 kPa) were obtained from the Middle East crude oils. The high temperature of about 120 C in oil to mixed-wet For such challenging reservoirs, an approach using carbonate reservoirs around the Middle East and elsewhere tetraalkylammonium salt (TAS) type cationic surfactant is an important criterion to be considered when looking for was proposed for enhancing ORF from heavy oil-impreg- appropriate surfactants for cEOR. The high salinities such nated calcite cores (Saleh et al. 2008). It is commonly as 16%–22% TDS in Abu Dhabi along with the high observed that spontaneous water imbibition is not possible temperature in the range of 120 C are current challenges in oil-wet rock surfaces due to the presence of very small or in the implementation of cEOR in the United Arab Emi- negative capillary pressure. Initially, it was believed that rates (Quadri et al. 2015). The viscosities of dead crude oils wettability reversal by anionic ethoxylated sulfonate sur- and crude oils containing dissolved gasses (saturated and factants was capable of achieving spontaneous imbibition under saturated) from the Middle East were accurately of water by capillary forces in the new water-wetted sur- calculated using the Elsharkawy and Alikhan model (El- faces (Standnes and Austad 2000a). Nevertheless, low 20% sharkawy and Alikhan 1999) for the formation evaluation ORF values obtained from experiments using anionic 123 Pet. Sci. (2018) 15:77–102 91 Table 2 Chemical EOR laboratory studies for carbonate reservoirs by surfactants, alkaline surfactants and ASP mixed slugs Surfactant type and Materials Synthetic brine Comments/experimental Estimated References concentration outcomes ﬁnal recovery, Amphoteric Petrostep B-100 Cretaceous Formation brine (TDS- Experiments conducted at 45 Olsen et al. 2? 2? surfactant (0.2wt%– Upper 12,000 ppm, Ca ,Mg , reservoir temperature of (1990) 0.5wt%) ? Pusher 700E Edwards Na ) 42 C polymer reservoir Crude oil viscosity: 3 cP; (0.12wt%) ? sodium Carbonate API: 27 (light oil) tripolyphosphate (0.4%– formations ASP ﬂooding was adopted 0.5%) and sodium from Central carbonate (2%) alkali Texas Permeability: 75 mD Cationic surfactants of the Oil-wet low Three different brines with Two types of oil are used: Oil 10–75 Standnes type tetra alkyl ammonium permeability various dissolved solids A—acidic crude oil: n- and ? ? 2? (six) (2–7 mD) content (Na ,K ,Mg , heptane (60:40) and Oil Austad 2? - 2- - outcrop chalk Ca ,Cl ,SO , HCO ) B—pure n-heptane (2003) 4 3 Anionic surfactants (eight) from Stevns Imbibition tests run with 0.1wt% for each Klint cationic and anionic Copenhagen surfactants at different temperatures (40–70 C) Cationic surfactants have a higher potential to expel oil from oil-wet chalk material (irreversible wettability alteration) than anionic surfactants Surfactant concentration [ CMC Anionic (ethoxylated and Dolomite cores Formation brines (NaCl, KCl, Anionic surfactants and 40–50 Hirasaki propoxylated sulfate) CaCl , MgCl ,Na SO ) Na CO /NaHCO changed and 2 2 2 4 2 3 3 Permeability: surfactants ? sodium the wettability of oil-wet Zhang 40–122 mD carbonate alkali mixture dolomite cores to (2003) (0.05wt%–0.1wt%) preferentially water-wet as a function of the prior aging temp in crude oil Oil recovery from oil-wet dolomite cores was by spontaneous imbibition with an alkaline anionic surfactant solution Oil viscosity: 18.1–22.6 cP 123 92 Pet. Sci. (2018) 15:77–102 Table 2 continued Surfactant type and Materials Synthetic brine Comments/experimental Estimated References concentration outcomes ﬁnal recovery, Nonionic ethoxy alcohol Dolomite cores Actual Yates reservoir brine Nonionic ethoxy alcohol – Vijapurapu surfactants (\ 3500 ppm) (NaCl, KCl, CaCl , MgCl , surfactants decreased IFT and Rao 2 2 Na SO , NaHCO ) supplied between Yates crude oil (2004) 2 4 3 by Marathon Oil Company. and Yates brine, along with a simultaneous decrease in Synthetic brine (prepared as contact angle from 156 per the same composition) (strongly oil-wet) to 39 (water-wet) The experimental study identiﬁed two simple techniques of surfactant addition and brine dilution to beneﬁcially alter the wettability of oil-wet fractured cores and minimize capillary trapping of crude oil in reservoir rocks Anionic ethoxylated (EO) and Calcite Synthetic brine (Na CO ) The oil used was West Texas 35–55 Seethepalli 2 3 propoxylated (PO) sulfate lithographic fractured carbonate ﬁeld et al. surfactants limestone, crude oil (19.1 cP, API (2004) marble, 28.2-light) supplied by Cationic (CTAB) surfactants