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A review of development methods and EOR technologiesfor carbonate reservoirs

A review of development methods and EOR technologiesfor carbonate reservoirs Carbonate reservoirs worldwide are complex in structure, diverse in form, and highly heterogeneous. Based on these char- acteristics, the reservoir stimulation technologies and fluid flow characteristics of carbonate reservoirs are briefly described in this study. The development methods and EOR technologies of carbonate reservoirs are systematically summarized, the relevant mechanisms are analyzed, and the application status of oil fields is catalogued. The challenges in the development of carbonate reservoirs are discussed, and future research directions are explored. In the current development processes of carbonate reservoirs, water flooding and gas flooding remain the primary means but are often prone to channeling problems. Chemical flooding is an effective method of tertiary oil recovery, but the harsh formation conditions require high-performance chemical agents. The application of emerging technologies can enhance the oil recovery efficiency and environmental friendli- ness to a certain extent, which is welcome in hard-to-recover areas such as heavy oil reservoirs, but the economic cost is often high. In future research on EOR technologies, flow field control and flow channel plugging will be the potential directions of traditional development methods, and the application of nanoparticles will revolutionize the chemical EOR methods. On the basis of diversified reservoir stimulation, combined with a variety of modern data processing schemes, multichannel EOR technologies are being developed to realize the systematic, intelligent, and cost-effective development of carbonate reservoirs. Keywords Carbonate reservoir · Reservoir stimulation · Flow characteristic · Development method · EOR technology 1 Introduction deposition. The main rock types of carbonate reservoirs include limestone (grainstone, reef limestone, etc.) and Carbonate rocks are sedimentary rocks composed of sedi- dolomite, and their storage space is usually comprised of mentary carbonate minerals (calcite, dolomite, etc.). Most pores, karst caves and fractures (Wang et al. 2012). Gener- carbonate rocks were deposited in warm and clean shal- ally, pores and karst caves are the main storage spaces, and low sea environments, primarily as a result of endogenous fractures serve as both storage spaces and the main flow channels in reservoir rocks. Globally, carbonate reservoirs have become the main oil and gas production resources due Handling Editor: Kun Ma to their ubiquity, uniform thickness, and large scale. Middle Edited by Yan-Hua Sun East oil production accounts for approximately two-thirds of global production, and 80% of Middle East oil-bearing * Song-Yan Li formations are carbonate rocks (Nairn and Alsharhan 1997). lsyupc@163.com Oil production in carbonate reservoirs in North America * Zhao-Min Li accounts for approximately 1/2 of all North American oil lizhm@upc.edu.cn 6 2 production (Wilson 1980a, b). There are nearly 3 × 10  km School of Petroleum Engineering, China University of carbonate rocks in China, accounting for approximately of Petroleum (East China), Qingdao 266580, Shandong, 1/3 of the China’s land area. These data illustrate the impor- China tance of carbonate oil and gas fields in the world. Key Laboratory of Unconventional Oil and Gas The distribution of carbonate rocks accounts for 20% of Development, China University of Petroleum (East China), the total area of global sedimentary rocks; carbonate oil and Ministry of Education, Qingdao 266580, Shandong, China gas resources account for approximately 70% of the world’s Sinopec Group, Beijing 100728, China Vol:.(1234567890) 1 3 Petroleum Science (2020) 17:990–1013 991 oil and gas resources, and proven recoverable reserves than 3500 m. Among them, the oil fields under development account for approximately 50% of the world’s oil and gas with a burial depth of more than 5000 m are mainly concen- resources (Li et al. 2018c). The oil and gas production in trated in North America, Russia, Italy and other regions. In global carbonate reservoirs accounts for approximately recent years, China has made an important progress in the 60% of global oil and gas production (Roehl and Choquette development of deep carbonate rocks in the Tarim Basin 2012). Marine carbonate oil and gas resources account for (Ma et al. 2011). Carbonate rocks are easily fractured. With 90% of global oil and gas resources, as marine carbonate oil increased burial depth, dissolution has a great influence on and gas resources are vast. There are 389 oil and gas basins the pore structure of carbonate reservoirs. Through organic in the world engaged in commercial production, among acid dissolution, hydrothermal dissolution, thermochemical which 208 basins are located in marine carbonate strata. By sulfate reduction (TSR) and other processes, corrosion pores the end of 2013, the proven plus probable (2P) recoverable are formed in the buried environment. Geologists who have reserves of oil, natural gas and condensate that had been long engaged in marine carbonate research are focusing on the 11 14 3 discovered worldwide were 3.534 × 10   t, 3.27 × 10  m development of corrosion pores. These newly discovered deep and 2.24 × 10  t, respectively, and their oil equivalent was and ultradeep carbonate rocks are all ae ff cted by fractures and 6.383 × 10  t. Among them, the 2P recoverable reserves vugs, forming fractured reservoirs with fractures as the main of petroleum, natural gas, and condensate in marine car- storage spaces, which usually contain abundant reserves that 11 14 3 bonate formations were 1.296 × 10   t, 1.2 × 10  m , are amenable to large-scale development. and 1.22 × 10   t, respectively. The oil equivalent was Compared with sandstone reservoirs, carbonate reservoirs 2.382 × 10  t. The recoverable reserves of oil, natural gas have notable differences in geological structure character - and condensate in marine carbonate rock series account for istics and reservoir displacement mechanisms that require 36.7%, 36.7% and 54.5% of the total discovered oil and gas certain particularities in development methods. There are in the world, respectively, accounting for 37.3% of the total many development methods utilized in carbonate reservoirs based on oil equivalence calculations. Figure 1 shows a sum- because depletion is inexpensive, the formations are adapt- mary of the recoverable reserves of marine carbonate reser- able, and natural energy can be fully utilized. For reservoirs voirs in the world. It can be seen that oil and gas are mainly with low stress sensitivity, depletion production is generally concentrated in four oil and gas regions: the Middle East, the used. However, depletion production causes the formation former Soviet Union, North America, and the Asia–Pacific pressure to drop, thus hindering stabilized reservoir pro- region (Wang et al. 2016). duction; the premise of adopting this method is the lack of With the continuous advancement of oil and gas exploration supplementary formation measures and corresponding EOR throughout the world, the development of deep and ultradeep technologies. Therefore, because of these unique character- oil and gas has become a topic of interest. More than 10% istics, it is important to efficiently develop carbonate reser - of carbonate oil and gas fields have a burial depth of more voirs by formulating ideal potential tapping countermeasures and adopting appropriate development methods. This review focuses on the related technical problems in 1020 the development processes of carbonate reservoirs in the 1006 Oil, 10 t world. This study combines the results of laboratory experi- 1000 12 3 Natural gas, 10 m ments and practical applications in oil fields, explains the 140 Condensate, 10 t technological measures for the stimulation of carbonate 120 reservoirs, analyzes the flow characteristics of formation fluid in fractured vuggy carbonate reservoirs, and details the various development methods such as water flooding, gas flooding, chemical flooding, and emerging oil production technologies. The EOR mechanisms for carbonate reservoirs are summarized, and the challenges of carbonate reservoir 40 development and the directions of future development tech- nologies are discussed. 20 17 4 4 2 2 11 1 1 2 Stimulation of carbonate reservoirs The porosity and permeability of carbonate reservoirs in the world are generally low; approximately 80% of reser- Fig. 1 The proven plus probable recoverable reserves of marine car- bonates in the world (Energy 2008; Gautier et al. 1995; USGS 2000) voir porosity values range between 4% and 16%, and the 1 3 Middle East Soviet Union North America Asia-Pacific Africa Central South America Europe Reserves 992 Petroleum Science (2020) 17:990–1013 permeability ranges from 1 to 500 mD. When the matrix However, due to its strong reservoir sensitivity and high permeability of carbonate reservoirs is low, dissolution cost, the economic benefits need to be considered before structures such as pores, fractures and karst caves are devel- using a VES (Barati and Liang 2014). In low-pressure res- oped, and the heterogeneity of these formations is strong. ervoirs, the effect of foam acid fracturing is better than that Natural microfractures and dissolved pores, as the main stor- of conventional acid fracturing. Foam fluid-carrying acid age spaces, provide a large contribution to oil production can achieve u fl idity control and multistage fracturing (MSF) and are often distributed in the form of discontinuous zones (Rahim 2018). The performance of foam acid systems with great randomness. The matching relationship between largely depends on the stability of the foam, which depends natural fractures and pore structures is diverse, which can on the development of thermal resistance and the salt toler- cause divisions within a reservoir, where the connectivity of ance of the foam systems. Organic acids can adapt well to these structures is poor and their conductivity is different. the formation environment of carbonate reservoirs. However, In terms of production characteristics, the initial oil produc- due to their low solubility, there are many limitations in their tion levels can be high, but maintaining stable production is application to acid fracturing. difficult. Therefore, reservoir stimulation measures, such as With the global development of carbonate reservoir stim- acid fracturing, occupy an important position in the efficient ulation, new technologies for acid fracturing have emerged development of carbonate reservoirs. in recent years. Guo et  al. (Guo et  al. 2019) proposed a In the process of carbonate reservoir development, acidiz- hybrid volume stimulation (HVS) technology for tightly ing is an effective measure used to increase production and fractured carbonate reservoirs. The technology includes injection. The injection of an acid solution can eliminate three stages: hydraulic fracturing, large-scale acid fractur- rock cementation or formation plugging through dissolution ing and proppant injection. The core concept is to establish and corrosion to improve the permeability of the reservoir. a complex fracture system with high conductivity, as shown Acid fracturing expands the fracture openings by injecting in Fig. 2. The system includes main fractures, branch frac- pad fluid or acid fluid directly under the condition that the tures, induced fractures, and acid-etched wormholes. HVS injection pressure is higher than the formation fracture pres- technology combines the advantages of traditional hydraulic sure, and the acid fluid produces uneven corrosion on the fracturing and acid fracturing to further improve the stimula- fracture surfaces. Even after the fracture is closed, it main- tion effect of tight fractured carbonate reservoirs. tains a certain conductivity to achieve the effect of increas- In-situ microfoam acidizing is a new type of acidifica- ing oil and gas production. Acid fracturing is an important tion technology. The technology uses conventional chemi- technical means to increase and stabilize the production of cal reactions between acids and carbonate rocks to produce carbonate reservoirs. However, there are severe formation supercritical CO . With the synergistic effect of foaming conditions, such as high temperature, high pressure, and agents and stabilizers, C O foam fluid is generated in situ, high stress, in deep and ultradeep carbonate reservoirs that which carries the acid solution into the carbonate rock pose a great challenge to the implementation of acid fractur- matrix for acidification (Yan et al. 2019). The mechanism ing technology. is shown in Fig. 3. Foamed acid can temporarily block the For the acidic fluid systems commonly used in carbon- high-permeability layer, transfer the acid solution to the low- ate reservoir acidification, Aljawad et al. (2019) provided a permeability area and achieve a uniform treatment of the very detailed summary, including for hydrochloric acid and carbonate reservoirs. Compared with conventional acidifi- organic acids. Hydrochloric acid is widely used because of cation, the selectivity of foamed acid can ensure that less its strong dissolving ability, and under high temperatures, acid is used while still realizing the deep acidification of the the reaction rate of hydrochloric acid is greatly accelerated. reservoir (Li et al. 2008). It is necessary to add a slow release agent to reduce the acid Guo et al. (2020) proposed the technical concept of three- rock reaction and loss rate. The addition of polymer gels can dimensional acid fracturing based on the development of increase the viscosity of the system and reduce the loss of fractured vuggy carbonate reservoirs in the Tarim Basin, acid to a certain extent. However, polymer gels are greatly China. The concept is based on optimizing the deployment affected by temperature and pH, which enhances their per - of collective reservoir space and using long well sections to formance when used as additives. Emulsified hydrochloric penetrate heterogeneous reservoirs to achieve three-dimen- acid, which is usually composed of diesel oil, emulsifier and sional stimulation in the planar and longitudinal directions. acid (DEA), is also a mixture that can reduce acid loss. In The transformation of different types of reservoirs is shown terms of deep acidification, DEA can also prevent corrosion in Fig. 4. For the stimulation of porous and fractured reser- caused by acid contact. However, this acid system may cause voirs, the emphasis is on increasing the area of the fractures considerable reservoir pollution (Nasr-El-Din and Al Moajil and carrying out complex fractures by acid fracturing. For 2007). As a cleaning fluid, a viscoelastic surfactant (VES) fractured vuggy reservoirs with strong heterogeneity, tempo- can provide good viscosity control and shunting ability. rary plugging steering technology or targeted acid fracturing 1 3 Petroleum Science (2020) 17:990–1013 993 Induced fractures Acid reached branches Wormholes Main fracture Fig. 2 Ideal schematic diagram of a complex fracture system created by HVS. Reprint permission obtained from Guo et al. (2019) technology is often used to connect the fractures and vugs while forming main fractures with high conductivity (Li Foam formation et al. 2015). Acid fracturing and other reservoir stimulation technolo- gies can enhance the conductivity of fractures, which is important for increasing the production of carbonate reser- Carbonate rock voirs. With the continuous increase in the depth of explora- tion and development of carbonate reservoirs, the difficulty of reservoir stimulation caused by heterogeneous geologi- cal conditions and complex fluid distributions has become Acidizing reactions increasingly prominent. The solution requires more accurate High fracture and vug identification and description technology. As a result, the adaptability of the new acid fracturing pro- Foam diversion cess has gradually improved. Additionally, the harsh reser- + 2+ Low CaCO3 + 2H Ca + H2O + CO2 voir environment imposes very high requirements for the Carbonate rock Carbonate rock operational equipment and acid system, especially to reduce the corrosion of the acid system on related equipment and improve the deep acidizing ability. Ultimately, research on the fracture extension mechanism and fluid flow character - istics should be strengthened to achieve theoretical innova- Fig. 3 Mechanism of in  situ foam acidizing technology. Reprint per- tion and technological breakthroughs and solve technical mission obtained from Yan et al. (2019) problems in the process of carbonate reservoir stimulation. Temporary plugging area (a) (b) (c) Natural fracture Acid main Acid branch fracture fractures Artificial fracture Corrosion pores Artificial Acid Natural fracture fracture wormholes Fig. 4 Three-dimensional stimulation diagram of different types of reservoirs: a pore type, b fracture cavity type, c fracture type. Reprint per - mission obtained from Guo et al. (2020) 1 3 994 Petroleum Science (2020) 17:990–1013 and the cave system, the driving force of the displacement 3 Flow characteristics of carbonate pressure difference makes the fluid in the matrix flow under reservoirs the driving pressure gradient. If there is not enough produc- tion pressure die ff rence, the driving pressure gradient is less Reservoir fluid dynamics are the basis for exploring the fluid than the capillary pressure gradient, and the complex pore flow characteristics in a reservoir and must be addressed structure of rock affects the displacement efficiency. In the during oil field development. In sandstone reservoirs, the matrix, crude oil is effectively utilized by the “spontaneous percolation theory in porous media is the core component imbibition and oil drainage” mode generated by capillary of hydrodynamics, while in porous and fractured carbon- pressure. Generally, the capillary force end effect between ate reservoirs, the percolation theory in multiple continuous the injected fluid and the matrix system should be overcome medium fields is the foundation of hydrodynamics (Garland when using crude oil in a carbonate matrix, which depends et al. 2012). The flow characteristics of the above types of on the change in reservoir permeability and wettability. reservoirs are clearly understood and will not be described here. 3.2 Displacement of the fracture system In fracture cavity carbonate reservoirs, the matrix, frac- tures, and cave systems develop together. The water flooding Compared with the matrix system and the karst cave system, process is carried out under the combined effects of driv - the fracture system has the characteristics of “low porosity ing pressure, gravity, and capillary forces. The flow media and high permeability.” The starting pressure difference of of fractured vuggy carbonate reservoirs is shown in Fig. 5. the fluid flow in the system is small, and the capillary force Due to the existence of both “Darcy flow” and “cavity flow” can be ignored. The oil displacement process is carried out in fractured vuggy reservoirs, it is difficult to accurately by driving pressure and gravity. The oil displacement pro- describe the fluid flow characteristics by using the exist- cess of the fracture system may include two methods. First, ing reservoir fluid dynamics theory. Although scholars have as mentioned above, the injected fluid enters the reservoir performed extensive research, the exchange mechanisms and through the fracture system, and the fracture serves as the flow characteristics of fluid between the matrix, fracture, and storage space. When the displacement pressure difference is karst vug have not formed mature related theories. greater than the start-up pressure of the fracture, the crude oil in the fracture is driven out to the karst cave or produc- 3.1 Displacement of the matrix system tion well, and this process can be regarded as piston-type oil displacement. The second method involves the flow between There are two means of oil displacement in the matrix fracture networks. Because of the complex structure of frac- system: differential pressure displacement under external ture networks of different levels, channeling easily occurs in pressure and self-priming oil displacement under capillary the displacement process, such as the fingering of injected force. When both means exist, one is dominant. Generally, fluid and the coning of bottom water. the injected fluid enters the reservoir from fractures or caves under the driving pressure difference, and the fluid entering 3.3 Displacement of the cave system the reservoir is sucked in by the matrix under the action of capillary force and displaces the crude oil. Under the condi- For fractured vuggy reservoirs, there are cases where karst tion of eliminating the interference of the fracture system caves are used as the storage space. In karst cave systems, the flooding process is similar to that in fracture systems. One process involves fluid flow under the imposed pres- Wellbore Flow direction sure gradient, and the other involves vertical differentiation under gravity. If there is edge and bottom water develop- Bedding fracture ment in the reservoir, in the case of a large-scale karst cave, Filled cave the fluid is almost replaced by piston displacement. In an actual reservoir, there is a filling medium in the cave, and Unfilled cave the nature and degree of the filling medium have a great Carbonate matrix influence on the flow characteristics in the cave system. In Fracture zone general, the injected fluid is characterized by percolation- pipe flow-percolation during the process of entering the cave Dissolution pore Collapse cave from the fracture. The main flow in the instant karst cave is pipe flow, and the gravity differentiation determines the displacement pattern. During horizontal flooding, laminar flow at low speeds and wave-like flow at high speeds occur Fig. 5 Flow media in the fractured vuggy reservoir 1 3 Petroleum Science (2020) 17:990–1013 995 in the cave. When vertical gas flooding occurs, layered flows imbibition and replaces the crude