Introduction
Long-term stable crude oil production in China is an essential prerequisite for safeguarding national energy security. In this respect, it is critical to enhance the recovery of existing oilfields and develop new domains, especially unconventional oil, in an effective and extensive manner. In China, the upgrading and modified water flooding technology remains as the primary contributor to oil production. The chemical flooding technology and thermal recovery technology for enhanced oil recovery (EOR) are at the forefront of the world, and each has maintained an annual production over ten million tons for more than a decade, significantly contributing to the sustained stable oil production of China. In recent years, with the further continuous development of conventional mature oilfields, stable oil production has become increasingly difficult, and the extensive and efficient de-velopment of new domains (particularly shale oil) faces technical and economic challenges. These situations trigger a growing demand for new theories, methods and technologies of EOR. In response to the new situations, problems and challenges in oilfield development, many new mechanisms, processes and techniques of EOR have emerged through innovative laboratory researches with the support of scientific and technological investment. Some of these mechanisms, processes and techniques have been tested in fields, yielding satisfactory preliminary results. Based on ongoing research and investigations, this paper delineates recent progress in fundamental research methods such as in-situ sampling and non-destructive testing of formation rock/fluid, micro/nano- scale flow mechanisms and physical simulation, reservoir modeling, and numerical simulation. This paper also discusses the progress in research and experiments on new EOR methods including water flooding, chemical flooding, gas flooding, thermal recovery, and continental shale oil development, with respect to oil displacement mechanisms, approaches, oil displacement agents, and key processes. Furthermore, the issues and deficiencies of EOR techniques are analyzed, and the research and application prospects of various methods are predicted, and the recommendations for future research are proposed.
1. Fundamental research methods
1.1. New methods in in-situ sampling and non-destructive testing (NDT) of formation rock/fluid
As a practice in the industry, the formation rock/fluid sample is taken with pressure-retained downhole to the surface where it is transferred to a sample bottle and then restored to in-situ temperature and pressure conditions for analysis. This process often results in multiple temperature and pressure changes, making it difficult to restore the true in-situ state of the rock or fluid, which significantly impacts the evaluation of shale oil reservoir parameters.
The CNPC research team [1-2] proposed an approach of in-situ sampling and non-destructive testing (NDT) of formation rock/fluid. Principally, the formation rock/fluid sample is taken underground using the sampler, which uses non-metallic material instead of metallic material, to the surface where the sample is directly tested through the sampler using high-power computed tomography (CT), nuclear magnetic resonance (NMR) and other micro/nano-scale analysis techniques. By examining differences in parameters (e.g. density) of the sample in in-situ state at different positions of the sampler, the sample is analyzed finely for rock matrix, pore (throat), fracture distribution, and the phase, occurrence and distribution of fluids like oil, gas, and water, without the need for transferring the sample into a bottle. This allows a more intuitive and accurate understanding of subsurface reservoirs. Currently, significant progress has been made in NDT techniques and methods using non-metallic sampler and metal windowed samplers, or and NDT techniques and methods through samplers.
1.2. Physical simulation systems and methods for micro/nano pore structures
In low-permeability to tight reservoirs and shale oil and gas reservoirs, the micro/nano-scale pores (throats) serve as the primary storage space. The fluid flow behaviors within the space are complex and differ greatly from that in conventional oil and gas reservoirs. A deeper understanding of fluid phase change characteristics and flow mechanisms within confined micro/nano-scale spaces is crucial for effectively developing these reservoirs [3].
Microfluidic physical simulation is a cutting-edge technology for studying fluid flow in micro/nano-scale space. As to its principle, a minute amount of fluid is accurately injected into the model of micro/nano pores with different sizes and shapes under high-temperature and high- pressure (HTHP) conditions, to study the phase state and flow behavior of the fluid within the model and their changes. Since the fluid characteristics within the model cannot be observed by eyes directly, high-speed camera will be used for high-frequency magnified photography. The captured images and videos are processed using high-performance computer and software, allowing detailed analysis to derive experimental results. Key aspects of microfluidic physical simulation include the control and measurement of fluid injection and production, fabrication of micro/nano-scale pore model, high-speed camera photography, image processing, and temperature and pressure retention in the micro/nano-scale space. Depending on factors such as reservoir temperature, pressure, wettability, and pore throat size, various etching materials and techniques, such as glass and polymer, are used to create microscopic models of pores down to tens of nanometers, thereby closely replicating reservoir conditions and physical properties to simulate and analyze fluid flow within pore throats.
The institutions like PetroChina Research Institute of Petroleum Exploration and Development, Sinopec Petroleum Exploration and Production Research Institute, and China University of Petroleum (Beijing) have established experimental systems for simulation studies, achieving considerable progress [3].