dolomite Marathon Oil Company 0.05wt% for each plates In the presence of Na CO , 2 3 anionic surfactants could change the calcite wettability of carbonate from oil-wet to water-wet, similar to or even better than cationic surfactants The adsorption of anionic sulfonate surfactants is signiﬁcantly suppressed by the addition of Na CO 2 3 Cationic C TAB surfactants Oil-wet low Artiﬁcial seawater Crude oil used was diluted 50–90 Hognesen permeability with 40vol% heptane et al. 0.6wt%–3.5wt% (1–3 mD) (2006) Oil viscosity: 2.5 cP (light outcrop chalk oil) from Stevns Oil production from different Klint surfaces of the core studied Copenhagen Comparison between the gravity and capillary force contribution Cationic C TAB surfactants Outcrop chalk Artiﬁcial seawater as Oil A: 60% crude and 40% 20–60 Strand et al. (1.0wt%) reference, 11 different brines heptane (2006) Permeability low with varying dissolved solid (2–5 mD) Ion pair interaction is the ? 2? contents (Na?,K ,Ca , probable wettability 2? - 2- - Mg , SCN ,SO ,Cl , alteration factor, thereby HCO ) increasing the capillary forces that facilitates spontaneous imbibition of oil The temperature range in the study was 90–130 C 123 Pet. Sci. (2018) 15:77–102 93 Table 2 continued Surfactant type and Materials Synthetic brine Comments/experimental Estimated References concentration outcomes ﬁnal recovery, Five anionic (sulfonate, Calcite plates Na CO and NaCl The oil used was West Texas 60–75 Gupta and 2 3 disulfonate and sulfate) limestone fractured carbonate ﬁeld Mohanty surfactants cores, crude oil (23.8 cP, API 2010 28.2-light) at 27 C Two nonionic (ethoxylates) Permeability: surfactants, 0.1wt% for each 15 mD The temperature ranges: 25–90 C Oil recovery rate increases with temperature increase for all anionic and nonionic surfactants studied up to 90 C Surfactant/brine imbibition was a gravity driven process Anionic (sulfonate, Calcite plates Synthetic brine (Na SO , Two oils used: (a) Model oil- 30–50 Gupta and 2 4 disulfonate and sulfate) Texas NaCl, Na CO , CaCl , 1.5wt% of cyclohexane Mohanty 2 3 2 surfactants, 0.1wt%–5wt% Cordova MgCl ) pentanoic acid ? n-decane. (2011) cream (b) West Texas fractured limestone core carbonate ﬁeld crude oil (23.8 cP, API 28.2-light) Permeability: at 27 C 15 mD Optimum surfactant concentration is directly linked with brine salinity Mixed with Na CO , anionic 2 3 surfactants desorb the naphthenic acid from carbonate surface, as at high pH, calcite charge is switched from positive to negative Wettability of oil-aged calcite altered by sulfate ions in the 2? 2? presence of Mg ,Ca at 90 C aiding in oil recovery Two anionic surfactants Limestone Formation brine (NaCl, The mixture of cationic and 70–80 Sharma and (ethoxylated sulfonate: MaCl ) nonionic surfactants is Mohanty AV-70, AV-150) stable at high temperatures (2013) (100 C) and high salinity Three nonionic surfactants (NP ethoxylate, 15-s- Effective in wettability ethoxylate, TDA 30EO) alteration of carbonate reservoirs with aging Four cationic surfactants 1–2 months (CTAB, DTAB, Arquad C-50, Arquad T-50) surfactants \ 0.2wt% for each 123 94 Pet. Sci. (2018) 15:77–102 Table 2 continued Surfactant type and Materials Synthetic brine Comments/experimental Estimated References concentration outcomes ﬁnal recovery, Anionic surfactants: alkyl Silurian Formation brine Crude oil viscosity: 22.5 cP; 26–80 Sagi et al. propoxy (PO) sulfates Dolomite (TDS = 9412–10,625 ppm, API: 28.2 (light oil) (2013) ? 2? 2? - (APS) and their blends with outcrop cores Na ,Mg ,Ca ,Cl , The experiments were 2- - internal oleﬁn sulfonates SO , HCO ) 4 3 Permeability: conducted at low (IOS), alkyl benzene 195 mD temperatures (* 25 C) sulfonate (ABS), alkyl and salinity of xylene sulfonate (AXS) * 11,000 ppm TDS 0.25wt%–2.0wt% The anionic surfactant blends produced optimal salinity close to reservoir salinity and achieved oil recovery efﬁciencies of [75% at 0.5wt% of surfactant concentration Two anionic and two Siliceous and Water Crude oil viscosity: – Alvarez nonionic surfactants [0.2, 1 carbonate 30–40.5 cP; API: 35.77– et al. and 2 gallons per thousand shale cores 37.74 (2014) gallons (gpt)] Both anionic and nonionic surfactants changed the wettability of carbonate shale cores Anionic surfactants performed better than nonionic surfactants in changing contact angles in oil shale samples Anionic Guerbet alkoxy Silurian dolomite Formation brine (TDS- Crude oil viscosity: 0.5 cP, 90–94.5 Lu et al. carboxylate (GAC) (478 mD) 23,800 ppm, divalent cation API: 34 (light