oil. However, most car- of fluids and oils appear in the caves. bonate reservoirs are biased toward oil wet reservoirs, which In general, a karst cave system has the characteristics is not conducive to water injection and oil displacement. of high porosity and high permeability, and the production Therefore, changing the type of injection water and adjusting pressure difference required for the fluid to flow in the sys- the injection method are current research directions for water tem is very low. Therefore, the fluid in the karst cave system injection development in carbonate reservoirs. first begins to flow under the actions of displacement and gravity. When the pressure in the cave system drops below 4.1.1 Smart water flooding the starting pressure of the fracture system, channeling of the fracture system to the cave system occurs. Under the action Smart water flooding is considered a low-salinity water flood of capillary pressure, the flow from the matrix system to the to some extent, which means that oil is produced by injecting fracture system or cave system is relatively delayed. Because a special brine into the formation. Low-salinity water flood- of the considerable heterogeneity of the reservoir, the con- ing has been used since the 1960s and has been evaluated nection modes of the fractures and karst caves are diverse, as an effective method to improve oil recovery (Hallenbeck and the filling characteristics are complex. These factors et al. 1991). Today, smart water flooding method has been make the oil displacement mechanism more complex. The successfully applied in sandstone reservoirs, and its devel- final oil displacement effect and remaining oil distribution opment and application in carbonate reservoirs is limited to are controlled by the connection degree, connection condi- pilot studies (Hao et al. 2019). tion and filling mode between the fractures and caves in the There are various mechanisms for smart water flooding karst cave system. to enhance the recovery of carbonate reservoirs. Hiorth Overall, fracture cavity carbonate reservoirs have special et al. (Hiorth et al. 2010) proposed the theory of rock dis- conditions and are difficult to develop. Compared with con - solution; compared with the initial high-salinity formation 2+ 2+ 2− ventional clastic reservoirs, these reservoirs have developed brine, the ion concentration (such as Ca , Mg and SO ) fractures and caves and have low recovery rates. Compared in the injected water decreases, breaking the original ion with sandstone reservoirs, fractured cavity carbonate reser- balance and leading to the dissolution of minerals (such as voirs face many challenges, mainly because fracture perme- CaCO , CaMg(CO ) and CaSO ) in the carbonate rock, 3 3 2 4 ability is much higher than reservoir matrix permeability. thus establishing a new balance with the injected brine. This notable difference in permeability may cause the tra- In this process, the release of the adsorbed polar compo- ditional oil recovery method to fail to affect the crude oil, nents is accompanied by dissolved minerals, thus leading to and the low-viscosity displacement fluid may prematurely increased water wettability and improved oil recovery. How- escape, resulting in low oil washing efficiency. Due to the ever, this mechanism has been refuted to some extent (Aus- difference in density, the injected gas spreads to the upper tad et al. 2009). More scholars now agree with the surface part of the oil layer, and the injected water spreads to the ion exchange theory; on the surface of carbonate rocks, there lower part of the oil layer. The middle layer crude oil cannot is ion exchange between rocks, crude oil and injected water, be effectively accessed. Therefore, fluidity control is very which can improve formation wettability by changing the important. Only by diverting the fluid from the channel to surface charge (RezaeiDoust et al. 2009). The mechanism of the uncovered area can the ultimate recovery be improved smart water flooding to improve the recovery of carbonate (Wang et al. 2017b). reservoirs can be obtained as shown in Fig. 6. Yousef et al. (2012) introduced the results of two smart water injection field tests successfully completed in a car - 4 Development methods of carbonate bonate reservoir in Saudi Arabia to study the effects of reservoirs changing seawater salinity and ion content on oil produc- tion. Combined with their previous research, it was found 4.1 Water flooding that smart water flooding has high application potential in carbonate reservoirs. Smart water flooding has little effect Compared with other methods that can be used to increase on oil–water interfacial tension, mainly because of the inter- recovery in carbonate reservoirs, except for areas where action between the injected fluid and the rock to improve water resources are scarce, water flooding is often consid- oil recovery, which is manifested in improving wettability ered a convenient and cost-effective method (Yousef et al. through the change of the surface charge of the rock and the 2011b). In the water injection process, the injected water enhanced connectivity between pores through microdisso- mainly flows in the fracture system due to the low perme- lution. The performance of smart water flooding is greatly ability of the matrix system of the main oil reservoir. The affected by the reservoir temperature, the physical properties injected water in some fractures enters the matrix through of the rock and the fluid properties of the water. In addition, 1 3 996 Petroleum Science (2020) 17:990–1013 Flow direction Flow direction Smart water Smart water injection Oil drop release mainly due to rock-fluid interfacial effect Oil Flow direction Flow direction Oil bank due to combined effect Coalescence of oil drops due to from both interfaces fluid-fluid interfacial effect Fig. 6 Smart water flooding recovery mechanism using the combined effects from both fluid–fluid and rock-fluid interfaces. Adapted from Ayi- rala et al. (2016) reducing the ion concentration and the presence of polyva- with the traditional C O displacement method, this approach lent ions can enhance the degree of change in the wettability has the following advantages: (1) CWI requires less C O , of smart water flooding (Yousef et al. 2011a, b, c). which reduces the cost of purchasing and transporting C O . As early as 2008, Saudi Aramco focused its research on (2) The density of CO -saturated brine is higher than that of how seawater can increase the production of carbonate res- pure brine, which prevents the flow driven by CO buoyancy ervoirs. Saudi Aramco’s two recent technical papers show and reduces the risk of CO leaking into the ground. (3) that the company has begun to consider how to improve When CO is mixed with brine, it flows in a porous medium, water treatment systems to turn seawater into “smart water” which suppresses the fingering problem of CO flooding and and provide the latest progress in laboratory research to improves the sweep efficiency. (4) The injection of carbon- study how active substances in seawater affect oil produc- ated water into the reservoir can reduce the viscosity and tion (Ayirala et al. 2016). It is clear from these papers and interfacial tension of the oil, improve the formation water other sources that Saudi Aramco’s use of seawater as a cheap wettability, encourage crude oil swelling, and improve the alternative to scarce freshwater can increase the amount of oil mobility in the low permeability matrix (Mahdavi and oil eventually recovered from the ground. The study also James 2019). showed that seawater can be made more effective by chang- At present, most CWI studies have focused on micro- ing its chemical composition into smart water. However, this models and sandstones, and there have been no compre- option is neither simple nor cheap. To reduce the salinity of hensive studies of the application of CWI in carbonate the extremely salty seawater used by Saudi Petroleum, large- reservoirs in the literature, especially when reservoir scale desalination is required (Rassenfoss 2016). When tar- f luids have high salt contents. To understand the mecha- geting carbonate heavy oil reservoirs, low-salinity hot water nism of CWI and improve the oil recovery rate of car- injection is often used to improve oil fluidity (Lee and Lee bonate reservoirs, Jia (2019) took the Lansing carbonate 2019). reservoir in Kansas as an example, carried out relevant oil displacement experiments and analyzed the composi- 4.1.2 Carbonated water flooding tion of the produced water. It was found that the perfor- mance of CWI in carbonate rock is much better than that Carbonated water injection (CWI) is an alternative method of conventional water injection, especially when the rock of gas-phase CO displacement. Before injection, CO is dis- is oil wet. In addition, the oil recovery performance of 2 2 solved in brine at ground level for pretreatment. Compared aged carbonate is more significant than that of non-aged 1 3 Petroleum Science (2020) 17:990–1013 997 carbonate. The dissolution and deposition of carbon- drops between glass and oil, indicating that the model has ate can be observed, and the deposition largely depends strong water wetting characteristics (Seyyedi et al. 2015). on the composition of the brine. Mahzari et al. (2019) injected CO -rich carbonated water into carbonate rocks 4.1.3 Variable strength water injection through visualization experiments and carried out a quan- titative analysis of crude oil recovery and DP profiles. It By changing the injection production intensity, disturb- was found that additional oil recovery can be obtained by ing the pressure field, and eliminating the shielding effect injecting carbonated water, mainly because the interaction of fracture division, variable strength water injection can between CO and water adjusts the oil composition and improve the water swept area of fracture-pore and fracture- the relative permeability of the gas and oil, and the inter- vug reservoirs, whether by periodic water injection, pulse facial tension (IFT) between oil and gas shows a down- water injection, unstable water injection, or asynchronous ward trend, which indicates that light oil components water injection (Li et al. 2018c). are extracted into the gas phase. Ghandi et  al. (2019) Using the elastic energy of rock and fluid to extract part contended that although carbonated water can slightly of the remaining crude oil with EOR is the core concept of reduce the water absorption rate by IFT reduction, the depressurized production. The method of variable-strength most important factor controlling the spontaneous imbi- water flooding in fractured vuggy carbonate reservoirs bition process in oil wet rock is the change in wettability. involves selecting an injection production well group in a The use of saltwater with a specific concentration and fractured vuggy unit for water flooding development and high valence ions can increase water absorption. Mean- adjusting the water flooding intensity continuously during while, carbonated water can accelerate the dissolution of the water flooding process. By forming an unstable water the rock surface and the agglomeration of oil droplets injection flow field in the formation to change the flow field through its own acidity, which also leads to wettability of low water rising, this approach can prevent the formation changes. Riazi (2011) performed micromodel visualiza- of channels during the water displacement process to expand tion experiments and observed some changes in wettabil- the swept volume and enhance oil recovery. ity during CWI. Figure  7 shows the wettability change The oil in the flooded block enters the fracture from the of the micromodel reported by Riazi during CWI. From matrix under the combined effect of rock compression and the direction of the water–oil interface in Fig. 7a, it can liquid expansion and then gathers to the top of the reservoir be seen that after water injection (WI), the micromodel under gravity. In this process, the transformation from arti- shows an increased oil wetting trend; however, in Fig. 7b, ficial driving to natural driving, the spontaneous imbibition c, it can be seen that after CWI, there are small water of the matrix and the drainage of elastic oil are carried out continuously. Using the method of depressurized mining by (a) Glass (b) Water (c) Oil Water-oil interface Fig. 7 Fluid distribution in a section of the micromodel (a) after WI and (b, c) after 19.6 and 47.12 h of CWI, respectively. Reprint permission obtained from Seyyedi et al. (2015) 1 3 998 Petroleum Science (2020) 17:990–1013 alternately combining natural and manual driving, break- while measures such as changing the flow direction of injec- ing the current distribution of underground oil and water at tion wells into production wells achieved better results. high water contents, making the cracks produce differential Song and Li (2018) determined the basic characteristics closure rates, reducing the fracture conductivity, restraining of different types of carbonate reservoirs by studying several and interfering with the oil output of the fracture system and, carbonate reservoirs in the Middle East and proposed three at the same time, making every effort to develop the oil pro- main water injection development methods applicable to dif- duction capacity of the rock block system can be considered ferent carbonate reservoirs. Taking the Mishrif Formation to achieve the goal of improving the ultimate oil recovery. of the Hafaya oilfield as an example, a set of regional well Continuous water injection and proper liquid extraction are pattern high-efficiency water injection development plans adopted to reduce the pressure. Proper artificial water injec- and strategies was proposed, as shown in Fig. 8. tion to supplement the shortage of natural energy and keep the formation pressure at a low level not only ensures that production wells are not abnormal due to low formation 4.2 Gas flooding pressure but also plays the elastic role of rocks and fluids, enhances the production potential of medium and small frac- Gas flooding is the most commonly used method to enhance ture holes and rock block systems, and improves the devel- oil recovery in fractured vuggy carbonate reservoirs. At pre- opment effect (Yu et al. 2017).sent, CO, N and hydrocarbon gas injection are the main 2 2 With the change in formation pressure during the carbon- technologies of EOR in carbonate reservoirs. The release ate reservoir development process, the composition and per- of anthropogenic greenhouse gases (water vapor, carbon colation characteristics of crude oil are constantly changing, dioxide, methane, nitrous oxide) into the atmosphere is the so a reasonable development technology scheme may lead likely cause of global warming, so the injection of these to different oilfield development effects. Zhao et al. (2016) greenhouse gases could alleviate global warming (Pachauri took a fractured carbonate reservoir in the eastern part of the and Meyer 2014). According to the statistics in the World Pre-Caspian Basin as an example, and based on PVT experi- EOR Survey report published by the American Oil and ments, analyzed the influence of formation pressure change Gas Journal from 2000 to 2010, the gas injection projects on the nature of crude oil and established corresponding implemented in carbonate reservoirs are shown in Fig.  9 water injection policies according to the different develop- (Leena 2008; Koottungal 2010; Al Adasani and Bai 2011). ment degrees of water injection fractures in various forma- The largest proportion of injection projects involve CO at tions, which has guiding significance for the reasonable 61%, with 36% engaged in hydrocarbon gas injection and recovery of formation pressure. Yang et al. (2020) took a only 3% engaged in N injection. This is mainly due to the fractured reservoir in the Tahe oilfield as an example, estab-abundant CO gas sources and many related projects in the lished a visual physical model based on real fracture hole USA. In recent years, because of the natural exploitation unit simplification, and carried out multiple groups of water advantage of N drives for fractured vuggy carbonate reser- injection experiments by changing the connectivity type. voirs, this approach has developed rapidly into an indispen- Combined with the field production results, it was found that sable gas drive technology. The miscible pressure of CO is changing injection and production parameters and increasing lower than that of N . Under the same reservoir conditions, the number of flow channels between injection wells and injected CO easily mixes with crude oil to form a miscible production wells had little effect on displacement efficiency, gas drive, while N does not easily mix with crude oil to Reservoir architecture Round 1 inverted nine-spot Round 2 five-spot Round 3 infilled five-spot Round 4 secondary infilled of Mishrif formation well pattern well pattern well pattern five-spot well pattern Barriers Type I reservoirType II reservoirType III reservoir Fig. 8 Schematic diagram for different types of reservoirs developed by different well patterns. Reprint permission obtained from Song and Li (2018) 1 3 Petroleum Science (2020) 17:990–1013 999 the reservoir to displace the crude oil due to gravity differen- 3% tiation. Although nitrogen is not easily miscible with crude 36% oil, it can be partially dissolved in crude oil after making contact, resulting in a reduction in the viscosity and volume CO2 injection expansion of the crude oil. Using the driving energy of the N2 injection Hydrocarbon gas injection injected gas and the expansion elasticity of the crude oil, the partially dissolved crude oil “spills” from its retention space 61% and becomes a displaceable oil phase (Yuan et al. 2015). Among non-hydrocarbon gas flooding methods, N flood- Fig. 9 The proportion of the world’s carbonate reservoir gas injection ing is the most effective enhanced oil recovery technology projects for high-pressure and high-temperature (HP/HT) light oil reservoirs. Generally, in this type of carbonate reservoir, N form a nonmiscible gas drive. Both displacement methods flooding can reach miscibility conditions. However, non- can be used in fractured vuggy carbonate reservoirs, while miscible N is also often used to maintain the formation hydrocarbon gas drives are mainly used in Canada and other pressure or the circulation of condensate gas reservoirs. In countries due to their abundant natural gas resources. the past four decades, the USA has reported a number of There are three displacement processes in gas flooding: fractured vuggy carbonate reservoir N flooding projects. immiscible, near-miscible, and miscible. Miscible flooding Moritis (Leena 2008) reported a miscible WAG-N from Jay refers to the interphase mass transfer between the displacing LEC. In addition to the USA, Cantarell is the only offshore agent (injected gas) and crude oil during the drive process, carbonate oil field with detailed records and representative which dissolves with each other to form a single-phase tran- N flooding projects in the Gulf of Mexico. Due to the high sition zone. The reduction in interfacial tension and capillary availability of N in this area, the number of N flooding 2 2 force makes its flooding efficiency much higher than immis- projects in this area is expected to increase in the near future. cible flooding. Miscible flooding can be further divided into In recent years, the large-scale recovery of N has become first contact miscibility (FCM) and multiple contact mis- inseparable from the reductions in air separation technology cibility (MCM). The success of miscibility development costs and operational costs. In addition, HPAI (high-pressure under reservoir conditions depends on the change of phase air injection) is a promising option, as its application poten- behavior. The key parameter to distinguish the miscible state tial is robust, and its cost is far lower than that of mixed N is the minimum miscible pressure (MMP). Gas and crude oil flooding. In recent years, HPAI projects have been growing can reach miscible state when the injection pressure is higher steadily, especially in light carbonate reservoirs in the USA than the MMP. Oil vaporization and decrease in oil viscos- (Manrique 2009). ity are the main reasons for the high oil recovery of misci- The main advantage of CO is that its miscible pressure ble flooding. The phase of oil and gas is near-miscible or with crude oil is low, and both immiscible and miscible immiscible when the injection pressure is lower than MMP. flooding can be used; however, its density decreases with Solution gas drive and oil swelling can enhance the fluidity increasing temperature, leading to a decrease in the solubil- of crude oil. Whether gas flooding can successfully achieve ity of C O in crude oil. Therefore, the minimum miscible miscible displacement depends on reservoir temperature pressure also increases with increasing temperature. CO is and pressure, injected gas and compositions of the crude easily dissolved in crude oil. Its solubility in crude oil is 3-9 oil. In fact, in carbonate reservoirs, the final displacement times higher than its solubility in water, which can expand efficiency of miscible flooding is affected due to reservoir the volume and reduce the viscosity of crude oil, thereby heterogeneity, but it is still significantly higher than general improving the oil–water mobility ratio and the oil displace- water flooding (Li et al. 2018a). ment efficiency. At the same time, CO can also reduce the oil–water interfacial tension and play a role in dissolved gas 4.2.1 Non‑hydrocarbon gas flooding flooding. These properties confirm that CO flooding is a very competitive method for improving recovery efficiency. N is low in price, stable in chemical properties, low in den- It has a high degree of adaptability to a wide range of physi- sity, insoluble in water and less soluble in crude oil. Com- cal properties and burial depths of crude oil in different res- pared with CO, N has a small compressibility factor, does ervoirs and has low requirements for miscible flooding (Li 2 2 not easily compress, has a