1.3. Reservoir simulation and fracturing optimization simulation software
For the development of highly water-saturated, low- permeability, and unconventional oil and gas resources, laboratory physical simulation is significantly limited. Reservoir simulation and fracturing optimization simulation have become powerful tools for optimizing the reservoir development process.
In terms of reservoir numerical simulation, the recently introduced multifunctional integrated reservoir numerical simulation software, HiSim® [4], incorporates ten major functions including geological modeling, and black oil/component/unconventional oil and gas simulation. It features ten core technologies such as multimodal complex flow mathematical characterization, multi-scale fracture modeling and simulation, and large-scale efficient solving. HiSim® has distinct advantages in simulating the improvement of water flooding in mature oilfields, injection of gas (e.g. CO2, N2 and hydrocarbon gas) for EOR, carbonate reservoir development, gas reservoir development, and tight/shale oil and gas development. Over 1 600 units have been installed in 17 oil and gas field companies and engineering technology companies of China National Petroleum Corporation (CNPC), as well as several universities, and successfully applied in over 100 oil and gas blocks [2].
In terms of fracturing optimization simulation, CNPC released the integrated geological-engineering fracturing optimization design software, FrSmart 1.0 [5], which incorporates 10+ key technologies. It features over forty functions across eight modules including fracturing simulation and productivity simulation, covering all stages from pre-fracturing fracability analysis, casing deformation risk assessment, fracturing design, post-fracturing evaluation, to productivity prediction. It supports integrated fracturing optimization design for various well types, such as vertical wells and horizontal wells, adapting to the optimization needs of conventional and shale oil and gas reservoir stimulation technologies. Over 1 000 units have been installed in CNPC, Sinopec, China National Offshore Oil Corporation (CNOOC), Shaanxi Yanchang Petroleum (Group) Co. Ltd., and more than ten universities, with over 3 200 stages/layers of demonstration applications, achieving promising preliminary application results.
2. New EOR methods for mature oilfields
2.1. Modified water flooding
Most oilfields in China adopt early water injection to maintain reservoir pressure. In recent years, remarkable advancements have been made in modified water flooding, particularly in modified water injection for low-permeability reservoirs and well life extension in ultra-high water cut oilfields.
2.1.1. "Nano-water" flooding
Nanotechnology has developed rapidly in recent years, motivating researchers to explore its application in the petroleum industry, particularly in the extraction of oil and gas in low-permeability to tight reservoirs. Miranda et al. [6] studied reservoir surface wettability and fluid diffusivity at the molecular level with molecular dynamics methods, investigating nanoparticle systems that could reduce interfacial tension between oil and nanoparticles for EOR. Ayatollahi et al. [7] presented nanotechnology-assisted EOR techniques. Nonetheless, these techniques are primarily at the laboratory research stage, and mostly focus on the properties of nanomaterials.
In ultra-low permeability to tight reservoirs, conventional water injection often fails to establish effective displacement, making it difficult for oil to flow from tiny pores to the wellbore. The bottleneck in improving recovery is "difficult injection and unworkable extraction". The CNPC research teams [8-9] indicated that the "difficult injection" of water arises from strong hydrogen bonding in water molecules forming a "super weak gel" dynamic network, while the "unworkable extraction" of oil results from interactions between oil molecules forming a similar network. The solution involves creating a multifunctional integrated nano-scale material carrier to damage or weaken these interactions, producing small-molecule water (or "nano-water") and small-molecule oil (or "nano-oil") to facilitate injection and extraction. Using SiO2 nanoparticles, the first-generation nanofluid flooding agent iNanoW was developed to damage or weaken water molecule hydrogen bonding. Field tests in the ultra-low permeability reservoirs of Changqing Jiyuan Oilfield, tight oil reservoirs of Xinjiang Mahu Oilfield, NW China, and complex fault-block low-permeability reservoirs of Dagang Oilfield have demonstrated that iNanoW significantly reduces injection pressure difference and improves injectivity compared to ordinary water. In November 2018, a test was initiated in the ultra-low-permeability reservoirs of Changqing Jiyuan Oilfield by injecting pure "nano-water" via a flooding unit consisting of 10 injectors and 36 producers. As of May 2022, consistent positive results had been witnessed, and all three central wells were responded satisfactorily, with a staged net oil increment of 2 428 t and a cumulative oil increment of 8 624 t by controlling the production decline (Fig. 1 ) [9]. The successful field test of iNanoW highlights the potential of "nano-water" flooding in the development of ultra- low permeability to tight oil reservoirs.