oil) (2014a) surfactants (0.15wt%– Estaillade concentration 3700 ppm) The GAC surfactants reduced 1.0wt%) limestone core IFT signiﬁcantly (187 mD) The GAC can act as alternatives to sulfate surfactants for high-salinity, high-temperature reservoirs where alkali is not included in the formulation Nonionic branched SACROC CO , SACROC brine (NaCl, The surfactants are more – McLendon nonylphenol ethoxylates carbonate CaCl , MgCl ) soluble in CO , thus et al. 2 2 2 (Huntsman SURFONICS cores forming stable CO -in- (2014) N-120 & Huntsman brine foams which appear Permeability: SURFONICS N-150) and to be promising CO 13–16 mD branched isotridecyl additives for mobility ethoxylate (Huntsman control SURFONICS TDA-9) They can act as appropriate surfactants candidates for EOR * 0.07wt% applications surfactants indicated that the desired wettability alteration on calcite, wetted by either heavy or light oil. The mech- is not always achieved. This ﬁnding leads to considering anism of action of C TAC on the ORF for heavy oil pri- and testing of other surfactants of cationic nature. In their marily involved oil disaggregation followed by viscosity conjoint theoretical and experimental studies, Pons-Jime- decrease. Reduction in viscosity led to the release of oil nez et al. (2014) proposed a plausible chemical mechanism that is loosely adsorbed onto the rock. However, there was involved in 36% ORF increase by the cationic surfactant no detectable wettability alteration of the carbonate dicecyltrimethylammonium chloride (C TAC) at 150 C reserves, in this case, conﬁrming that both the asphaltenes 123 Pet. Sci. (2018) 15:77–102 95 and resins of crude oils remain strongly adsorbed on the some positive results from several experimental and pilot rock surfaces, thereby maintaining the oil-wet state of ﬁeld studies, actual trials at exploration sites in a com- carbonate rocks. mercial setting are very limited (Adibhatla and Mohanty Recently, surfactant-aided gravity drainage process of oil 2008). Lack of adequate practical knowledge about sur- recovery for water- as well as gas-ﬂooded HTHS carbonate factants used in dual-porosity fractured carbonate reser- reservoirs was also tested. Sometimes, water ﬂooding fails voirs, limits their performance to a great extent (Manrique to perform successfully in heavily fractured carbonate et al. 2007). In a few cases reported for surfactant-based rocks, where large viscous gradients cannot be imposed cEOR for carbonate reservoirs, which include the Mauddud (Adibhatla and Mohanty 2008). In such cases, gas-aided carbonate reservoir of Bahrain (Zubari and Sivakumar gravity drainage is a conventional oil recovery technique. 2003), Yates ﬁeld in Texas (Yang and Wadleigh 2000), However, again when the permeability is low, the remain- Cottonwood Creek ﬁeld in Wyoming (Xie et al. 2004) and ing oil saturation in such anticline-shaped reservoirs can be the Baturaja Formation in the Semoga ﬁeld of Indonesia quite high and recovery annoyingly slow (Wang and (Rilian et al. 2008), the temperature was about 45 C and Mohanty 2013). Herein comes the surfactant (anionic, never higher. Therefore, much work remains to be nonionic and cationic) enhanced gravity drainage technique accomplished for HTHS carbonate oil reserves to establish (Srivastava and Nguyen 2010; Ren et al. 2011; Guo et al. credible production baselines and successfully capture the 2012). Cationic surfactants of the type alkyl trimethylam- recovered mobilized oil (Kiani et al. 2011). monium bromide (C TAB) efﬁciently recovered approxi- Surfactant injection EOR for an oil-wet carbonate mately 70% of OOIP by imbibing water into originally oil- reservoir might not always be successful because of several wet chalks (Standnes and Austad 2000a, b, 2003). They reasons as outlined in the works of Kiani and coworkers. were believed to form ion pairs with adsorbed organic Their experimental ﬁndings suggested that in contrast to carboxylates of the crude oil, solubilizing them into the oil the homogeneous unfractured reservoirs, the pressure gra- and thereby changing the mixed/oil-wet rock surfaces to dient in fractured formations may be too small to displace water-wet. This wettability alteration assisted in counter- oil from the matrix. At times, several high-permeable current imbibition of brine and led to increased oil recovery. fracture areas can act like ‘‘thief zones’’ and may bypass However, the major drawbacks of this method are still the smaller fractures. To overcome such challenges, use of high surfactant concentration