high miscibility pressure with et al. 2018a, b, 2019a). However, cost issues limit the wide crude oil, and does not easily form miscibility. These char- application of this technology. Carbonate reservoirs require acteristics make N suitable for massive reservoirs, inclined a large amount of CO injection. Natural C O resources are 2 2 reservoirs and fractured vuggy reservoirs. The injected N usually too far from the injection point, resulting in lower replenishes the formation energy and migrates to the top of CO usage. However, in the USA, C O flooding is the main 2 2 1 3 1000 Petroleum Science (2020) 17:990–1013 technology used because of their considerable CO reserves, 4.2.2 Hydrocarbon gas flooding with the most CO flooding occurring in the world. Accord- ing to survey data from 2014, the annual EOR production Hydrocarbon gas flooding is one of the most widely used from CO flooding reached 1371 × 10  t, accounting for 93% processes in the petroleum industry, and it is a promising of the total annual global EOR from C O flooding (Koot- EOR method that can be used in carbonate oil fields in the tungal 2010). Middle East (Kumar et al. 2017). The injected hydrocarbon The low viscosity and low density of CO can lead to gases include methane, rich gas and liquefied petroleum gas viscous fingering and gas leakage. In addition, reservoir (LPG). These gases usually have the characteristics of sim- heterogeneity is conducive to the transport of C O through ple pretreatment, noncorrosion of pipelines, low miscible high-permeability layers. These three characteristics can pressure and so on. LPG is liquid under high pressure, which lead to the early breakthrough of gas, which reduces the oil is easy to achieve miscibility with crude oil. Although the displacement efficiency of CO gas flooding; this problem displacement efficiency is high after injection into the reser - of gas channeling can also occur during N flooding (Jian voir, the slug drive is usually used due to the high cost. The et al. 2019). Qu et al. (2020) used visualization models and injection of rich gas is similar to LPG. In order to achieve macroscopic models to simulate fractured vuggy carbon- high oil displacement efficiency, the rich gas (C –C ) injec- 2 6 ate reservoirs. On the basis of studying the gas channeling tion slug can be used, and then the other types of low-cost characteristics of fractured vuggy carbonate reservoirs, they displacement media can be injected. Under a high-pressure proposed three risk assessment methods of gas channeling: environment, methane gas is easily dissolved into crude oil the “PIR” of typical fractured vuggy carbonate reservoirs. to form foam oil, resulting in a decrease in the density and Through the verification of reservoir data, the “PIR” risk viscosity of the crude oil. This is conducive to the flow of assessment method can effectively identify gas channeling, crude oil during the displacement process and can achieve a which is of great significance for the prevention and evalu- higher crude oil recovery factor (Ding et al. 2016). ation of gas channeling risk in layers. Laboratory experiments should be carried out to deter- It is worth mentioning that, as one of the most popular mine the feasibility of hydrocarbon injection before field and successful displacement technology, water alternating implementation. Kumar et al. (Kumar et al. 2015) conducted gas (WAG) injection has the advantages of both water injec- pressure/volume/temperature (PVT) experiments and core tion and gas injection. WAG can reduce the relative perme- displacement experiments of natural gas in combination ability of the gas phase, change the gas flow characteristics, with hydrocarbon gas injection projects of carbonate reser- and improve the gas sweep efficiency. The final oil recovery voirs. The results show that the minimum miscible pressure of WAG injection is better than that of gas and water injec- (MMP) of injected natural gas is somewhat higher than the tion alone. After water and gas are alternately injected, water initial reservoir pressure, but crude oil has a strong swelling flooding blocks the high-permeability zone, and gas flood- effect (once saturated by gas, the swelling rate can reach 1.45 ing sweeps tiny pores, which is accompanied by the effect times). An experiment involving unsteady core flooding with of gravity differentiation. And the displacement process is a 200 cm long core showed that the recovery of immisci- a dynamic process in which the state of water in the pores ble flooding can reach 70%, while that of miscible flooding is constantly broken and rebuilt. Generally speaking, the oil can reach 92%. It is thus suggested that gas enrichment and recovery factor of carbonate formation by WAG injection is WAG injection should be used to improve the displacement higher than that of sandstone formation. This is because for effect. reservoirs with severe heterogeneity, the dynamic plugging In a tight heterogeneous carbonate field onshore in Abu caused by alternating water injection can further improve Dhabi, other miscible gas injection tests were implemented the WAG flooding effect. When WAG injection is to be in the injection scheme, thereby improving the spreading adopted, the first decision is whether to use miscible flood- efficiency (Al-Hajeri et al. 2011). These gas injection tri- ing or immiscible flooding. This decision depends on the als indicated that natural gas injection (dry/wet/sweet) is suitability of the reservoir, but it is mainly affected by eco- expected to be a viable EOR option for the Abu Dhabi field. nomic constraints. The application of WAG injection also Dawoud et al. (2010) introduced a case history of an early brings a series of problems. It is easy to cause corrosion and miscible hydrocarbon gas injection project in a newly devel- scaling of the pipe string, blockage caused by hydrates, and oped heterogeneous carbonate reservoir. Based on the analy- poor fluidity control in heavy oil reservoirs. It also led to a sis of 4-year development results, it was concluded that the decrease in gas injection capacity and the relative perme- highest recovery factor can be obtained by the injection of ability of crude oil. miscible hydrocarbon gas. In continental fractured cavity carbonate reservoirs in the USA, hydrocarbon gas injection projects account for a relatively small proportion of all EOR projects (Manrique 1 3 Petroleum Science (2020) 17:990–1013 1001 et al. 2007). In countries rich in natural gas resources, such by a small amount. When the rock is completely heated and as Canada, the development of carbonate reservoirs is domi- injected with new steam, the recovery mechanism is mainly nated by hydrocarbon gas flooding, and there are ongoing driven by steam, and the effect of rock on the fluid is weak - or underevaluated hydrocarbon miscible water injection ened (Wilson 2013). (continuous injection or WAG mode) projects in marine Steam injection thermal recovery seems to be the first carbonate reservoirs. In the WAG process, natural gas is choice for heavy oil reservoirs with carbonate rocks, but con- used to maintain the formation pressure. This development ventional steam injection designs may not be able to produce strategy helps to maintain reservoir energy and maximize oil enough oil to obtain benefits. Due to the characteristics of recovery. At the same time, the potential of hydrocarbon gas low viscosity and high fluidity, steam can easily cross over flooding can be enhanced through a reservoir decompression a flow and overlap, which reduces the sweep volume of the strategy (i.e., reservoir discharge or decompression) at the steam. At the same time, the heterogeneity of carbonate res- end of reservoir development. ervoirs further intensifies the crossflow degree of injected Compared with non-hydrocarbon gases such as carbon steam, so there are few steam injection methods applied to dioxide and nitrogen, there are still many deficiencies in the carbonate reservoirs. Limited field applications include Lacq study of hydrocarbon injection. Due to the relatively high Superior in France, Ikiztepe in Turkey, Yates in the USA, cost of hydrocarbon gases, numerical simulation methods Bati Raman in Turkey, Wafra in Saudi Arabia and Kuwait, are currently used for research. With the increasing tension Oudeh in Syria and Qarn Alam in Oman (Sahuquet et al. of petroleum resources and the importance of environmen- 1990; Nakamura et al. 1995; Snell and Close 1999; Babada- tal protection, the petrochemical industry aims to establish gli et al. 2008; Brown et al. 2011; Li et al. 2010; Smith and atomic economy. Relatively speaking, olefins and hydrogen Parakh 2016). in dry gas have higher value and are easier to recycle and use, which can indicate that some of the hydrocarbon gases 4.3 Chemical flooding may be more economically feasible to be refined and sold rather than to be injected. At the same time, considering the Chemical flooding is an effective method for the develop- safety and controllability of hydrocarbon gas injection, the ment of carbonate fractured reservoirs. Chemical flood- application of hydrocarbon gas flooding in oil fields also ing EOR (C-EOR) technology can be further divided into needs to be carefully selected. polymer flooding, surfactant flooding, alkali flooding, and combinations of these flooding methods. Surfactant/polymer 4.2.3 Thermal recovery by steam injection flooding is the most effective method because it has the syn- ergistic effect of reducing IFT and controlling fluidity with Thermal recovery by steam injection is the main technology minimal negative effects (Bai et al. 2017). In the later stages used for heavy oil extraction. The heavy oil extracted by of oil field development, chemically enhanced oil recovery this technology accounts for more than 80% of the world’s (EOR) technology became economically viable. The C-EOR annual heavy oil production. Steam injection is also an effec- method is a proven technology that may play a key role in tive thermal recovery method for heavy oil extracted from carbonate reservoirs. Carbonate reservoirs are often hetero- carbonate reservoirs with strong heterogeneity. When the geneous and contain natural fractures. By utilizing chemical injected steam flows into the fracture network, it can effec- flooding, the breakthrough of injected gas can be avoided, tively heat the formation to reduce its oil viscosity and dis- thereby improving the sweep efficiency (Koyassan Veedu charge crude oil more effectively by gravity (Li et al. 2019c). et al. 2015). Mohsenzadeh et  al. (2016) conducted a long fracture model experiment, focusing on an oil displacement process under the condition of coinjection of steam and gas. It was found that the coinjection of steam and flue gas under certain conditions can significantly improve the recovery of heavy oil in an experimental model of fractured carbonate rock (Li Free imbibition et al. 2017). Tang et al. (2011) found that steam injection is Thermal expansion a very effective method for carbonate heavy oil reservoirs Forced imbibition and summarized its possible recovery mechanism, as shown Steam drive by flashing Rock compaction in Fig. 10. When steam is injected into carbonate reservoirs, imbibition is the initial recovery mechanism. If the tempera- ture exceeds the critical temperature, free imbibition domi- nates the production process with the aid of heat transfer, Fig. 10 Possible recovery mechanisms for steam injection in frac- and forced imbibition only increases the oil recovery rate tured carbonate rock. Adapted from Tang et al. (2011) 1 3 1002 Petroleum Science (2020) 17:990–1013 4.3.1 Polymer flooding plugging agent that can be used for water injection treat- ment in deep carbonate reservoirs. Polymer flooding is the most widely used chemical flooding Due to the high-temperature and high-salt characteristics method in sandstone reservoirs. For carbonate reservoirs, of some carbonate reservoirs, low-salinity polymer flooding polymers are more commonly used to control the fluidity (LSPF) is a promising EOR method with synergistic effects. of the flooding fluid. Because the injected fluid can eas- Polymers can be added to provide favorable mobility while ily breakthrough in carbonate reservoirs with large fracture changing the wettability of the carbonate rock surface by openings, to improve the recovery of carbonate reservoirs, using low-salinity water in the polymer solution (Khorsandi high viscosity polymers are injected into the formation, and et al. 2017; Vermolen et al. 2014). This synergistic effect they are often used in the initial stage of water injection to increases the efficiency of oil production. In addition, as the increase the fluidity ratio and expand the sweep efficiency seawater desalinates, the degree of degradation of the poly- of the injected fluid (Alsofi et al. 2013). mer decreases, indicating that low-salinity water increases Polymer flooding has been used in many carbonate res- the stability of the polymer (Zaitoun et al. 2012). In addi- ervoirs because it can prevent fracture flow to some extent. tion, the use of low-salinity water requires a small amount of There are 1327 candidate reservoirs suitable for polymer polymer to achieve the target viscosity, which may signifi- flooding in the USA, a third of which are carbonate reser - cantly reduce costs and solve chemical production problems voirs (Mohan et al. 2011). Ultradeep carbonate reservoirs are (Salih et al. 2016). Lee et al. (2019) studied the influence widely distributed in western China and Central Asia, and of injected water pH and PDI on oil recovery when LSPF their oil and gas production can reach 100 million tons per was applied to carbonate reservoirs. It was found that a high 2- year. Because the temperature and salinity of ultradeep car- concentration of SO can improve the wettability of the bonate reservoirs are no less than 130 °C and 220,000 mg/L, formation, reduce the adsorption of the formation on the respectively, developing water blocking agents that can be polymer, and obtain the maximum oil recovery under neutral used in this harsh environment has global impacts (Long conditions. et al. 2009). A considerable number of new temperature- and salt water-resistant gel polymers have been prepared to 4.3.2 Surfactant flooding reduce syneresis during the displacement process. Although several novel acrylamide polymers have been reported in the Surfactant flooding is also a widely used chemical flooding literature, only a few have been industrialized (Singh and technology in fractured vuggy carbonate reservoirs. Low Mahto 2016; Chen et al. 2018). Partially hydrolyzed poly- oil recovery after water injection in carbonate reservoirs is acrylamide (HPAM) is the most widely used polymer for caused by wettability and IFT problems, which reduce the chemical EOR due to its high water solubility (Sheng 2010; impact of spontaneous water absorption processes (Dong Zhang and Seright 2013). HPAM is a polyelectrolyte with a and Al Yafei 2015). In fractured reservoirs, self-absorption negative charge on carboxylate (–COOH) and is highly sen- may infiltrate into the fractures from the rock matrix, leading sitive to pH, salinity, ionic composition and concentration. to the evacuation of oil from the matrix to the fracture net- When the pH of the supplemental brine is low, the polymer work. This mechanism makes surfactants attractive, which chains are coiled, and the polymer adsorption on the rock can improve the recovery of oil wet carbonate reservoirs by surface increases, resulting in the loss of the polymer (Choi changing the wettability of the rock (to the mixed/water wet et al. 2010). In addition, due to the charge shielding effect, state) and promoting the water absorption process. Because the polymer has poor viscosity and stability when it is higher the reserves of fractured vuggy carbonate reservoirs account than a certain salinity (Abidin et al. 2012; Unsal et al. 2018). for a large proportion of the world’s oil reserves, the chemi- Compared with other new types of hydrogels, PAtBA and cal assistant method based on surfactant injection (i.e., spon- polyethyleneimine (PEI) crosslinking systems are widely taneous imbibition, wetting agent, and ITF reduction) is an used to block water in reservoirs. Many researchers have active research field, often used as an important method to studied the mechanisms of heat resistance and salt toler- improve the recovery of fractured vuggy carbonate reser- ance in detail (Eoff et al. 2007; Bai et al. 2015). However, voirs (Alvarado and Manrique 2010). By changing the wet- the cost of PatBA and PEI is high, so it is not reasonable to tability of the surfactants, the interfacial tension of oil/water use PAtBA-PEI hydrogels when the international oil price is can be effectively reduced to ultralow values, the adsorp- low. Chen et al. (2019a) carried out a series of experiments tion capacity can be reduced and the absorption process can and evaluated the stability mechanism of an acrylamide/ be promoted (Farhadinia and Delshad 2010; Alvarado and acryl-acid/2-acrylamido-2methyl-propanesulfonate (AM/ Manrique 2010; Kiani et al. 2011). AA/AMPS) hydrogel. It was found that the AM/AA/AMPS Austad and colleagues conducted a series of studies of the hydrogel is an excellent temperature- and salt-resistant use of surfactant solutions to recover oil from oil wet chalk cores (Standnes and Austad 2000a, b, 2003; Austad and 1 3 Petroleum Science (2020) 17:990–1013 1003 Milter 1997). The results showed that cationic surfactants et  al. 2007), the Mauddud oil field in the Arabian Basin (such as DTAB) are very effective (OOIP is approximately (Zubari and Sivakumar 2003) and the Semogal oil field in 70%) in absorbing water into the original oil wet core at a South Sumatra, Indonesia (Rilian et al. 2010). Most of the higher concentration than its CMC (approximately 1 wt%). test results have been confirmed, verifying the feasibility The mechanism is considered to operate as follows: (1) Ion of surfactant flooding to improve the recovery of fractured pairs are formed through the interaction between the sur- carbonate reservoirs. factant monomer and the organic carboxylates adsorbed in the crude oil. (2) The water wettability of the solid surface 4.3.3 ASP flooding and foam flooding is enhanced due to the dissolution of the ion pairs in the oil phase. (3) As the capillary pressure absorbs saltwater ASP flooding combines the mechanisms of alkali flooding, independently, the water absorption rate decreases with surfactant flooding and polymer flooding. In the formulation increasing temperature and has a negative correlation with selection of ASP, the most commonly used basic additives the irreducible water saturation. Wu et al. (2010) reported are sodium carbonate and sodium bicarbonate with neutral that an anionic surfactant (alkyl alcohol propoxylated sul- pH values. The most commonly used surfactant is petro- fate), as an effective candidate for C-EOR, can reduce IFT at leum sulfonate, while the polymer is usually polyacryla- low concentrations and recover 50% of the residual oil under mide. By increasing the charge density on the surface of high salinity. Zhang et al. (2015) developed a new type of the rock, the basic additives can reduce the adsorption of zwitterionic surfactant derived from castor oil, which can anionic surfactants on the formation, promote the emulsi- −3 reduce IFT to an ultralow value of 5.4 × 10  mN/m at a min- fication of crude oil and regulate the phase behavior. Sur - eralization of 10 g/L. These types of surfactants are suitable factants can enhance the oil washing efficiency by reducing for high-temperature and high-salinity carbonate reservoirs. the interfacial tension between oil and water, and polymers Surfactant for tertiary oil recovery in carbonate reservoirs can improve the fluidity by increasing the viscosity of the is still in a developing stage, and there is not a widely appli- solution to improve the sweep efficiency and oil recovery cable surfactant system. Commonly used are anionic, cati- (Kon et al. 2002; Zubari and Sivakumar 2003). onic, non-ionic and amphoteric surfactants. The molecules ASP flooding is a tertiary oil recovery method that is gen- of anionic surfactants are negatively charged after being ion- erally used in sandstone reservoirs but seldom used in car- ized in water, while the surface of carbonate rocks is nor- bonate reservoirs. In some experimental studies, it was found mally positively charged (the isoelectric point of limestone that the conventional ASP formula can be applied to carbon- is 9.2, the isoelectric point of dolomite is 7.4). Therefore, the ate reservoirs. Although ASP composite flooding technology adsorption capacity of this kind of surfactants on the surface has the development prospect, the adaptability condition of of carbonate rocks is relatively high. Cationic surfactant is a alkali flooding is harsh. Generally speaking, the required kind of effective surfactant for EOR of carbonate reservoir. acid value of crude oil is greater than 0.5, the relative density Cationic surfactant has good temperature and salt resistance, is about 0.9, and the viscosity is lower than 200 mPa s. High- and its adsorption capacity on the surface of positive carbon- density crude oil often contains enough organic acids, which ate is also low. However, the high demand concentration can react with alkali solution to form favorable saponifiable and high cost of this kind of surfactant limit its application substances. On the other hand, when the alkaline solution in oil fields. At present, there are few studies of the adsorp- contained in ASP flooding agent is injected into the oil well, tion of surfactants on carbonate rocks. The adsorption of it reacts with reservoir rock, including dissolution, mixing surfactants on sandstone or other solid surfaces can be used and ion exchange. Thus, the problems such as formation for reference. At the same time, in order to select a suitable damage, scale corrosion and flow resistance, equipment surfactant system, it is necessary to analyze the specific res- wear and so on, seriously affect the normal production of ervoir conditions. Most carbonate reservoirs are high tem- oil wells. Therefore, it is usually feasible to use SP flood- perature and high salt, so the selected surfactant should have ing with the synergistic effect of surfactants and polymers. good temperature and salt resistance, low adsorption loss Dual composite flooding technology has the advantages of and good interfacial activity. reducing interfacial tension and plugging high-permeability There are few examples of e fi ld applications of surfactant channel, so it has high displacement efficiency in carbonate flooding. The limited field applications in the open litera- reservoir. ture include, for example, the Asmari oil field in Iran, the Foam fluid can be used to control the fluidity of gas and Sabriyah-mauddud oil field in Kuwait and the Abu Dhabi water during the displacement process (Wang et al. 2017a; oil field in the United Arab Emirates (Carlisle et al. 2014). Zhu et al. 2017). The water-based foam bursts when it comes A series of surfactant stimulation measures have been car- into contact with oil, and the released surfactant can further ried out in the Yates oil field in Texas (Chen et al. 2000) reduce the interfacial tension between oil and water (Simjoo and the Cottonwood Creek oil field in Wyoming (Manrique and Zitha 2013; Li et al. 2020a). The foam preferentially 1 3 1004 Petroleum Science (2020) 17:990–1013 enters the area with high permeability, which is conducive to temperature and high salt in the fracture cavity reservoir, adjusting the injection profile (Li et al. 2019b). The mecha- the foam does not easily remain in a stable condition, and nism is shown in Fig. 11. Foam flooding and foam plugging the sealing capacity of the foam is limited. It is not effec - have been shown to have a beneficial effect on the develop- tive for highly permeable fracture cavity units, and blocking ment of carbonate reservoirs (Wen et al. 2019; Hou et al. requires the cooperation of certain blocking agent materials. 