Fig. 1. Production performance of "nano-water" flooding test in ultra-low permeability reservoirs of Jiyuan Oilfield [9]. |
On the basis of "nano-water" flooding, the basic research on "nano-water+" is gaining more and more attention. When iNanoW is added into the polyacrylamide solution, the particle size of the polyacrylamide with a molecular weight (MW) of (150-400)×104 reduces from 290-2 900 nm to below 41 nm, which is equivalent to the particle size of the nano oil displacement agent, enabling its injection into ultra-low permeability reservoirs for polymer flooding [9]. Additionally, in a polymer solution (polymer MW of 150×104) with a concentration of 1 000 mg/L, the addition of 1 000 mg/L iNanoW yields a great reduction in the solution's particle size but not in viscosity (Fig. 2 ) [9]. Field tests in deep low-permeability reservoirs of Jidong Oilfield demonstrated promising results for "nano-water+" polymer flooding systems [9]. These oil displacement systems, including "nano-water+" polymer and "nano-water+" natural gas, expand the application of "nano-water" flooding technology.
Fig. 2. Variation of "nano-water+" polymer system viscosity with "nano-water" mass concentration [9]. |
2.1.2. Ion-matched water flooding
In 1996, bp and the University of Wyoming initiated a research on low-salinity-water flooding, and achieved ideal results in field tests [10-11]. However, low-salinity- water flooding primarily focuses on reducing the overall salinity of the injected water, without specifically adjusting certain ion concentrations.
Considering the complex oil/water/rock interfaces and fine pore throats in low-permeability reservoirs, the CNPC research team developed an ion-matched water system and associated oil displacement technologies [12]. The mechanism involves ion matching and exchange between injected water and formation water to adjust the charge density at the oil/water/rock interfaces, reduce the interactions between oil/water/rock molecules, and alter wettability, so as to strip residual oil films, lower residual oil saturation, and enhance waterflood recovery. Through in-situ oil/water/rock system simulations, and with the help of experimental methods such as X-ray photoelectron spectroscopy (XPS), quartz crystal microbalance with dissipation monitoring (QCM-D), and atomic force microscopy, the team directly measured the impacts of ion composition and salinity changes in injected water on the properties and forces of crude oil/mineral interfaces. Laboratory studies indicated that, given the same concentration, NaCl solution, Na2SO4 solution and CaCl2 solution rank in an ascending order of solution-oil interfacial tension, and the Na+ solution exhibits a lower interfacial tension. For the same solution, the lower the ion concentration, the smaller the interfacial tension between the solution and crude oil. If Ca2+ ions on rock mineral surfaces are replaced by Na+ ions, the interfacial tension between oil film and water film attached to the rock surface decreases, allowing the films to be separated easily. Most sandstones are hydrophilic rocks. Eventually, the oil film on the rock surface is more easily peeled off and extracted. Especially for rocks with high kaolinite and chlorite content, the ion exchange effect is better, and the oil film is easier to peel off after ion exchange.
Since June 2016, the ion-matched water flooding technology has been satisfactorily tested in several blocks of Jilin, Changqing and other oilfields. For example, in the Xinmuqian 60 block of Jilin Oilfield, China, a pilot test of ion-matched water flooding was performed in a unit consisting of 5 injectors and 15 producers. The initial responses were noticeable, and the later productivity kept sustained and stable, potentially increasing the water flooding recovery by 5 percentage points [12].
2.1.3. Polymer microsphere flooding
Long-term water injection in oil layers often creates dominate water flow channels, significantly reducing the sweep efficiency of the injected water. Changqing Oilfield developed a series of key nanoparticle polymer microsphere products [13], which increase the resistance in these dominate water channels through creep migration, adsorption aggregation, expansion bridging, and surface effect coupling, redirecting injected water to expand the sweep area. Through field practices, a process mode with the features of small particle size, low concentration, long cycle, and centralized injection was established. This mode, supported by digital injection equipment and a whole-process intelligent monitoring platform, enabled a large-scale application in the loess plateau terrain. With sustained efforts, a deep profile control technology integrating product R&D, mechanism understanding, process innovation, and digital support was developed to further facilitate the water flooding in low-permeability oil reservoirs. Polymer microsphere flooding has been implemented in 21 963 wells (3 137 wells annually), covering a production up to 1 100×104 t, with a decline rate reduced by over 2 percentage points in the application areas [13]. This technology has also been promoted in the Tuha and Yumen oilfields.
The sizes of dominant channels, fractures, and pores for water flow in formations span greatly, and ordinary polymer microspheres face challenges in matching pore throat sizes and in achieving strong plugging capabilities. Therefore, some researchers developed self-aggregating polymer microspheres [14]. Laboratory studies suggested that self-aggregating microspheres can effectively plug large pores or dominant flow channels, initiating micro-scale profile control in un-swept low-permeability regions and significantly enhancing recovery.
2.1.4. Single-well injection and production technology
As mid-to-high permeability oilfields enter late development stage with high water-cut, some problems emerge, such as decline in oil production, difficulty in water treatment, and poverty in development efficiency. In the 1990s, international oil companies proposed the concept of downhole oil-water separation and conducted relevant research [15]. Field tests were performed in several oilfields, but mostly suffered the issues such as poor downhole oil-water separation performance and efficiency, possible blockage in reinjection layers, and high injection pressures leading to short service life of downhole tool. Similar research was conducted in China, and tests were successfully performed in oilfields such as Daqing, Dagang, Jilin and Jidong [16⇓-18].