requirement along with its mobility control agents, for example foam, may be con- cost which leads to searches for newer cheaper cationic sidered (Talebian et al. 2014, 2015). However, issues surfactants of the form C NH (Adibhatla and Mohanty similar to foam stability in the presence of oil are still a 10 2 2008). Another example of less expensive surfactants is the challenge which requires much attention. More experi- several bioderivatives of the coconut palm, termed Arquad ments on pseudo-emulsion physics and chemistry should and Dodigen (Strand et al. 2003). Several anionic surfac- be undertaken soon, where increased efforts should be tants under the commercial name Alfoterra and those made in the collection of more and more experimental data mentioned in the works of Adibhatla and Mohanty (2008) and correlating them with the stability of foams in oil- were considered for gravity-aided methods in fractured saturated carbonate reservoirs. Other parameters, such as carbonate formations. Anionic surfactants were known to salinity, temperature and wettability, must also be taken diffuse into the matrix, lower the IFT and contact angle, into account while designing future experiments. Another which in turn decreases the capillary pressure and increase important parameter, which is very often neglected in the oil relative permeability. The high relative permeability analyzing foam stability in the presence of oil, is the dis- of oil helps the gravitational force in pulling the oil out of joining pressure, which exists in very thin foam layers. For matrix (Hirasaki and Zhang 2003; Seethepalli et al 2004). optimization of foam properties in contact with the oil As usual, the adsorption of anionic surfactants on the sur- phase, studies of the disjoining pressure in the pseudo- face of calcite was suppressed with an increase in pH and a emulsion ﬁlms and its control are crucial, which remains a decrease in salinity. challenge. Some of the typical problems encountered when poly- mers are used, especially during combined ﬂooding 5 Overcoming challenges in EOR: future strategies such as ASP ﬂooding, include low injectivity or perspectives complete plugging of injection wells, degradation of polymers, incomplete polymer dissolution, and pump fail- Over the last decade, a good number of technologies have ures. Additionally, alkali and surfactant may cause corro- been advanced to overcome many of the past failures and sion, the formation of a persistent and stable emulsion unlock new areas of research for challenging carbonate between injected chemicals and oil and, most importantly, reservoirs. Nonetheless, it should be noted that despite scaling (Bataweel and Nasr-El-Din 2011; Stoll et al 2010). 123 96 Pet. Sci. (2018) 15:77–102 Mineral scales are formed by deposition from aqueous scientists studying adsorption behavior of both anionic solution of brine when they become supersaturated due to a (Ahmadall et al. 1993) and cationic surfactants (Rosen change in their thermodynamic and chemical equilibrium and Li 2001) over the calcite and dolomite surfaces i.e., ionic composition, pH, pressure and temperature arrived at the conclusion that the source of carbonate (Mackay et al. 2005). In oilﬁeld operations, scaling is material seems to have a substantial impact on surfactant principally formed by a decrease in pressure and/or an adsorption. Nevertheless, the search for newer cheaper increase in temperature of brine, which leads to the surfactants and alkalis should be taken up. Efﬁcient sur- reduction in the solubility of salts. The alkalis react with factant screening should be done for selecting the opti- 2? 2- 2- ions (Ca ,CO ,SO ) of the carbonate minerals in the mum surfactant for a system. Sometimes when a single 3 4 rock forming scales. Sometimes mixing of two incompat- surfactant fails to perform successfully for HTHS reser- ible brines (formation water rich in cations such as barium, voirs, a dual-surfactant system may be a workable calcium, strontium and sulfate-rich seawater) leads to strategy. precipitation of sulfate scales (BaSO ) (Zahedzadeh et al. Based on the recent analysis on the impact of water 2014). Scales damage well productivity by reducing per- softening on the economics of cEOR, it was found that meability, plugging production lines, and fouling equip- chemical cost can be decreased signiﬁcantly by using soft ment, which leads to production-equipment failure, sea water. Improved technologies are expected to come up emergency shutdown with increased maintenance