2018; Li et al. 2020b). However, under high-temperature By selecting a plugging agent with good plugging perfor- and high-salinity (HTHS) conditions, foam stability remains mance, and the foam has permeability selectivity, that is, challenging for two reasons. First, the strength of the foam the foam preferentially plugs the high-permeability layer, usually decreases with increasing temperature because the and the plugging agent can also have plugging selectivity viscosity of the liquid phase decreases at high temperatures, through the foam carrying. The migration distance of the which accelerates the liquid discharge process in the foam plugging agent is relatively short, and the foam can be con- liquid film and the plateau boundary. Second, the water tinuously destroyed and regenerated in the formation and can stability of conventional surfactants limits their use under carry the plugging agent to the deep part of the formation, HTHS conditions. Some researchers have investigated new effectively extending the lateral plugging distance. Foam has surfactant-stabilized foams for HTHS conditions. Cui et al. adjustable density. By changing the gas–liquid ratio of the (2016) studied the application of Ethomeen C12 surfactant- foam, the foam quality can be adjusted, and the gravity dif- stabilized foam under HTHS conditions in carbonate res- ference can be used to carry the plugging agent to achieve ervoirs. The surfactant was stable only at a lower pH (near longitudinal plugging to a certain extent (Li et al. 2019d). 4) because it requires C12 to be completely protonated to dissolve. Xue et al. (2015) reported a high-viscosity foam 4.3.4 Addition of nanoparticles produced by using CO soluble ionic surfactants at a tem- perature of 120 °C and a saltwater TDS content of 14.6%. One of the advantages of nanoparticles is that they can be Recently, Alzobaidi et al. (2017) reported the use of zwit- grafted or modified with different functional groups to pro- terionic surfactants to prepare highly stable foams with a vide the properties required for underground applications. viscosity in excess of 100 cP at 120 °C. These include increased viscosity (Ponnapati et al. 2011), A foam blocking agent is a kind of blocking system that improved water stability (Griffith and Daigle 2017) and is widely used in the regulation of gas channeling. Because required surface wettability (Panthi et al. 2017). This makes the foam is stable in water, defoams in oil, and increases nanoparticles very promising in oilfield applications. the blocking capacity with the increase in permeability, it Nanoparticles (NPs) are now widely recognized in the can play a good role in fluidity control and can effectively field of petroleum engineering. They are used in different address the problem of channeling in heterogeneous forma- areas of oil exploration and production, such as drilling, tions. At the same time, because the gas phase density in the logging, reservoir management and EOR. Due to the size foam is relatively low, it can effectively increase the utiliza- of NPs, they have special physical and chemical properties. tion of the top oil layer. When the foam flows in a fracture Therefore, NPs affect the characteristics of the fluid system, cavity system, due to the severe formation conditions of high including viscosity, magnetism, and IFT. Injecting NPs into a reservoir for EOR is more effective than injecting water, but it is not as effective as chemical flooding. Therefore, NPs are injected with low-salinity water (LSW) or chemi- Inj. Prod. cals (such as surfactants) to increase oil recovery. NPs are used to prevent fine particle migration during LSW injec- tion, control the fluidity of formation water, and reduce the Gas Oil adsorption of surfactants on the pore walls of the reservoir Regular gas injection (Olayiwola and Dejam 2019). In recent years, NPs coated with chemical agents (such as Regular water injection polymers and surfactants) have attracted widespread atten- Water Oil tion. The purpose is to change the wettability of the reservoir from oil wetting to water wetting to improve oil production (Shalbafan et al. 2019). Wang et al. (2019) used the Truva oil field in northern Kazakhstan as an example to comprehen- Foam improves Foam Oil sweep efficiency sively evaluate the plugging effect and oil/water selectivity of polymer microspheres (PMs) in carbonate matrix cores and fractured cores. Through scanning electron microscopy (SEM) imaging results and energy dispersive spectroscopy Fig. 11 Field applications of foam for EOR (Skauge et al. 2020) 1 3 Petroleum Science (2020) 17:990–1013 1005 (EDS) elemental analysis techniques, it was found that the 4.4 Application of emerging technologies blocking mechanism of PMs in the throat and cracks of cores is mainly manifested in three aspects: adsorption retention, 4.4.1 Electromagnetic oil production mechanical retention and agglomeration. By dispersing nan- oparticles in low-salinity water, most problems associated Recently, some emerging eco-friendly technologies have with rock/fluid interactions can be eliminated by improving been proposed to enhance the recovery of crude oil, the attractive force between fine particles and the particle including the application of magnetic fields and electro- surface (Arab and Pourafshary 2013) and preventing forma- magnetic waves. A technology called magnetic water tech- tion damage (Abhishek et al. 2018). Ali et al. (2019) syn- nology has been used in different industries in the past thesized a polymer/nanoparticle composite material using few years, and Hashemizadeh et al. (2014) tried to use pomegranate seed extract as a raw material. The material it for crude oil displacement. It was found that with the was dispersed in diluted seawater to obtain a low-salinity increase in the magnetism of water, the activity of water polymer nanofluid, which interacted with crude oil to obtain molecules changed, and the breakthrough speed was accel- a stable emulsion. As shown in Fig. 12, the fluid can improve erated. For a thin oil layer with low permeability and deep the formation water wetness and adjust the displacement depth, an electromagnetic wave or microwave at a certain profile. radio frequency range can produce the effect of thermal The high apparent viscosity of foam is attributed to the oil recovery. Electromagnetic heating is used to transfer viscoelasticity of the surfactant. By adding nanoparticles the electric energy to the dielectric material in the form of with customized surface coatings to surfactants, it is possi- heat. By injecting fluid with strong absorption into the oil ble to make the generated foam more firm and stable (Singh layer, the oil layer is directly heated, creating a high heat and Mohanty 2020). Sun et al. (2014) introduced modified utilization rate, low oil viscosity and improved oil mobil- hydrophobic SiO nanoparticles into the foam system. It was ity (Kashif et al. 2011; Xu et al. 2019; Zaid et al. 2014). found that SiO nanoparticles significantly improved the vis- In addition, when dealing with the leakage of offshore coelasticity of the foam liquid film, and the foam was not crude oil, electric and magnetic methods have also been easily deformed. This process could produce more micro- combined to improve the recovery efficiency of light crude forces in the displacement process and drive more oil. The oil (Liu et al. 2018). mechanism is shown in Fig. 13. In carbonate reservoirs, the charge on the surface of the rock has a great effect on the wettability of the formation. 2− 2+ The ions (C O and Ca ) that determine the potential of the rock surface are susceptible to external conditions, which Oil-nanofluid emulsion Nanoparticles Oil-polymeric nanofluid emulsion Xanthan gum Oil-polymer emulsion Fig. 12 Schematic diagram illustrating the trapped crude oil and low-salinity polymeric-nanofluid emulsion. Reprint permission obtained from Ali et al. (2019) 1 3 1006 Petroleum Science (2020) 17:990–1013 Water Nanoparticle Bubble Bubble Water Water Water Oil droplet Oil droplet Fig. 13 Displacement differences for an oil droplet on a pore wall by SDS foam (left) and SiO /SDS foam (right). Reprint permission obtained from Sun et al. (2014) can cause changes in the surface adsorption of the rock, and adjusted in the next stage (solvent injection) (Al-Bahlani changes in their surface forces can affect the flow of fluid and Babadagli 2011). in the pores. By adding a magnetic field to the carbonate According to the SOS-FR method, the team of Moham- formation, the formation wettability transitions from oil wet med and Babadagli (2016) has carried out combined experi- to water wet, so the compatibility of the water and rock sur- ments on the cores of Canada’s Grosmont carbonate reser- face is improved, and the spontaneous imbibition speed of voir under different conditions. This method can increase injected water is accelerated to replace more crude oil in the crude oil production, and the optimized process can quickly fractures and ultimately improve the oil recovery (Amrouche promote asphalt recovery, showing economic and effective et al. 2019). application potential. Based on the laboratory- and field- scale analysis of heavy oil recovery by the SOS-FR method, 4.4.2 Steam‑over‑solvent injection Al-Gosayir et  al. (2015) optimized SOS-FR technology through overall improvements and adjusted the heated steam Steam-assisted gravity drainage (SAGD) is a common injection stage, solvent injection stage and low-temperature method used for asphalt recovery in steam injection in Can- steam injection stage to improve the profits and efficiency ada (Butler 1994, 1998). The vapor extraction (VAPEX) of carbonate reservoir development. process is a method that injects pure solvent from horizon- tal wells to replace oil by gravity drainage. It was proposed 4.4.3 In‑situ oil recovery by Butler and Mokrys (1991) as an alternative method of steam injection. To promote the interaction between steam In the development of carbonate reservoirs, energy and the and heavy oil in fractured vuggy carbonate reservoirs, other environment are two major concerns that exist together. It methods of steam-over-solvent injection in fractured reser- is necessary to seek an environmentally friendly reservoir voirs (SOS-FR) have been proposed (Al Bahlani and Babad- development method. The in situ mining model solves two agli 2009, 2012). problems in the development of carbonate reservoirs. One SOS-FR is a new method that was used in early 2008 to is to greatly reduce pollution to the ground environment, recover heavy oil from fractured (especially oil wet) res- and the other is to improve the efficiency of oil production. ervoirs. It takes advantage of injecting steam and solvents In situ combustion (ISC) can reduce the viscosity of into fractured reservoirs to efficiently extract heavy oil from heavy oil through the heat generated at the combustion fractured carbonate reservoirs. The main idea behind this front and make it flow to the production well. Heat is formed technology is to generate a variety of thermal and chemical and maintained by injecting air or oxygen enriched under disturbances that cause the system to readjust, thus driving high temperature and pressure and burning deposited fuel oil from the matrix to the fractures. Therefore, introducing (Aleksandrov et al. 2017). During the combustion process, a thermal difference between the fracture and the matrix the heat generated promotes the thermal cracking reaction, can cause the oil trapped in the matrix to thermally expand thereby increasing the proportion of low molecular weight first. Under the influence of wettability, a certain amount of compounds. On the other hand, coking reactions occur with water (condensate from steam) is absorbed into the matrix. heavy components such as asphaltenes, and coke deposition During this period, the viscosity of the crude oil decreases is not conducive to the combustion process. As an effective and accelerates its discharge, and the oil in the matrix is thermal oil recovery technology, ISC can achieve greater displacement efficiency and technically enhance heavy oil. 1 3 Injector Producer Petroleum Science (2020) 17:990–1013 1007 However, in natural fractured carbonate heavy oil reservoirs, The enhancement of fracture connectivity and the the application of ISC still has various obstacles (Chen et al. improvement of conductivity in carbonate reservoirs are 2019b). particularly important, which requires advanced acid fractur- In-situ upgrading technology (ISUT) is a new alternative ing stimulation technology to achieve. At the same time, for method in the production of heavy oil and asphalt, which deep carbonate reservoirs, how to achieve deep acidic fi ation can not only improve the recovery factor but also upgrade and propose new acid fracturing technology is the focus of the crude oil at a certain stage. In this method, the vacuum future research. For fractured vuggy carbonate reservoirs, residue (VR) recovered from the produced oil is injected into on the basis of realizing reservoir stimulation, it is of great a reservoir with a nanocatalyst and hydrogen, and a modifi- significance to accurately grasp the flow characteristics of cation reaction is performed (Elahi et al. 2019). The mecha- reservoir fluid for efficient development, which depends on nism is shown in Fig. 14. ISUT is more environmentally theoretical analysis and numerical simulation means, and friendly than other recovery technologies, such as steam- requires the assistance of artificial intelligence and the oper - assisted gravity drain (SAGD). In addition, after preliminary ation of big data. economic evaluation and research, it was found that the oil In the process of water injection development, the power recovery rate and return rate of the ISUT process are higher of oil displacement is mainly provided by the driving pres- than those of SAGD (Nguyen et al. 2017). sure difference, capillary force and gravity. During the devel- opment of stable water injection, spontaneous infiltration and oil drainage are mainly caused by capillary forces in the matrix. However, this phenomenon is only obvious when 5 Challenges and prospects the reservoir is water wet, and it has the characteristics of fast speed and low efficiency. The wettability of carbonate There are many differences in carbonate reservoirs through- reservoirs can be improved by adjusting the properties of out the world, such as complex geological structures, strong injected water (such as low-salinity treatment and carbona- reservoir heterogeneity, and harsh reservoir conditions. The tion). The large pore-throat ratio and oil–water viscosity existing development technology still cannot completely ratio are the main reasons for the low efficiency of spon - solve the problems in the development process of carbonate taneous imbibition and oil drainage. In a fracture system, reservoirs, and many challenges remain in the research on water drive and gravity are the dominant factors, and the EOR technology. choice of water injection mode has a great influence on oil Upgraded oil (>20° API) Vacuum distillation unit Cat-Skid H VR VR + H ( + Cat.) Overburden Heavy Recovery zone Heating oil Catalyst zone adsorption Fig. 14 Schematic of the ISUT for a carbonate reservoir. Reprint permission obtained from Elahi et al. (2019) 1 3 1008 Petroleum Science (2020) 17:990–1013 recovery. The research shows that unstable water injection be established according to the type, connectivity, and spa- is an effective way to improve the recovery of fractured car - tial location of the reservoir unit to improve the control bonate reservoirs. By adjusting the direction of the o fl w e fi ld effect of water and gas injection and the degree of oil pro- and increasing the spread coefficient, the remaining oil can duction and reduce the remaining oil reserves. In the middle be effectively extracted. and late stages of water and gas injection development, it is Gas injection development has been mainly categorized necessary to strengthen the control of oil wells based on the into miscible and immiscible flooding, which has been main control factors and the distribution characteristics of widely used in the field and has achieved good economic the remaining oil and use measures such as gravity drainage benefits. However, the choice of gas injection method is and spontaneous infiltration and drainage to disturb (reform) different in different oilfields in different countries. This the flow field. The research of C-EOR technologies cannot is not only determined by the reservoir conditions and the be ignored; these technologies can replace water injection efficiency of the gas injection method but also affected by and gas injection to a certain extent and maximize the oil the different needs, technical levels and oil prices of various production of carbonate reservoirs. Finally, in combina- countries. Whether the reservoir is water wet or oil wet, the tion with modern methods such as artificial intelligence, a gas phase is always a non-wetting phase, so the injected gas flexible and perfect development plan and technical system occupies the middle part of the fracture, and the nature of should be established to achieve the cost-effective develop- the gas has a great influence on the production effect of the ment of carbonate reservoirs and promote the development crude oil. The expansion of nitrogen and the dissolution of of the world’s petroleum industry. carbon dioxide are widely used to reduce the viscosity of Acknowledgements This project was supported by the Innovation Pro- crude oil, and the injection of miscible hydrocarbon gas in ject for Graduates in UPC (Grant YCX2019016). We acknowledge the fractured cavity media has been shown to be effective. How - National Natural Science Foundation of China (Nos. 51774306 and ever, due to the serious interlayer heterogeneity in fractured 51974346), the Science and Technology Support Plan for Youth Inno- vuggy reservoirs, gas channeling is easily caused by gravity vation of University in Shandong Province under Grant 2019KJH002, the Major Scientific and Technological Projects of CNPC under Grant differentiation between fluids during gas injection, which ZD2019-183-008. We are grateful to the researchers at the Foam Fluid significantly reduces reservoir production. Enhanced Oil & Gas Production Engineering Research Center in Shan- There are two limiting factors that ae ff ct the development dong Province and UPC-COSL Joint Laboratory on Heavy Oil Recov- of carbonate reservoirs: one is the viscosity of crude oil, and ery for their kind help in this study. the other is the generation of channeling. In view of the high Open Access This article is licensed under a Creative Commons Attri- viscosity of crude oil, steam injection and thermal recov- bution 4.0 International License, which permits use, sharing, adapta- ery are often used to reduce the viscosity of crude oil. The tion, distribution and reproduction in any medium or format, as long injection of a surfactant is beneficial to reduce the oil–water as you give appropriate credit to the original author(s) and the source, provide a link to the Creative Commons licence, and indicate if changes interfacial tension and improve the washing efficiency. were made. The images or other third party material in this article are Polymer injection can increase the sweep coefficient and included in the article’s Creative Commons licence, unless indicated block the channel. The plugging capabilities are enhanced otherwise in a credit line to the material. If material is not included in by foam-type plugging agents and particle-based plugging the article’s Creative Commons licence and your intended use is not permitted by statutory regulation or exceeds the permitted use, you will agents. The use of foam to carry particle plugging agents need to obtain permission directly from the copyright holder. To view a can achieve deep plugging. However, the harsh formation copy of this licence, visit http://creativ ecommons .or g/licenses/b y/4.0/. conditions of carbonate reservoirs often have a great impact on the performance of chemical agents, and the development of temperature- and salt-resistant surfactants and polymers is an essential task. 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A review of development methods and EOR technologiesfor carbonate reservoirs

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10.1007/s12182-020-00467-5
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Abstract

Carbonate reservoirs worldwide are complex in structure, diverse in form, and highly heterogeneous. Based on these char- acteristics, the reservoir stimulation technologies and fluid flow characteristics of carbonate reservoirs are briefly described in this study. The development methods and EOR technologies of carbonate reservoirs are systematically summarized, the relevant mechanisms are analyzed, and the application status of oil fields is catalogued. The challenges in the development of carbonate reservoirs are discussed, and future research directions are explored. In the current development processes of carbonate reservoirs, water flooding and gas flooding remain the primary means but are often prone to channeling problems. Chemical flooding is an effective method of tertiary oil recovery, but the harsh formation conditions require high-performance chemical agents. The application of emerging technologies can enhance the oil recovery efficiency and environmental friendli- ness to a certain extent, which is welcome in hard-to-recover areas such as heavy oil reservoirs, but the economic cost is often high. In future research on EOR technologies, flow field control and flow channel plugging will be the potential directions of traditional development methods, and the application of nanoparticles will revolutionize the chemical EOR methods. On the basis of diversified reservoir stimulation, combined with a variety of modern data processing schemes, multichannel EOR technologies are being developed to realize the systematic, intelligent, and cost-effective development of carbonate reservoirs. Keywords Carbonate reservoir · Reservoir stimulation · Flow characteristic · Development method · EOR technology 1 Introduction deposition. The main rock types of carbonate reservoirs include limestone (grainstone, reef limestone, etc.) and Carbonate rocks are sedimentary rocks composed of sedi- dolomite, and their storage space is usually comprised of mentary carbonate minerals (calcite, dolomite, etc.). Most pores, karst caves and fractures (Wang et al. 2012). Gener- carbonate rocks were deposited in warm and clean shal- ally, pores and karst caves are the main storage spaces, and low sea environments, primarily as a result of endogenous fractures serve as both storage spaces and the main flow channels in reservoir rocks. Globally, carbonate reservoirs have become the main oil and gas production resources due Handling Editor: Kun Ma to their ubiquity, uniform thickness, and large scale. Middle Edited by Yan-Hua Sun East oil production accounts for approximately two-thirds of global production, and 80% of Middle East oil-bearing * Song-Yan Li formations are carbonate rocks (Nairn and Alsharhan 1997). lsyupc@163.com Oil production in carbonate reservoirs in North America * Zhao-Min Li accounts for approximately 1/2 of all North American oil lizhm@upc.edu.cn 6 2 production (Wilson 1980a, b). There are nearly 3 × 10  km School of Petroleum Engineering, China University of carbonate rocks in China, accounting for approximately of Petroleum (East China), Qingdao 266580, Shandong, 1/3 of the China’s land area. These data illustrate the impor- China tance of carbonate oil and gas fields in the world. Key Laboratory of Unconventional Oil and Gas The distribution of carbonate rocks accounts for 20% of Development, China University of Petroleum (East China), the total area of global sedimentary rocks; carbonate oil and Ministry of Education, Qingdao 266580, Shandong, China gas resources account for approximately 70% of the world’s Sinopec Group, Beijing 100728, China Vol:.(1234567890) 1 3 Petroleum Science (2020) 17:990–1013 991 oil and gas resources, and proven recoverable reserves than 3500 m. Among them, the oil fields under development account for approximately 50% of the world’s oil and gas with a burial depth of more than 5000 m are mainly concen- resources (Li et al. 2018c). The oil and gas production in trated in North America, Russia, Italy and other regions. In global carbonate reservoirs accounts for approximately recent years, China has made an important progress in the 60% of global oil and gas production (Roehl and Choquette development of deep carbonate rocks in the Tarim Basin 2012). Marine carbonate oil and gas resources account for (Ma et al. 2011). Carbonate rocks are easily fractured. With 90% of global oil and gas resources, as marine carbonate oil increased burial depth, dissolution has a great influence on and gas resources are vast. There are 389 oil and gas basins the pore structure of carbonate reservoirs. Through organic in the world engaged in commercial production, among acid dissolution, hydrothermal dissolution, thermochemical which 208 basins are located in marine carbonate strata. By sulfate reduction (TSR) and other processes, corrosion pores the end of 2013, the proven plus probable (2P) recoverable are formed in the buried environment. Geologists who have reserves of oil, natural gas and condensate that had been long engaged in marine carbonate research are focusing on the 11 14 3 discovered worldwide were 3.534 × 10   t, 3.27 × 10  m development of corrosion pores. These newly discovered deep and 2.24 × 10  t, respectively, and their oil equivalent was and ultradeep carbonate rocks are all ae ff cted by fractures and 6.383 × 10  t. Among them, the 2P recoverable reserves vugs, forming fractured reservoirs with fractures as the main of petroleum, natural gas, and condensate in marine car- storage spaces, which usually contain abundant reserves that 11 14 3 bonate formations were 1.296 × 10   t, 1.2 × 10  m , are amenable to large-scale development. and 1.22 × 10   t, respectively. The oil equivalent was Compared with sandstone reservoirs, carbonate reservoirs 2.382 × 10  t. The recoverable reserves of oil, natural gas have notable differences in geological structure character - and condensate in marine carbonate rock series account for istics and reservoir displacement mechanisms that require 36.7%, 36.7% and 54.5% of the total discovered oil and gas certain particularities in development methods. There are in the world, respectively, accounting for 37.3% of the total many development methods utilized in carbonate reservoirs based on oil equivalence calculations. Figure 1 shows a sum- because depletion is inexpensive, the formations are adapt- mary of the recoverable reserves of marine carbonate reser- able, and natural energy can be fully utilized. For reservoirs voirs in the world. It can be seen that oil and gas are mainly with low stress sensitivity, depletion production is generally concentrated in four oil and gas regions: the Middle East, the used. However, depletion production causes the formation former Soviet Union, North America, and the Asia–Pacific pressure to drop, thus hindering stabilized reservoir pro- region (Wang et al. 2016). duction; the premise of adopting this method is the lack of With the continuous advancement of oil and gas exploration supplementary formation measures and corresponding EOR throughout the world, the development of deep and ultradeep technologies. Therefore, because of these unique character- oil and gas has become a topic of interest. More than 10% istics, it is important to efficiently develop carbonate reser - of carbonate oil and gas fields have a burial depth of more voirs by formulating ideal potential tapping countermeasures and adopting appropriate development methods. This review focuses on the related technical problems in 1020 the development processes of carbonate reservoirs in the 1006 Oil, 10 t world. This study combines the results of laboratory experi- 1000 12 3 Natural gas, 10 m ments and practical applications in oil fields, explains the 140 Condensate, 10 t technological measures for the stimulation of carbonate 120 reservoirs, analyzes the flow characteristics of formation fluid in fractured vuggy carbonate reservoirs, and details the various development methods such as water flooding, gas flooding, chemical flooding, and emerging oil production technologies. The EOR mechanisms for carbonate reservoirs are summarized, and the challenges of carbonate reservoir 40 development and the directions of future development tech- nologies are discussed. 20 17 4 4 2 2 11 1 1 2 Stimulation of carbonate reservoirs The porosity and permeability of carbonate reservoirs in the world are generally low; approximately 80% of reser- Fig. 1 The proven plus probable recoverable reserves of marine car- bonates in the world (Energy 2008; Gautier et al. 1995; USGS 2000) voir porosity values range between 4% and 16%, and the 1 3 Middle East Soviet Union North America Asia-Pacific Africa Central South America Europe Reserves 992 Petroleum Science (2020) 17:990–1013 permeability ranges from 1 to 500 mD. When the matrix However, due to its strong reservoir sensitivity and high permeability of carbonate reservoirs is low, dissolution cost, the economic benefits need to be considered before structures such as pores, fractures and karst caves are devel- using a VES (Barati and Liang 2014). In low-pressure res- oped, and the heterogeneity of these formations is strong. ervoirs, the effect of foam acid fracturing is better than that Natural microfractures and dissolved pores, as the main stor- of conventional acid fracturing. Foam fluid-carrying acid age spaces, provide a large contribution to oil production can achieve u fl idity control and multistage fracturing (MSF) and are often distributed in the form of discontinuous zones (Rahim 2018). The performance of foam acid systems with great randomness. The matching relationship between largely depends on the stability of the foam, which depends natural fractures and pore structures is diverse, which can on the development of thermal resistance and the salt toler- cause divisions within a reservoir, where the connectivity of ance of the foam systems. Organic acids can adapt well to these structures is poor and their conductivity is different. the formation environment of carbonate reservoirs. However, In terms of production characteristics, the initial oil produc- due to their low solubility, there are many limitations in their tion levels can be high, but maintaining stable production is application to acid fracturing. difficult. Therefore, reservoir stimulation measures, such as With the global development of carbonate reservoir stim- acid fracturing, occupy an important position in the efficient ulation, new technologies for acid fracturing have emerged development of carbonate reservoirs. in recent years. Guo et  al. (Guo et  al. 2019) proposed a In the process of carbonate reservoir development, acidiz- hybrid volume stimulation (HVS) technology for tightly ing is an effective measure used to increase production and fractured carbonate reservoirs. The technology includes injection. The injection of an acid solution can eliminate three stages: hydraulic fracturing, large-scale acid fractur- rock cementation or formation plugging through dissolution ing and proppant injection. The core concept is to establish and corrosion to improve the permeability of the reservoir. a complex fracture system with high conductivity, as shown Acid fracturing expands the fracture openings by injecting in Fig. 2. The system includes main fractures, branch frac- pad fluid or acid fluid directly under the condition that the tures, induced fractures, and acid-etched wormholes. HVS injection pressure is higher than the formation fracture pres- technology combines the advantages of traditional hydraulic sure, and the acid fluid produces uneven corrosion on the fracturing and acid fracturing to further improve the stimula- fracture surfaces. Even after the fracture is closed, it main- tion effect of tight fractured carbonate reservoirs. tains a certain conductivity to achieve the effect of increas- In-situ microfoam acidizing is a new type of acidifica- ing oil and gas production. Acid fracturing is an important tion technology. The technology uses conventional chemi- technical means to increase and stabilize the production of cal reactions between acids and carbonate rocks to produce carbonate reservoirs. However, there are severe formation supercritical CO . With the synergistic effect of foaming conditions, such as high temperature, high pressure, and agents and stabilizers, C O foam fluid is generated in situ, high stress, in deep and ultradeep carbonate reservoirs that which carries the acid solution into the carbonate rock pose a great challenge to the implementation of acid fractur- matrix for acidification (Yan et al. 2019). The mechanism ing technology. is shown in Fig. 3. Foamed acid can temporarily block the For the acidic fluid systems commonly used in carbon- high-permeability layer, transfer the acid solution to the low- ate reservoir acidification, Aljawad et al. (2019) provided a permeability area and achieve a uniform treatment of the very detailed summary, including for hydrochloric acid and carbonate reservoirs. Compared with conventional acidifi- organic acids. Hydrochloric acid is widely used because of cation, the selectivity of foamed acid can ensure that less its strong dissolving ability, and under high temperatures, acid is used while still realizing the deep acidification of the the reaction rate of hydrochloric acid is greatly accelerated. reservoir (Li et al. 2008). It is necessary to add a slow release agent to reduce the acid Guo et al. (2020) proposed the technical concept of three- rock reaction and loss rate. The addition of polymer gels can dimensional acid fracturing based on the development of increase the viscosity of the system and reduce the loss of fractured vuggy carbonate reservoirs in the Tarim Basin, acid to a certain extent. However, polymer gels are greatly China. The concept is based on optimizing the deployment affected by temperature and pH, which enhances their per - of collective reservoir space and using long well sections to formance when used as additives. Emulsified hydrochloric penetrate heterogeneous reservoirs to achieve three-dimen- acid, which is usually composed of diesel oil, emulsifier and sional stimulation in the planar and longitudinal directions. acid (DEA), is also a mixture that can reduce acid loss. In The transformation of different types of reservoirs is shown terms of deep acidification, DEA can also prevent corrosion in Fig. 4. For the stimulation of porous and fractured reser- caused by acid contact. However, this acid system may cause voirs, the emphasis is on increasing the area of the fractures considerable reservoir pollution (Nasr-El-Din and Al Moajil and carrying out complex fractures by acid fracturing. For 2007). As a cleaning fluid, a viscoelastic surfactant (VES) fractured vuggy reservoirs with strong heterogeneity, tempo- can provide good viscosity control and shunting ability. rary plugging steering technology or targeted acid fracturing 1 3 Petroleum Science (2020) 17:990–1013 993 Induced fractures Acid reached branches Wormholes Main fracture Fig. 2 Ideal schematic diagram of a complex fracture system created by HVS. Reprint permission obtained from Guo et al. (2019) technology is often used to connect the fractures and vugs while forming main fractures with high conductivity (Li Foam formation et al. 2015). Acid fracturing and other reservoir stimulation technolo- gies can enhance the conductivity of fractures, which is important for increasing the production of carbonate reser- Carbonate rock voirs. With the continuous increase in the depth of explora- tion and development of carbonate reservoirs, the difficulty of reservoir stimulation caused by heterogeneous geologi- cal conditions and complex fluid distributions has become Acidizing reactions increasingly prominent. The solution requires more accurate High fracture and vug identification and description technology. As a result, the adaptability of the new acid fracturing pro- Foam diversion cess has gradually improved. Additionally, the harsh reser- + 2+ Low CaCO3 + 2H Ca + H2O + CO2 voir environment imposes very high requirements for the Carbonate rock Carbonate rock operational equipment and acid system, especially to reduce the corrosion of the acid system on related equipment and improve the deep acidizing ability. Ultimately, research on the fracture extension mechanism and fluid flow character - istics should be strengthened to achieve theoretical innova- Fig. 3 Mechanism of in  situ foam acidizing technology. Reprint per- tion and technological breakthroughs and solve technical mission obtained from Yan et al. (2019) problems in the process of carbonate reservoir stimulation. Temporary plugging area (a) (b) (c) Natural fracture Acid main Acid branch fracture fractures Artificial fracture Corrosion pores Artificial Acid Natural fracture fracture wormholes Fig. 4 Three-dimensional stimulation diagram of different types of reservoirs: a pore type, b fracture cavity type, c fracture type. Reprint per - mission obtained from Guo et al. (2020) 1 3 994 Petroleum Science (2020) 17:990–1013 and the cave system, the driving force of the displacement 3 Flow characteristics of carbonate pressure difference makes the fluid in the matrix flow under reservoirs the driving pressure gradient. If there is not enough produc- tion pressure die ff rence, the driving pressure gradient is less Reservoir fluid dynamics are the basis for exploring the fluid than the capillary pressure gradient, and the complex pore flow characteristics in a reservoir and must be addressed structure of rock affects the displacement efficiency. In the during oil field development. In sandstone reservoirs, the matrix, crude oil is effectively utilized by the “spontaneous percolation theory in porous media is the core component imbibition and oil drainage” mode generated by capillary of hydrodynamics, while in porous and fractured carbon- pressure. Generally, the capillary force end effect between ate reservoirs, the percolation theory in multiple continuous the injected fluid and the matrix system should be overcome medium fields is the foundation of hydrodynamics (Garland when using crude oil in a carbonate matrix, which depends et al. 2012). The flow characteristics of the above types of on the change in reservoir permeability and wettability. reservoirs are clearly understood and will not be described here. 3.2 Displacement of the fracture system In fracture cavity carbonate reservoirs, the matrix, frac- tures, and cave systems develop together. The water flooding Compared with the matrix system and the karst cave system, process is carried out under the combined effects of driv - the fracture system has the characteristics of “low porosity ing pressure, gravity, and capillary forces. The flow media and high permeability.” The starting pressure difference of of fractured vuggy carbonate reservoirs is shown in Fig. 5. the fluid flow in the system is small, and the capillary force Due to the existence of both “Darcy flow” and “cavity flow” can be ignored. The oil displacement process is carried out in fractured vuggy reservoirs, it is difficult to accurately by driving pressure and gravity. The oil displacement pro- describe the fluid flow characteristics by using the exist- cess of the fracture system may include two methods. First, ing reservoir fluid dynamics theory. Although scholars have as mentioned above, the injected fluid enters the reservoir performed extensive research, the exchange mechanisms and through the fracture system, and the fracture serves as the flow characteristics of fluid between the matrix, fracture, and storage space. When the displacement pressure difference is karst vug have not formed mature related theories. greater than the start-up pressure of the fracture, the crude oil in the fracture is driven out to the karst cave or produc- 3.1 Displacement of the matrix system tion well, and this process can be regarded as piston-type oil displacement. The second method involves the flow between There are two means of oil displacement in the matrix fracture networks. Because of the complex structure of frac- system: differential pressure displacement under external ture networks of different levels, channeling easily occurs in pressure and self-priming oil displacement under capillary the displacement process, such as the fingering of injected force. When both means exist, one is dominant. Generally, fluid and the coning of bottom water. the injected fluid enters the reservoir from fractures or caves under the driving pressure difference, and the fluid entering 3.3 Displacement of the cave system the reservoir is sucked in by the matrix under the action of capillary force and displaces the crude oil. Under the condi- For fractured vuggy reservoirs, there are cases where karst tion of eliminating the interference of the fracture system caves are used as the storage space. In karst cave systems, the flooding process is similar to that in fracture systems. One process involves fluid flow under the imposed pres- Wellbore Flow direction sure gradient, and the other involves vertical differentiation under gravity. If there is edge and bottom water develop- Bedding fracture ment in the reservoir, in the case of a large-scale karst cave, Filled cave the fluid is almost replaced by piston displacement. In an actual reservoir, there is a filling medium in the cave, and Unfilled cave the nature and degree of the filling medium have a great Carbonate matrix influence on the flow characteristics in the cave system. In Fracture zone general, the injected fluid is characterized by percolation- pipe flow-percolation during the process of entering the cave Dissolution pore Collapse cave from the fracture. The main flow in the instant karst cave is pipe flow, and the gravity differentiation determines the displacement pattern. During horizontal flooding, laminar flow at low speeds and wave-like flow at high speeds occur Fig. 5 Flow media in the fractured vuggy reservoir 1 3 Petroleum Science (2020) 17:990–1013 995 in the cave. When vertical gas flooding occurs, layered flows imbibition and replaces the