costs and in the near future which can reduce several operational and decrease in overall production efﬁciency (Mackay and logistic issues of cEOR for carbonate reservoirs. There has Jordan 2005). A traditional commercial approach to alle- to be a life-cycle approach to cEOR, and the concept of viate scaling in the oil and gas industry is by applying energizing the reservoir deserves attention from the earliest conventional hydrophilic scale inhibitors, for example, stages of ﬁeld planning and development. PPCA (polyphosphonocarboxylic acid) and DETPMP (di- ethylenetriaminepenta (methylene phosphonic acid)) (Bezemer and Bauer 1969). However, many of these 6 Summary organic phosphates and phosphonates that are widely used as scale inhibitors are highly toxic and unacceptable envi- Fractured low-permeability carbonate reservoirs long ronmentally. Currently, new generation green scale inhi- drained by water and gas injections can have high bitors which minimize pollution associated with the remaining oil saturation. Surfactant EOR technologies manufacture and application of hazardous materials are targeted toward such reserves are considered versatile ter- being considered (Kumar et al. 2010). This study seems tiary oil recovery techniques to maximize total oil pro- promising, and future investigations in optimizing favor- duction. Presently there are an increasing number of able environment-friendly inhibitors should be encouraged ongoing and planned cEOR evaluations at pilot scales for successful elimination of this challenging problem of globally. Though several publications on surfactant-as- carbonate formations. sisted polymer, ASP, foam, microemulsions ﬂooding Another signiﬁcant difﬁculty for implementing surfac- experimental results on carbonate formations are available, tant EOR lies in its high adsorption on reservoir forma- there are very few ﬁeld cases reported. Due to very chal- tions which needs continuous surfactant re-injection, lenging conditions of temperature and salinity, the avail- rendering the designed EOR process inefﬁcient and eco- ability of proper surfactants and polymers is severe nomically infeasible. The surface chemistry of most of the limitation. Although switchable alkyl amine surfactants carbonate rocks signiﬁcantly inﬂuences surfactant show promising results in laboratory tests for foam EOR, adsorption. Complex dissolution behavior is observed in their application to ﬁeld level still requires substantial certain minerals in carbonate rocks such as dolomite effort. Surfactants and polymers for ASP, SP and polymer (CaMg (CO ) ), calcite (CaCO ) and magnesite (MgCO ) EOR applications are still not available to cater for the 3 2 3 3 (Hiorth et al. 2010). Interestingly, the isoelectric point of needs for HSHT carbonate reservoirs, though a few catio- calcite is known to be dependent on the pH and sources nic surfactants showed promising results in wettability of materials, equilibrium time and ionic strength in alteration experiments at laboratory scale. In addition to aqueous solutions (Ma et al. 2013). From their experi- that, a laboratory and a ﬁeld test show promising results but mental simulations, Vdovic and Biscan stated that under injection water used was of low salinity which seriously -3 3 the same ionic strength (10 mol/dm NaCl) within the questions the application where low-salinity injection pH range of 7–11, natural calcite (Polycarb, ECC Inter- water is not available. As polymers are the primary national) was more negatively charged than synthetic requirement for mobility control in ASP and SP schemes, calcite (Socal-U1, Solvay, UK) (Vdovic and Biscan even if the surfactants become available, unavailability of 1998). Experiments conducted by various groups of suitable polymers is also a drawback in the development of 123 Pet. Sci. (2018) 15:77–102 97 conference at oil & gas West Asia, April 11–13, Muscat, Oman, EOR projects and development of suitable polymers should 2010. doi:10.2118/129228-MS. be considered as well. 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Review of surfactant-assisted chemical enhanced oil recovery for carbonate reservoirs: challenges and future perspectives

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Review of surfactant-assisted chemical enhanced oil recovery for carbonate reservoirs: challenges and future perspectives

Review of surfactant-assisted chemical enhanced oil recovery for carbonate reservoirs: challenges and future perspectives

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