crude oil. However, most car- of fluids and oils appear in the caves. bonate reservoirs are biased toward oil wet reservoirs, which In general, a karst cave system has the characteristics is not conducive to water injection and oil displacement. of high porosity and high permeability, and the production Therefore, changing the type of injection water and adjusting pressure difference required for the fluid to flow in the sys- the injection method are current research directions for water tem is very low. Therefore, the fluid in the karst cave system injection development in carbonate reservoirs. first begins to flow under the actions of displacement and gravity. When the pressure in the cave system drops below 4.1.1 Smart water flooding the starting pressure of the fracture system, channeling of the fracture system to the cave system occurs. Under the action Smart water flooding is considered a low-salinity water flood of capillary pressure, the flow from the matrix system to the to some extent, which means that oil is produced by injecting fracture system or cave system is relatively delayed. Because a special brine into the formation. Low-salinity water flood- of the considerable heterogeneity of the reservoir, the con- ing has been used since the 1960s and has been evaluated nection modes of the fractures and karst caves are diverse, as an effective method to improve oil recovery (Hallenbeck and the filling characteristics are complex. These factors et al. 1991). Today, smart water flooding method has been make the oil displacement mechanism more complex. The successfully applied in sandstone reservoirs, and its devel- final oil displacement effect and remaining oil distribution opment and application in carbonate reservoirs is limited to are controlled by the connection degree, connection condi- pilot studies (Hao et al. 2019). tion and filling mode between the fractures and caves in the There are various mechanisms for smart water flooding karst cave system. to enhance the recovery of carbonate reservoirs. Hiorth Overall, fracture cavity carbonate reservoirs have special et al. (Hiorth et al. 2010) proposed the theory of rock dis- conditions and are difficult to develop. Compared with con - solution; compared with the initial high-salinity formation 2+ 2+ 2− ventional clastic reservoirs, these reservoirs have developed brine, the ion concentration (such as Ca , Mg and SO ) fractures and caves and have low recovery rates. Compared in the injected water decreases, breaking the original ion with sandstone reservoirs, fractured cavity carbonate reser- balance and leading to the dissolution of minerals (such as voirs face many challenges, mainly because fracture perme- CaCO , CaMg(CO ) and CaSO ) in the carbonate rock, 3 3 2 4 ability is much higher than reservoir matrix permeability. thus establishing a new balance with the injected brine. This notable difference in permeability may cause the tra- In this process, the release of the adsorbed polar compo- ditional oil recovery method to fail to affect the crude oil, nents is accompanied by dissolved minerals, thus leading to and the low-viscosity displacement fluid may prematurely increased water wettability and improved oil recovery. How- escape, resulting in low oil washing efficiency. Due to the ever, this mechanism has been refuted to some extent (Aus- difference in density, the injected gas spreads to the upper tad et al. 2009). More scholars now agree with the surface part of the oil layer, and the injected water spreads to the ion exchange theory; on the surface of carbonate rocks, there lower part of the oil layer. The middle layer crude oil cannot is ion exchange between rocks, crude oil and injected water, be effectively accessed. Therefore, fluidity control is very which can improve formation wettability by changing the important. Only by diverting the fluid from the channel to surface charge (RezaeiDoust et al. 2009). The mechanism of the uncovered area can the ultimate recovery be improved smart water flooding to improve the recovery of carbonate (Wang et al. 2017b). reservoirs can be obtained as shown in Fig. 6. Yousef et al. (2012) introduced the results of two smart water injection field tests successfully completed in a car - 4 Development methods of carbonate bonate reservoir in Saudi Arabia to study the effects of reservoirs changing seawater salinity and ion content on oil produc- tion. Combined with their previous research, it was found 4.1 Water flooding that smart water flooding has high application potential in carbonate reservoirs. Smart water flooding has little effect Compared with other methods that can be used to increase on oil–water interfacial tension, mainly because of the inter- recovery in carbonate reservoirs, except for areas where action between the injected fluid and the rock to improve water resources are scarce, water flooding is often consid- oil recovery, which is manifested in improving wettability ered a convenient and cost-effective method (Yousef et al. through the change of the surface charge of the rock and the 2011b). In the water injection process, the injected water enhanced connectivity between pores through microdisso- mainly flows in the fracture system due to the low perme- lution. The performance of smart water flooding is greatly ability of the matrix system of the main oil reservoir. The affected by the reservoir temperature, the physical properties injected water in some fractures enters the matrix through of the rock and the fluid properties of the water. In addition, 1 3 996 Petroleum Science (2020) 17:990–1013 Flow direction Flow direction Smart water Smart water injection Oil drop release mainly due to rock-fluid interfacial effect Oil Flow direction Flow direction Oil bank due to combined effect Coalescence of oil drops due to from both interfaces fluid-fluid interfacial effect Fig. 6 Smart water flooding recovery mechanism using the combined effects from both fluid–fluid and rock-fluid interfaces. Adapted from Ayi- rala et al. (2016) reducing the ion concentration and the presence of polyva- with the traditional C O displacement method, this approach lent ions can enhance the degree of change in the wettability has the following advantages: (1) CWI requires less C O , of smart water flooding (Yousef et al. 2011a, b, c). which reduces the cost of purchasing and transporting C O . As early as 2008, Saudi Aramco focused its research on (2) The density of CO -saturated brine is higher than that of how seawater can increase the production of carbonate res- pure brine, which prevents the flow driven by CO buoyancy ervoirs. Saudi Aramco’s two recent technical papers show and reduces the risk of CO leaking into the ground. (3) that the company has begun to consider how to improve When CO is mixed with brine, it flows in a porous medium, water treatment systems to turn seawater into “smart water” which suppresses the fingering problem of CO flooding and and provide the latest progress in laboratory research to improves the sweep efficiency. (4) The injection of carbon- study how active substances in seawater affect oil produc- ated water into the reservoir can reduce the viscosity and tion (Ayirala et al. 2016). It is clear from these papers and interfacial tension of the oil, improve the formation water other sources that Saudi Aramco’s use of seawater as a cheap wettability, encourage crude oil swelling, and improve the alternative to scarce freshwater can increase the amount of oil mobility in the low permeability matrix (Mahdavi and oil eventually recovered from the ground. The study also James 2019). showed that seawater can be made more effective by chang- At present, most CWI studies have focused on micro- ing its chemical composition into smart water. However, this models and sandstones, and there have been no compre- option is neither simple nor cheap. To reduce the salinity of hensive studies of the application of CWI in carbonate the extremely salty seawater used by Saudi Petroleum, large- reservoirs in the literature, especially when reservoir scale desalination is required (Rassenfoss 2016). When tar- f luids have high salt contents. To understand the mecha- geting carbonate heavy oil reservoirs, low-salinity hot water nism of CWI and improve the oil recovery rate of car- injection is often used to improve oil fluidity (Lee and Lee bonate reservoirs, Jia (2019) took the Lansing carbonate 2019). reservoir in Kansas as an example, carried out relevant oil displacement experiments and analyzed the composi- 4.1.2 Carbonated water flooding tion of the produced water. It was found that the perfor- mance of CWI in carbonate rock is much better than that Carbonated water injection (CWI) is an alternative method of conventional water injection, especially when the rock of gas-phase CO displacement. Before injection, CO is dis- is oil wet. In addition, the oil recovery performance of 2 2 solved in brine at ground level for pretreatment. Compared aged carbonate is more significant than that of non-aged 1 3 Petroleum Science (2020) 17:990–1013 997 carbonate. The dissolution and deposition of carbon- drops between glass and oil, indicating that the model has ate can be observed, and the deposition largely depends strong water wetting characteristics (Seyyedi et al. 2015). on the composition of the brine. Mahzari et al. (2019) injected CO -rich carbonated water into carbonate rocks 4.1.3 Variable strength water injection through visualization experiments and carried out a quan- titative analysis of crude oil recovery and DP profiles. It By changing the injection production intensity, disturb- was found that additional oil recovery can be obtained by ing the pressure field, and eliminating the shielding effect injecting carbonated water, mainly because the interaction of fracture division, variable strength water injection can between CO and water adjusts the oil composition and improve the water swept area of fracture-pore and fracture- the relative permeability of the gas and oil, and the inter- vug reservoirs, whether by periodic water injection, pulse facial tension (IFT) between oil and gas shows a down- water injection, unstable water injection, or asynchronous ward trend, which indicates that light oil components water injection (Li et al. 2018c). are extracted into the gas phase. Ghandi et  al. (2019) Using the elastic energy of rock and fluid to extract part contended that although carbonated water can slightly of the remaining crude oil with EOR is the core concept of reduce the water absorption rate by IFT reduction, the depressurized production. The method of variable-strength most important factor controlling the spontaneous imbi- water flooding in fractured vuggy carbonate reservoirs bition process in oil wet rock is the change in wettability. involves selecting an injection production well group in a The use of saltwater with a specific concentration and fractured vuggy unit for water flooding development and high valence ions can increase water absorption. Mean- adjusting the water flooding intensity continuously during while, carbonated water can accelerate the dissolution of the water flooding process. By forming an unstable water the rock surface and the agglomeration of oil droplets injection flow field in the formation to change the flow field through its own acidity, which also leads to wettability of low water rising, this approach can prevent the formation changes. Riazi (2011) performed micromodel visualiza- of channels during the water displacement process to expand tion experiments and observed some changes in wettabil- the swept volume and enhance oil recovery. ity during CWI. Figure  7 shows the wettability change The oil in the flooded block enters the fracture from the of the micromodel reported by Riazi during CWI. From matrix under the combined effect of rock compression and the direction of the water–oil interface in Fig. 7a, it can liquid expansion and then gathers to the top of the reservoir be seen that after water injection (WI), the micromodel under gravity. In this process, the transformation from arti- shows an increased oil wetting trend; however, in Fig. 7b, ficial driving to natural driving, the spontaneous imbibition c, it can be seen that after CWI, there are small water of the matrix and the drainage of elastic oil are carried out continuously. Using the method of depressurized mining by (a) Glass (b) Water (c) Oil Water-oil interface Fig. 7 Fluid distribution in a section of the micromodel (a) after WI and (b, c) after 19.6 and 47.12 h of CWI, respectively. Reprint permission obtained from Seyyedi et al. (2015) 1 3 998 Petroleum Science (2020) 17:990–1013 alternately combining natural and manual driving, break- while measures such as changing the flow direction of injec- ing the current distribution of underground oil and water at tion wells into production wells achieved better results. high water contents, making the cracks produce differential Song and Li (2018) determined the basic characteristics closure rates, reducing the fracture conductivity, restraining of different types of carbonate reservoirs by studying several and interfering with the oil output of the fracture system and, carbonate reservoirs in the Middle East and proposed three at the same time, making every effort to develop the oil pro- main water injection development methods applicable to dif- duction capacity of the rock block system can be considered ferent carbonate reservoirs. Taking the Mishrif Formation to achieve the goal of improving the ultimate oil recovery. of the Hafaya oilfield as an example, a set of regional well Continuous water injection and proper liquid extraction are pattern high-efficiency water injection development plans adopted to reduce the pressure. Proper artificial water injec- and strategies was proposed, as shown in Fig. 8. tion to supplement the shortage of natural energy and keep the formation pressure at a low level not only ensures that production wells are not abnormal due to low formation 4.2 Gas flooding pressure but also plays the elastic role of rocks and fluids, enhances the production potential of medium and small frac- Gas flooding is the most commonly used method to enhance ture holes and rock block systems, and improves the devel- oil recovery in fractured vuggy carbonate reservoirs. At pre- opment effect (Yu et al. 2017).sent, CO, N and hydrocarbon gas injection are the main 2 2 With the change in formation pressure during the carbon- technologies of EOR in carbonate reservoirs. The release ate reservoir development process, the composition and per- of anthropogenic greenhouse gases (water vapor, carbon colation characteristics of crude oil are constantly changing, dioxide, methane, nitrous oxide) into the atmosphere is the so a reasonable development technology scheme may lead likely cause of global warming, so the injection of these to different oilfield development effects. Zhao et al. (2016) greenhouse gases could alleviate global warming (Pachauri took a fractured carbonate reservoir in the eastern part of the and Meyer 2014). According to the statistics in the World Pre-Caspian Basin as an example, and based on PVT experi- EOR Survey report published by the American Oil and ments, analyzed the influence of formation pressure change Gas Journal from 2000 to 2010, the gas injection projects on the nature of crude oil and established corresponding implemented in carbonate reservoirs are shown in Fig.  9 water injection policies according to the different develop- (Leena 2008; Koottungal 2010; Al Adasani and Bai 2011). ment degrees of water injection fractures in various forma- The largest proportion of injection projects involve CO at tions, which has guiding significance for the reasonable 61%, with 36% engaged in hydrocarbon gas injection and recovery of formation pressure. Yang et al. (2020) took a only 3% engaged in N injection. This is mainly due to the fractured reservoir in the Tahe oilfield as an example, estab-abundant CO gas sources and many related projects in the lished a visual physical model based on real fracture hole USA. In recent years, because of the natural exploitation unit simplification, and carried out multiple groups of water advantage of N drives for fractured vuggy carbonate reser- injection experiments by changing the connectivity type. voirs, this approach has developed rapidly into an indispen- Combined with the field production results, it was found that sable gas drive technology. The miscible pressure of CO is changing injection and production parameters and increasing lower than that of N . Under the same reservoir conditions, the number of flow channels between injection wells and injected CO easily mixes with crude oil to form a miscible production wells had little effect on displacement efficiency, gas drive, while N does not easily mix with crude oil to Reservoir architecture Round 1 inverted nine-spot Round 2 five-spot Round 3 infilled five-spot Round 4 secondary infilled of Mishrif formation well pattern well pattern well pattern five-spot well pattern Barriers Type I reservoirType II reservoirType III reservoir Fig. 8 Schematic diagram for different types of reservoirs developed by different well patterns. Reprint permission obtained from Song and Li (2018) 1 3 Petroleum Science (2020) 17:990–1013 999 the reservoir to displace the crude oil due to gravity differen- 3% tiation. Although nitrogen is not easily miscible with crude 36% oil, it can be partially dissolved in crude oil after making contact, resulting in a reduction in the viscosity and volume CO2 injection expansion of the crude oil. Using the driving energy of the N2 injection Hydrocarbon gas injection injected gas and the expansion elasticity of the crude oil, the partially dissolved crude oil “spills” from its retention space 61% and becomes a displaceable oil phase (Yuan et al. 2015). Among non-hydrocarbon gas flooding methods, N flood- Fig. 9 The proportion of the world’s carbonate reservoir gas injection ing is the most effective enhanced oil recovery technology projects for high-pressure and high-temperature (HP/HT) light oil reservoirs. Generally, in this type of carbonate reservoir, N form a nonmiscible gas drive. Both displacement methods flooding can reach miscibility conditions. However, non- can be used in fractured vuggy carbonate reservoirs, while miscible N is also often used to maintain the formation hydrocarbon gas drives are mainly used in Canada and other pressure or the circulation of condensate gas reservoirs. In countries due to their abundant natural gas resources. the past four decades, the USA has reported a number of There are three displacement processes in gas flooding: fractured vuggy carbonate reservoir N flooding projects. immiscible, near-miscible, and miscible. Miscible flooding Moritis (Leena 2008) reported a miscible WAG-N from Jay refers to the interphase mass transfer between the displacing LEC. In addition to the USA, Cantarell is the only offshore agent (injected gas) and crude oil during the drive process, carbonate oil field with detailed records and representative which dissolves with each other to form a single-phase tran- N flooding projects in the Gulf of Mexico. Due to the high sition zone. The reduction in interfacial tension and capillary availability of N in this area, the number of N flooding 2 2 force makes its flooding efficiency much higher than immis- projects in this area is expected to increase in the near future. cible flooding. Miscible flooding can be further divided into In recent years, the large-scale recovery of N has become first contact miscibility (FCM) and multiple contact mis- inseparable from the reductions in air separation technology cibility (MCM). The success of miscibility development costs and operational costs. In addition, HPAI (high-pressure under reservoir conditions depends on the change of phase air injection) is a promising option, as its application poten- behavior. The key parameter to distinguish the miscible state tial is robust, and its cost is far lower than that of mixed N is the minimum miscible pressure (MMP). Gas and crude oil flooding. In recent years, HPAI projects have been growing can reach miscible state when the injection pressure is higher steadily, especially in light carbonate reservoirs in the USA than the MMP. Oil vaporization and decrease in oil viscos- (Manrique 2009). ity are the main reasons for the high oil recovery of misci- The main advantage of CO is that its miscible pressure ble flooding. The phase of oil and gas is near-miscible or with crude oil is low, and both immiscible and miscible immiscible when the injection pressure is lower than MMP. flooding can be used; however, its density decreases with Solution gas drive and oil swelling can enhance the fluidity increasing temperature, leading to a decrease in the solubil- of crude oil. Whether gas flooding can successfully achieve ity of C O in crude oil. Therefore, the minimum miscible miscible displacement depends on reservoir temperature pressure also increases with increasing temperature. CO is and pressure, injected gas and compositions of the crude easily dissolved in crude oil. Its solubility in crude oil is 3-9 oil. In fact, in carbonate reservoirs, the final displacement times higher than its solubility in water, which can expand efficiency of miscible flooding is affected due to reservoir the volume and reduce the viscosity of crude oil, thereby heterogeneity, but it is still significantly higher than general improving the oil–water mobility ratio and the oil displace- water flooding (Li et al. 2018a). ment efficiency. At the same time, CO can also reduce the oil–water interfacial tension and play a role in dissolved gas 4.2.1 Non‑hydrocarbon gas flooding flooding. These properties confirm that CO flooding is a very competitive method for improving recovery efficiency. N is low in price, stable in chemical properties, low in den- It has a high degree of adaptability to a wide range of physi- sity, insoluble in water and less soluble in crude oil. Com- cal properties and burial depths of crude oil in different res- pared with CO, N has a small compressibility factor, does ervoirs and has low requirements for miscible flooding (Li 2 2 not easily compress, has a high miscibility pressure with et al. 2018a, b, 2019a). However, cost issues limit the wide crude oil, and does not easily form miscibility. These char- application of this technology. Carbonate reservoirs require acteristics make N suitable for massive reservoirs, inclined a large amount of CO injection. Natural C O resources are 2 2 reservoirs and fractured vuggy reservoirs. The injected N usually too far from the injection point, resulting in lower replenishes the formation energy and migrates to the top of CO usage. However, in the USA, C O flooding is the main 2 2 1 3 1000 Petroleum Science (2020) 17:990–1013 technology used because of their considerable CO reserves, 4.2.2 Hydrocarbon gas flooding with the most CO flooding occurring in the world. Accord- ing to survey data from 2014, the annual EOR production Hydrocarbon gas flooding is one of the most widely used from CO flooding reached 1371 × 10  t, accounting for 93% processes in the petroleum industry, and it is a promising of the total annual global EOR from C O flooding (Koot- EOR method that can be used in carbonate oil fields in the tungal 2010). Middle East (Kumar et al. 2017). The injected hydrocarbon The low viscosity and low density of CO can lead to gases include methane, rich gas and liquefied petroleum gas viscous fingering and gas leakage. In addition, reservoir (LPG). These gases usually have the characteristics of sim- heterogeneity is conducive to the transport of C O through ple pretreatment, noncorrosion of pipelines, low miscible high-permeability layers. These three characteristics can pressure and so on. LPG is liquid under high pressure, which lead to the early breakthrough of gas, which reduces the oil is easy to achieve miscibility with crude oil. Although the displacement efficiency of CO gas flooding; this problem displacement efficiency is high after injection into the reser - of gas channeling can also occur during N flooding (Jian voir, the slug drive is usually used due to the high cost. The et al. 2019). Qu et al. (2020) used visualization models and injection of rich gas is similar to LPG. In order to achieve macroscopic models to simulate fractured vuggy carbon- high oil displacement efficiency, the rich gas (C –C ) injec- 2 6 ate reservoirs. On the basis of studying the gas channeling tion slug can be used, and then the other types of low-cost characteristics of fractured vuggy carbonate reservoirs, they displacement media can be injected. Under a high-pressure proposed three risk assessment methods of gas channeling: environment, methane gas is easily dissolved into crude oil the “PIR” of typical fractured vuggy carbonate reservoirs. to form foam oil, resulting in a decrease in the density and Through the verification of reservoir data, the “PIR” risk viscosity of the crude oil. This is conducive to the flow of assessment method can effectively identify gas channeling, crude oil during the displacement process and can achieve a which is of great significance for the prevention and evalu- higher crude oil recovery factor (Ding et al. 2016). ation of gas channeling risk in layers. Laboratory experiments should be carried out to deter- It is worth mentioning that, as one of the most popular mine the feasibility of hydrocarbon injection before field and successful displacement technology, water alternating implementation. Kumar et al. (Kumar et al. 2015) conducted gas (WAG) injection has the advantages of both water injec- pressure/volume/temperature (PVT) experiments and core tion and gas injection. WAG can reduce the relative perme- displacement experiments of natural gas in combination ability of the gas phase, change the gas flow characteristics, with hydrocarbon gas injection projects of carbonate reser- and improve the gas sweep efficiency. The final oil recovery voirs. The results show that the minimum miscible pressure of WAG injection is better than that of gas and water injec- (MMP) of injected natural gas is somewhat higher than the tion alone. After water and gas are alternately injected, water initial reservoir pressure, but crude oil has a strong swelling flooding blocks the high-permeability zone, and gas flood- effect (once saturated by gas, the swelling rate can reach 1.45 ing sweeps tiny pores, which is accompanied by the effect times). An experiment involving unsteady core flooding with of gravity differentiation. And the displacement process is a 200 cm long core showed that the recovery of immisci- a dynamic process in which the state of water in the pores ble flooding can reach 70%, while that of miscible flooding is constantly broken and rebuilt. Generally speaking, the oil can reach 92%. It is thus suggested that gas enrichment and recovery factor of carbonate formation by WAG injection is WAG injection should be used to improve the displacement higher than that of sandstone formation. This is because for effect. reservoirs with severe heterogeneity, the dynamic plugging In a tight heterogeneous carbonate field onshore in Abu caused by alternating water injection can further improve Dhabi, other miscible gas injection tests were implemented the WAG flooding effect. When WAG injection is to be in the injection scheme, thereby improving the spreading adopted, the first decision is whether to use miscible flood- efficiency (Al-Hajeri et al. 2011). These gas injection tri- ing or immiscible flooding. This decision depends on the als indicated that natural gas injection (dry/wet/sweet) is suitability of the reservoir, but it is mainly affected by eco- expected to be a viable EOR option for the Abu Dhabi field. nomic constraints. The application of WAG injection also Dawoud et al. (2010) introduced a case history of an early brings a series of problems. It is easy to cause corrosion and miscible hydrocarbon gas injection project in a newly devel- scaling of the pipe string, blockage caused by hydrates, and oped heterogeneous carbonate reservoir. Based on the analy- poor fluidity control in heavy oil reservoirs. It also led to a sis of 4-year development results, it was concluded that the decrease in gas injection capacity and the relative perme- highest recovery factor can be obtained by the injection of ability of crude oil. miscible hydrocarbon gas. In continental fractured cavity carbonate reservoirs in the USA, hydrocarbon gas injection projects account for a relatively small proportion of all EOR projects (Manrique 1 3 Petroleum Science (2020) 17:990–1013 1001 et al. 2007). In countries rich in natural gas resources, such by a small amount. When the rock is completely heated and as Canada, the development of carbonate reservoirs is domi- injected with new steam, the recovery mechanism is mainly nated by hydrocarbon gas flooding, and there are ongoing driven by steam, and the effect of rock on the fluid is weak - or underevaluated hydrocarbon miscible water injection ened (Wilson 2013). (continuous injection or WAG mode) projects in marine Steam injection thermal recovery seems to be the first carbonate reservoirs. In the WAG process, natural gas is choice for heavy oil reservoirs with carbonate rocks, but con- used to maintain the formation pressure. This development ventional steam injection designs may not be able to produce strategy helps to maintain reservoir energy and maximize oil enough oil to obtain benefits. Due to the characteristics of recovery. At the same time, the potential of hydrocarbon gas low viscosity and high fluidity, steam can easily cross over flooding can be enhanced through a reservoir decompression a flow and overlap, which reduces the sweep volume of the strategy (i.e., reservoir discharge or decompression) at the steam. At the same time, the heterogeneity of carbonate res- end of reservoir development. ervoirs further intensifies the crossflow degree of injected Compared with non-hydrocarbon gases such as carbon steam, so there are few steam injection methods applied to dioxide and nitrogen, there are still many deficiencies in the carbonate reservoirs. Limited field applications include Lacq study of hydrocarbon injection. Due to the relatively high Superior in France, Ikiztepe in Turkey, Yates in the USA, cost of hydrocarbon gases, numerical simulation methods Bati Raman in Turkey, Wafra in Saudi Arabia and Kuwait, are currently used for research. With the increasing tension Oudeh in Syria and Qarn Alam in Oman (Sahuquet et al. of petroleum resources and the importance of environmen- 1990; Nakamura et al. 1995; Snell and Close 1999; Babada- tal protection, the petrochemical industry aims to establish gli et al. 2008; Brown et al. 2011; Li et al. 2010; Smith and atomic economy. Relatively speaking, olefins and hydrogen Parakh 2016). in dry gas have higher value and are easier to recycle and use, which can indicate that some of the hydrocarbon gases 4.3 Chemical flooding may be more economically feasible to be refined and sold rather than to be injected. At the same time, considering the Chemical flooding is an effective method for the develop- safety and controllability of hydrocarbon gas injection, the ment of carbonate fractured reservoirs. Chemical flood- application of hydrocarbon gas flooding in oil fields also ing EOR (C-EOR) technology can be further divided into needs to be carefully selected. polymer flooding, surfactant flooding, alkali flooding, and combinations of these flooding methods. Surfactant/polymer 4.2.3 Thermal recovery by steam injection flooding is the most effective method because it has the syn- ergistic effect of reducing IFT and controlling fluidity with Thermal recovery by steam injection is the main technology minimal negative effects (Bai et al. 2017). In the later stages used for heavy oil extraction. The heavy oil extracted by of oil field development, chemically enhanced oil recovery this technology accounts for more than 80% of the world’s (EOR) technology became economically viable. The C-EOR annual heavy oil production. Steam injection is also an effec- method is a proven technology that may play a key role in tive thermal recovery method for heavy oil extracted from carbonate reservoirs. Carbonate reservoirs are often hetero- carbonate reservoirs with strong heterogeneity. When the geneous and contain natural fractures. By utilizing chemical injected steam flows into the fracture network, it can effec- flooding, the breakthrough of injected gas can be avoided, tively heat the formation to reduce its oil viscosity and dis- thereby improving the sweep efficiency (Koyassan Veedu charge crude oil more effectively by gravity (Li et al. 2019c). et al. 2015). Mohsenzadeh et  al. (2016) conducted a long fracture model experiment, focusing on an oil displacement process under the condition of coinjection of steam and gas. It was found that the coinjection of steam and flue gas under certain conditions can significantly improve the recovery of heavy oil in an experimental model of fractured carbonate rock (Li Free imbibition et al. 2017). Tang et al. (2011) found that steam injection is Thermal expansion a very effective method for carbonate heavy oil reservoirs Forced imbibition and summarized its possible recovery mechanism, as shown Steam drive by flashing Rock compaction in Fig. 10. When steam is injected into carbonate reservoirs, imbibition is the initial recovery mechanism. If the tempera- ture exceeds the critical temperature, free imbibition domi- nates the production process with the aid of heat transfer, Fig. 10 Possible recovery mechanisms for steam injection in frac- and forced imbibition only increases the oil recovery rate tured carbonate rock. Adapted from Tang et al. (2011) 1 3 1002 Petroleum Science (2020) 17:990–1013 4.3.1 Polymer flooding plugging agent that can be used for water injection treat- ment in deep carbonate reservoirs. Polymer flooding is the most widely used chemical flooding Due to the high-temperature and high-salt characteristics method in sandstone reservoirs. For carbonate reservoirs, of some carbonate reservoirs, low-salinity polymer flooding polymers are more commonly used to control the fluidity (LSPF) is a promising EOR method with synergistic effects. of the flooding fluid. Because the injected fluid can eas- Polymers can be added to provide favorable mobility while ily breakthrough in carbonate reservoirs with large fracture changing the wettability of the carbonate rock surface by openings, to improve the recovery of carbonate reservoirs, using low-salinity water in the polymer solution (Khorsandi high viscosity polymers are injected into the formation, and et al. 2017; Vermolen et al. 2014). This synergistic effect they are often used in the initial stage of water injection to increases the efficiency of oil production. In addition, as the increase the fluidity ratio and expand the sweep efficiency seawater desalinates, the degree of degradation of the poly- of the injected fluid (Alsofi et al. 2013). mer decreases, indicating that low-salinity water increases Polymer flooding has been used in many carbonate res- the stability of the polymer (Zaitoun et al. 2012). In addi- ervoirs because it can prevent fracture flow to some extent. tion, the use of low-salinity water requires a small amount of There are 1327 candidate reservoirs suitable for polymer polymer to achieve the target viscosity, which may signifi- flooding in the USA, a third of which are carbonate reser - cantly reduce costs and solve chemical production problems voirs (Mohan et al. 2011). Ultradeep carbonate reservoirs are (Salih et al. 2016). Lee et al. (2019) studied the influence widely distributed in western China and Central Asia, and of injected water pH and PDI on oil recovery when LSPF their oil and gas production can reach 100 million tons per was applied to carbonate reservoirs. It was found that a high 2- year. Because the temperature and salinity of ultradeep car- concentration of SO can improve the wettability of the bonate reservoirs are no less than 130 °C and 220,000 mg/L, formation, reduce the adsorption of the formation on the respectively, developing water blocking agents that can be polymer, and obtain the maximum oil recovery under neutral used in this harsh environment has global impacts (Long conditions. et al. 2009). A considerable number of new temperature- and salt water-resistant gel polymers have been prepared to 4.3.2 Surfactant flooding reduce syneresis during the displacement process. Although several novel acrylamide polymers have been reported in the Surfactant flooding is also a widely used chemical flooding literature, only a few have been industrialized (Singh and technology in fractured vuggy carbonate reservoirs. Low Mahto 2016; Chen et al. 2018). Partially hydrolyzed poly- oil recovery after water injection in carbonate reservoirs is acrylamide (HPAM) is the most widely used polymer for caused by wettability and IFT problems, which reduce the chemical EOR due to its high water solubility (Sheng 2010; impact of spontaneous water absorption processes (Dong Zhang and Seright 2013). HPAM is a polyelectrolyte with a and Al Yafei 2015). In fractured reservoirs, self-absorption negative charge on carboxylate (–COOH) and is highly sen- may infiltrate into the fractures from the rock matrix, leading sitive to pH, salinity, ionic composition and concentration. to the evacuation of oil from the matrix to the fracture net- When the pH of the supplemental brine is low, the polymer work. This mechanism makes surfactants attractive, which chains are coiled, and the polymer adsorption on the rock can improve the recovery of oil wet carbonate reservoirs by surface increases, resulting in the loss of the polymer (Choi changing the wettability of the rock (to the mixed/water wet et al. 2010). In addition, due to the charge shielding effect, state) and promoting the water absorption process. Because the polymer has poor viscosity and stability when it is higher the reserves of fractured vuggy carbonate reservoirs account than a certain salinity (Abidin et al. 2012; Unsal et al. 2018). for a large proportion of the world’s oil reserves, the chemi- Compared with other new types of hydrogels, PAtBA and cal assistant method based on surfactant injection (i.e., spon- polyethyleneimine (PEI) crosslinking systems are widely taneous imbibition, wetting agent, and ITF reduction) is an used to block water in reservoirs. Many researchers have active research field, often used as an important method to studied the mechanisms of heat resistance and salt toler- improve the recovery of fractured vuggy carbonate reser- ance in detail (Eoff et al. 2007; Bai et al. 2015). However, voirs (Alvarado and Manrique 2010). By changing the wet- the cost of PatBA and PEI is high, so it is not reasonable to tability of the surfactants, the interfacial tension of oil/water use PAtBA-PEI hydrogels when the international oil price is can be effectively reduced to ultralow values, the adsorp- low. Chen et al. (2019a) carried out a series of experiments tion capacity can be reduced and the absorption process can and evaluated the stability mechanism of an acrylamide/ be promoted (Farhadinia and Delshad 2010; Alvarado and acryl-acid/2-acrylamido-2methyl-propanesulfonate (AM/ Manrique 2010; Kiani et al. 2011). AA/AMPS) hydrogel. It was found that the AM/AA/AMPS Austad and colleagues conducted a series of studies of the hydrogel is an excellent temperature- and salt-resistant use of surfactant solutions to recover oil from oil wet chalk cores (Standnes and Austad 2000a, b, 2003; Austad and 1 3 Petroleum Science (2020) 17:990–1013 1003 Milter 1997). The results showed that cationic surfactants et  al. 2007), the Mauddud oil field in the Arabian Basin (such as DTAB) are very effective (OOIP is approximately (Zubari and Sivakumar 2003) and the Semogal oil field in 70%) in absorbing water into the original oil wet core at a South Sumatra, Indonesia (Rilian et al. 2010). Most of the higher concentration than its CMC (approximately 1 wt%). test results have been confirmed, verifying the feasibility The mechanism is considered to operate as follows: (1) Ion of surfactant flooding to improve the recovery of fractured pairs are formed through the interaction between the sur- carbonate reservoirs. factant monomer and the organic carboxylates adsorbed in the crude oil. (2) The water wettability of the solid surface 4.3.3 ASP flooding and foam flooding is enhanced due to the dissolution of the ion pairs in the oil phase. (3) As the capillary pressure absorbs saltwater ASP flooding combines the mechanisms of alkali flooding, independently, the water absorption rate decreases with surfactant flooding and polymer flooding. In the formulation increasing temperature and has a negative correlation with selection of ASP, the most commonly used basic additives the irreducible water saturation. Wu et al. (2010) reported are sodium carbonate and sodium bicarbonate with neutral that an anionic surfactant (alkyl alcohol propoxylated sul- pH values. The most commonly used surfactant is petro- fate), as an effective candidate for C-EOR, can reduce IFT at leum sulfonate, while the polymer is usually polyacryla- low concentrations and recover 50% of the residual oil under mide. By increasing the charge density on the surface of high salinity. Zhang et al. (2015) developed a new type of the rock, the basic additives can reduce the adsorption of zwitterionic surfactant derived from castor oil, which can anionic surfactants on the formation, promote the emulsi- −3 reduce IFT to an ultralow value of 5.4 × 10  mN/m at a min- fication of crude oil and regulate the phase behavior. Sur - eralization of 10 g/L. These types of surfactants are suitable factants can enhance the oil washing efficiency by reducing for high-temperature and high-salinity carbonate reservoirs. the interfacial tension between oil and water, and polymers Surfactant for tertiary oil recovery in carbonate reservoirs can improve the fluidity by increasing the viscosity of the is still in a developing stage, and there is not a widely appli- solution to improve the sweep efficiency and oil recovery cable surfactant system. Commonly used are anionic, cati- (Kon et al. 2002; Zubari and Sivakumar 2003). onic, non-ionic and amphoteric surfactants. The molecules ASP flooding is a tertiary oil recovery method that is gen- of anionic surfactants are negatively charged after being ion- erally used in sandstone reservoirs but seldom used in car- ized in water, while the surface of carbonate rocks is nor- bonate reservoirs. In some experimental studies, it was found mally positively charged (the isoelectric point of limestone that the conventional ASP formula can be applied to carbon- is 9.2, the isoelectric point of dolomite is 7.4). Therefore, the ate reservoirs. Although ASP composite flooding technology adsorption capacity of this kind of surfactants on the surface has the development prospect, the adaptability condition of of carbonate rocks is relatively high. Cationic surfactant is a alkali flooding is harsh. Generally speaking, the required kind of effective surfactant for EOR of carbonate reservoir. acid value of crude oil is greater than 0.5, the relative density Cationic surfactant has good temperature and salt resistance, is about 0.9, and the viscosity is lower than 200 mPa s. High- and its adsorption capacity on the surface of positive carbon- density crude oil often contains enough organic acids, which ate is also low. However, the high demand concentration can react with alkali solution to form favorable saponifiable and high cost of this kind of surfactant limit its application substances. On the other hand, when the alkaline solution in oil fields. At present, there are few studies of the adsorp- contained in ASP flooding agent is injected into the oil well, tion of surfactants on carbonate rocks. The adsorption of it reacts with reservoir rock, including dissolution, mixing surfactants on sandstone or other solid surfaces can be used and ion exchange. Thus, the problems such as formation for reference. At the same time, in order to select a suitable damage, scale corrosion and flow resistance, equipment surfactant system, it is necessary to analyze the specific res- wear and so on, seriously affect the normal production of ervoir conditions. Most carbonate reservoirs are high tem- oil wells. Therefore, it is usually feasible to use SP flood- perature and high salt, so the selected surfactant should have ing with the synergistic effect of surfactants and polymers. good temperature and salt resistance, low adsorption loss Dual composite flooding technology has the advantages of and good interfacial activity. reducing interfacial tension and plugging high-permeability There are few examples of e fi ld applications of surfactant channel, so it has high displacement efficiency in carbonate flooding. The limited field applications in the open litera- reservoir. ture include, for example, the Asmari oil field in Iran, the Foam fluid can be used to control the fluidity of gas and Sabriyah-mauddud oil field in Kuwait and the Abu Dhabi water during the displacement process (Wang et al. 2017a; oil field in the United Arab Emirates (Carlisle et al. 2014). Zhu et al. 2017). The water-based foam bursts when it comes A series of surfactant stimulation measures have been car- into contact with oil, and the released surfactant can further ried out in the Yates oil field in Texas (Chen et al. 2000) reduce the interfacial tension between oil and water (Simjoo and the Cottonwood Creek oil field in Wyoming (Manrique and Zitha 2013; Li et al. 2020a). The foam preferentially 1 3 1004 Petroleum Science (2020) 17:990–1013 enters the area with high permeability, which is conducive to temperature and high salt in the fracture cavity reservoir, adjusting the injection profile (Li et al. 2019b). The mecha- the foam does not easily remain in a stable condition, and nism is shown in Fig. 11. Foam flooding and foam plugging the sealing capacity of the foam is limited. It is not effec - have been shown to have a beneficial effect on the develop- tive for highly permeable fracture cavity units, and blocking ment of carbonate reservoirs (Wen et al. 2019; Hou et al. requires the cooperation of certain blocking agent materials. 2018; Li et al. 2020b). However, under high-temperature By selecting a plugging agent with good plugging perfor- and high-salinity (HTHS) conditions, foam stability remains mance, and the foam has permeability selectivity, that is, challenging for two reasons. First, the strength of the foam the foam preferentially plugs the high-permeability layer, usually decreases with increasing temperature because the and the plugging agent can also have plugging selectivity viscosity of the liquid phase decreases at high temperatures, through the foam carrying. The migration distance of the which accelerates the liquid discharge process in the foam plugging agent is relatively short, and the foam can be con- liquid film and the plateau boundary. Second, the water tinuously destroyed and regenerated in the formation and can stability of conventional surfactants limits their use under carry the plugging agent to the deep part of the formation, HTHS conditions. Some researchers have investigated new effectively extending the lateral plugging distance. Foam has surfactant-stabilized foams for HTHS conditions. Cui et al. adjustable density. By changing the gas–liquid ratio of the (2016) studied the application of Ethomeen C12 surfactant- foam, the foam quality can be adjusted, and the gravity dif- stabilized foam under HTHS conditions in carbonate res- ference can be used to carry the plugging agent to achieve ervoirs. The surfactant was stable only at a lower pH (near longitudinal plugging to a certain extent (Li et al. 2019d). 4) because it requires C12 to be completely protonated to dissolve. Xue et al. (2015) reported a high-viscosity foam 4.3.4 Addition of nanoparticles produced by using CO soluble ionic surfactants at a tem- perature of 120 °C and a saltwater TDS content of 14.6%. One of the advantages of nanoparticles is that they can be Recently, Alzobaidi et al. (2017) reported the use of zwit- grafted or modified with different functional groups to pro- terionic surfactants to prepare highly stable foams with a vide the properties required for underground applications. viscosity in excess of 100 cP at 120 °C. These include increased viscosity (Ponnapati et al. 2011), A foam blocking agent is a kind of blocking system that improved water stability (Griffith and Daigle 2017) and is widely used in the regulation of gas channeling. Because required surface wettability (Panthi et al. 2017). This makes the foam is stable in water, defoams in oil, and increases nanoparticles very promising in oilfield applications. the blocking capacity with the increase in permeability, it Nanoparticles (NPs) are now widely recognized in the can play a good role in fluidity control and can effectively field of petroleum engineering. They are used in different address the problem of channeling in heterogeneous forma- areas of oil exploration and production, such as drilling, tions. At the same time, because the gas phase density in the logging, reservoir management and EOR. Due to the size foam is relatively low, it can effectively increase the utiliza- of NPs, they have special physical and chemical properties. tion of the top oil layer. When the foam flows in a fracture Therefore, NPs affect the characteristics of the fluid system, cavity system, due to the severe formation conditions of high including viscosity, magnetism, and IFT. Injecting NPs into a reservoir for EOR is more effective than injecting water, but it is not as effective as chemical flooding. Therefore, NPs are injected with low-salinity water (LSW) or chemi- Inj. Prod. cals (such as surfactants) to increase oil recovery. NPs are used to prevent fine particle migration during LSW injec- tion, control the fluidity of formation water, and reduce the Gas Oil adsorption of surfactants on the pore walls of the reservoir Regular gas injection (Olayiwola and Dejam 2019). In recent years, NPs coated with chemical agents (such as Regular water injection polymers and surfactants) have attracted widespread atten- Water Oil tion. The purpose is to change the wettability of the reservoir from oil wetting to water wetting to improve oil production (Shalbafan et al. 2019). Wang et al. (2019) used the Truva oil field in northern Kazakhstan as an example to comprehen- Foam improves Foam Oil sweep efficiency sively evaluate the plugging effect and oil/water selectivity of polymer microspheres (PMs) in carbonate matrix cores and fractured cores. Through scanning electron microscopy (SEM) imaging results and energy dispersive spectroscopy Fig. 11 Field applications of foam for EOR (Skauge et al. 2020) 1 3 Petroleum Science (2020) 17:990–1013 1005 (EDS) elemental analysis techniques, it was found that the 4.4 Application of emerging technologies blocking mechanism of PMs in the throat and cracks of cores is mainly manifested in three aspects: adsorption retention, 4.4.1 Electromagnetic oil production mechanical retention and agglomeration. By dispersing nan- oparticles in low-salinity water, most problems associated Recently, some emerging eco-friendly technologies have with rock/fluid interactions can be eliminated by improving been proposed to enhance the recovery of crude oil, the attractive force between fine particles and the particle including the application of magnetic fields and electro- surface (Arab and Pourafshary 2013) and preventing forma- magnetic waves. A technology called magnetic water tech- tion damage (Abhishek et al. 2018). Ali et al. (2019) syn- nology has been used in different industries in the past thesized a polymer/nanoparticle composite material using few years, and Hashemizadeh et al. (2014) tried to use pomegranate seed extract as a raw material. The material it for crude oil displacement. It was found that with the was dispersed in diluted seawater to obtain a low-salinity increase in the magnetism of water, the activity of water polymer nanofluid, which interacted with crude oil to obtain molecules changed, and the breakthrough speed was accel- a stable emulsion. As shown in Fig. 12, the fluid can improve erated. For a thin oil layer with low permeability and deep the formation water wetness and adjust the displacement depth, an electromagnetic wave or microwave at a certain profile. radio frequency range can produce the effect of thermal The high apparent viscosity of foam is attributed to the oil recovery. Electromagnetic heating is used to transfer viscoelasticity of the surfactant. By adding nanoparticles the electric energy to the dielectric material in the form of with customized surface coatings to surfactants, it is possi- heat. By injecting fluid with strong absorption into the oil ble to make the generated foam more firm and stable (Singh layer, the oil layer is directly heated, creating a high heat and Mohanty 2020). Sun et al. (2014) introduced modified utilization rate, low oil viscosity and improved oil mobil- hydrophobic SiO nanoparticles into the foam system. It was ity (Kashif et al. 2011; Xu et al. 2019; Zaid et al. 2014). found that SiO nanoparticles significantly improved the vis- In addition, when dealing with the leakage of offshore coelasticity of the foam liquid film, and the foam was not crude oil, electric and magnetic methods have also been easily deformed. This process could produce more micro- combined to improve the recovery efficiency of light crude forces in the displacement process and drive more oil. The oil (Liu et al. 2018). mechanism is shown in Fig. 13. In carbonate reservoirs, the charge on the surface of the rock has a great effect on the wettability of the formation. 2− 2+ The ions (C O and Ca ) that determine the potential of the rock surface are susceptible to external conditions, which Oil-nanofluid emulsion Nanoparticles Oil-polymeric nanofluid emulsion Xanthan gum Oil-polymer emulsion Fig. 12 Schematic diagram illustrating the trapped crude oil and low-salinity polymeric-nanofluid emulsion. Reprint permission obtained from Ali et al. (2019) 1 3 1006 Petroleum Science (2020) 17:990–1013 Water Nanoparticle Bubble Bubble Water Water Water Oil droplet Oil droplet Fig. 13 Displacement differences for an oil droplet on a pore wall by SDS foam (left) and SiO /SDS foam (right). Reprint permission obtained from Sun et al. (2014) can cause changes in the surface adsorption of the rock, and adjusted in the next stage (solvent injection) (Al-Bahlani changes in their surface forces can affect the flow of fluid and Babadagli 2011). in the pores. By adding a magnetic field to the carbonate According to the SOS-FR method, the team of Moham- formation, the formation wettability transitions from oil wet med and Babadagli (2016) has carried out combined experi- to water wet, so the compatibility of the water and rock sur- ments on the cores of Canada’s Grosmont carbonate reser- face is improved, and the spontaneous imbibition speed of voir under different conditions. This method can increase injected water is accelerated to replace more crude oil in the crude oil production, and the optimized process can quickly fractures and ultimately improve the oil recovery (Amrouche promote asphalt recovery, showing economic and effective et al. 2019). application potential. Based on the laboratory- and field- scale analysis of heavy oil recovery by the SOS-FR method, 4.4.2 Steam‑over‑solvent injection Al-Gosayir et  al. (2015) optimized SOS-FR technology through overall improvements and adjusted the heated steam Steam-assisted gravity drainage (SAGD) is a common injection stage, solvent injection stage and low-temperature method used for asphalt recovery in steam injection in Can- steam injection stage to improve the profits and efficiency ada (Butler 1994, 1998). The vapor extraction (VAPEX) of carbonate reservoir development. process is a method that injects pure solvent from horizon- tal wells to replace oil by gravity drainage. It was proposed 4.4.3 In‑situ oil recovery by Butler and Mokrys (1991) as an alternative method of steam injection. To promote the interaction between steam In the development of carbonate reservoirs, energy and the and heavy oil in fractured vuggy carbonate reservoirs, other environment are two major concerns that exist together. It methods of steam-over-solvent injection in fractured reser- is necessary to seek an environmentally friendly reservoir voirs (SOS-FR) have been proposed (Al Bahlani and Babad- development method. The in situ mining model solves two agli 2009, 2012). problems in the development of carbonate reservoirs. One SOS-FR is a new method that was used in early 2008 to is to greatly reduce pollution to the ground environment, recover heavy oil from fractured (especially oil wet) res- and the other is to improve the efficiency of oil production. ervoirs. It takes advantage of injecting steam and solvents In situ combustion (ISC) can reduce the viscosity of into fractured reservoirs to efficiently extract heavy oil from heavy oil through the heat generated at the combustion fractured carbonate reservoirs. The main idea behind this front and make it flow to the production well. Heat is formed technology is to generate a variety of thermal and chemical and maintained by injecting air or oxygen enriched under disturbances that cause the system to readjust, thus driving high temperature and pressure and burning deposited fuel oil from the matrix to the fractures. Therefore, introducing (Aleksandrov et al. 2017). During the combustion process, a thermal difference between the fracture and the matrix the heat generated promotes the thermal cracking reaction, can cause the oil trapped in the matrix to thermally expand thereby increasing the proportion of low molecular weight first. Under the influence of wettability, a certain amount of compounds. On the other hand, coking reactions occur with water (condensate from steam) is absorbed into the matrix. heavy components such as asphaltenes, and coke deposition During this period, the viscosity of the crude oil decreases is not conducive to the combustion process. As an effective and accelerates its discharge, and the oil in the matrix is thermal oil recovery technology, ISC can achieve greater displacement efficiency and technically enhance heavy oil. 1 3 Injector Producer Petroleum Science (2020) 17:990–1013 1007 However, in natural fractured carbonate heavy oil reservoirs, The enhancement of fracture connectivity and the the application of ISC still has various obstacles (Chen et al. improvement of conductivity in carbonate reservoirs are 2019b). particularly important, which requires advanced acid fractur- In-situ upgrading technology (ISUT) is a new alternative ing stimulation technology to achieve. At the same time, for method in the production of heavy oil and asphalt, which deep carbonate reservoirs, how to achieve deep acidic fi ation can not only improve the recovery factor but also upgrade and propose new acid fracturing technology is the focus of the crude oil at a certain stage. In this method, the vacuum future research. For fractured vuggy carbonate reservoirs, residue (VR) recovered from the produced oil is injected into on the basis of realizing reservoir stimulation, it is of great a reservoir with a nanocatalyst and hydrogen, and a modifi- significance to accurately grasp the flow characteristics of cation reaction is performed (Elahi et al. 2019). The mecha- reservoir fluid for efficient development, which depends on nism is shown in Fig. 14. ISUT is more environmentally theoretical analysis and numerical simulation means, and friendly than other recovery technologies, such as steam- requires the assistance of artificial intelligence and the oper - assisted gravity drain (SAGD). In addition, after preliminary ation of big data. economic evaluation and research, it was found that the oil In the process of water injection development, the power recovery rate and return rate of the ISUT process are higher of oil displacement is mainly provided by the driving pres- than those of SAGD (Nguyen et al. 2017). sure difference, capillary force and gravity. During the devel- opment of stable water injection, spontaneous infiltration and oil drainage are mainly caused by capillary forces in the matrix. However, this phenomenon is only obvious when 5 Challenges and prospects the reservoir is water wet, and it has the characteristics of fast speed and low efficiency. The wettability of carbonate There are many differences in carbonate reservoirs through- reservoirs can be improved by adjusting the properties of out the world, such as complex geological structures, strong injected water (such as low-salinity treatment and carbona- reservoir heterogeneity, and harsh reservoir conditions. The tion). The large pore-throat ratio and oil–water viscosity existing development technology still cannot completely ratio are the main reasons for the low efficiency of spon - solve the problems in the development process of carbonate taneous imbibition and oil drainage. In a fracture system, reservoirs, and many challenges remain in the research on water drive and gravity are the dominant factors, and the EOR technology. choice of water injection mode has a great influence on oil Upgraded oil (>20° API) Vacuum distillation unit Cat-Skid H VR VR + H ( + Cat.) Overburden Heavy Recovery zone Heating oil Catalyst zone adsorption Fig. 14 Schematic of the ISUT for a carbonate reservoir. Reprint permission obtained from Elahi et al. (2019) 1 3 1008 Petroleum Science (2020) 17:990–1013 recovery. The research shows that unstable water injection be established according to the type, connectivity, and spa- is an effective way to improve the recovery of fractured car - tial location of the reservoir unit to improve the control bonate reservoirs. By adjusting the direction of the o fl w e fi ld effect of water and gas injection and the degree of oil pro- and increasing the spread coefficient, the remaining oil can duction and reduce the remaining oil reserves. In the middle be effectively extracted. and late stages of water and gas injection development, it is Gas injection development has been mainly categorized necessary to strengthen the control of oil wells based on the into miscible and immiscible flooding, which has been main control factors and the distribution characteristics of widely used in the field and has achieved good economic the remaining oil and use measures such as gravity drainage benefits. However, the choice of gas injection method is and spontaneous infiltration and drainage to disturb (reform) different in different oilfields in different countries. This the flow field. The research of C-EOR technologies cannot is not only determined by the reservoir conditions and the be ignored; these technologies can replace water injection efficiency of the gas injection method but also affected by and gas injection to a certain extent and maximize the oil the different needs, technical levels and oil prices of various production of carbonate reservoirs. Finally, in combina- countries. Whether the reservoir is water wet or oil wet, the tion with modern methods such as artificial intelligence, a gas phase is always a non-wetting phase, so the injected gas flexible and perfect development plan and technical system occupies the middle part of the fracture, and the nature of should be established to achieve the cost-effective develop- the gas has a great influence on the production effect of the ment of carbonate reservoirs and promote the development crude oil. The expansion of nitrogen and the dissolution of of the world’s petroleum industry. carbon dioxide are widely used to reduce the viscosity of Acknowledgements This project was supported by the Innovation Pro- crude oil, and the injection of miscible hydrocarbon gas in ject for Graduates in UPC (Grant YCX2019016). We acknowledge the fractured cavity media has been shown to be effective. How - National Natural Science Foundation of China (Nos. 51774306 and ever, due to the serious interlayer heterogeneity in fractured 51974346), the Science and Technology Support Plan for Youth Inno- vuggy reservoirs, gas channeling is easily caused by gravity vation of University in Shandong Province under Grant 2019KJH002, the Major Scientific and Technological Projects of CNPC under Grant differentiation between fluids during gas injection, which ZD2019-183-008. We are grateful to the researchers at the Foam Fluid significantly reduces reservoir production. Enhanced Oil & Gas Production Engineering Research Center in Shan- There are two limiting factors that ae ff ct the development dong Province and UPC-COSL Joint Laboratory on Heavy Oil Recov- of carbonate reservoirs: one is the viscosity of crude oil, and ery for their kind help in this study. the other is the generation of channeling. In view of the high Open Access This article is licensed under a Creative Commons Attri- viscosity of crude oil, steam injection and thermal recov- bution 4.0 International License, which permits use, sharing, adapta- ery are often used to reduce the viscosity of crude oil. The tion, distribution and reproduction in any medium or format, as long injection of a surfactant is beneficial to reduce the oil–water as you give appropriate credit to the original author(s) and the source, provide a link to the Creative Commons licence, and indicate if changes interfacial tension and improve the washing efficiency. were made. The images or other third party material in this article are Polymer injection can increase the sweep coefficient and included in the article’s Creative Commons licence, unless indicated block the channel. The plugging capabilities are enhanced otherwise in a credit line to the material. If material is not included in by foam-type plugging agents and particle-based plugging the article’s Creative Commons licence and your intended use is not permitted by statutory regulation or exceeds the permitted use, you will agents. The use of foam to carry particle plugging agents need to obtain permission directly from the copyright holder. To view a can achieve deep plugging. However, the harsh formation copy of this licence, visit http://creativ ecommons .or g/licenses/b y/4.0/. conditions of carbonate reservoirs often have a great impact on the performance of chemical agents, and the development of temperature- and salt-resistant surfactants and polymers is an essential task. 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