As to the principle of this technology, the produced fluid is treated using a special equipment for downhole oil-water separation, with the separated water directly reinjected into the water injection zone, and the oil-rich water mixture lifted to the surface, so that water injection and oil production are completed simultaneously in the active wellbore [16]. Key aspects of this technology are the design of the injection-production string structure and the reinjection of separated water. Through years of efforts, the R&D team of CNPC Daqing Oilfield Company Limited (hereinafter referred to as Daqing Oilfield) developed the process of injection-production in the same well with gravity downhole oil-water separation and supporting techniques/tools [17].
In 2015, Daqing Oilfield conducted field tests of single-well injection and production in two blocks (one with water flooding and one with polymer flooding). The 31 wells involved showed an average decrease in liquid production of 94.5%, a roughly unchanged oil production, a reduction of water cut by 34.1%, a reduction in underground reinjected water consumption by 83.0%, and an average string service life exceeding 1.5 years or even up to 4.9 years [16-17], demonstrating remarkable application results.
2.2. Chemical flooding
Polymer flooding and alkali-surfactant-polymer (ASP) flooding have been successfully applied in Daqing Oilfield and other oilfields for many years. In response to new challenges and different application targets, the alkali-free binary flooding technology was developed, and it has achieved ideal results in pilot tests in Liaohe Oilfield, Xinjiang Oilfield, Dagang Oilfield, Shengli Oilfield, and others. Currently, some new chemical flooding methods are being studied, such as super binary flooding and low- concentration anionic-nonionic surfactant middle-phase microemulsion flooding. The application of chemical flooding is expanding by virtue of technical iteration and upgrading [19-20].
2.2.1. Super binary flooding
With the expansion of exploration targets to highly heterogeneous conglomerate reservoirs and low-to-medium permeability sandstone reservoirs, traditional chemical flooding systems, evaluation methods, and oil displacement mechanisms have proven inadequate. In response, the CNPC research team developed multi-dimensional methods for evaluating emulsification performance, characterizing three-phase interfacial adsorption, and examining oil-water-solid interactions. The team introduced novel metrics such as the emulsion migration retention index and structural separation pressure, thereby transitioning the original macroscopic, static and qualitative evaluation system to a microscopic, dynamic and quantitative one [21]. The team also presented new insights on oil displacement mechanisms, such as strong emulsification blockage in conglomerates and weak emulsification migration in low-to-medium permeability formations, expansion of microscopic sweep area through liquid film viscosity/elasticity synergistic action, and control of oil film stripping by ethylene oxide/propylene oxide groups. These insights clarified that the matching relationship between emulsification intensity and pore throats and the oil film stripping ability are critical factors determining the performance of chemical flooding in complex reservoirs. In laboratory experiments of oil displacement in highly heterogeneous conglomerates and low-to-medium permeability sandstones, the new generation of low-cost chemical flooding systems, which feature ultra-low interfacial tension, controllable emulsification intensity, and high-efficiency oil film stripping performance, demonstrated an over 25-percentage-point increase in oil displacement efficiency compared to water flooding. By optimizing the chemical flooding system, the Qizhong block of Xinjiang Oilfield achieved a matching of the emulsification intensity of the flooding system with the reservoir pore throats to maximize the sweep volume, with the recovery efficiency enhanced by 19.4 percentage points in pilot tests (Fig. 3 ) [21].
Fig. 3. Field test of binary flooding in conglomerate reservoirs in Qizhong block, Xinjiang Oilfield [21]. |
The Shengli Oilfield Company developed ultra-high MW, high-viscoelasticity polymers, and multifunctional surfactants that reduce adhesive work, crude oil viscosity, and interfacial tension. These innovations enabled a new generation of binary flooding systems tailored for heavy oil reservoirs [22].
2.2.2. Low-concentration anionic-nonionic surfactant middle-phase microemulsion flooding
The oil/water/surfactant system predominantly forms three types of microemulsions: Winsor I (oil-in-water), Winsor II (water-in-oil), and Winsor III (oil and water in equal proportions). Winsor III is the ideal middle-phase microemulsion, characterized by an ability to simultaneously solubilize both oil and water and a negligible capillary pressure during the oil displacement process. This type of microemulsion exhibits a strong solubilizing capacity for residual oil along the pathway, achieving an oil displacement efficiency of over 90% [23].
In the 1970s and 1980s, researchers primarily used petroleum sulfonate as the main agent to prepare microemulsions, requiring surfactant mass fractions of over 5% to form middle-phase microemulsions [23]. After 2000, the use of nonionic surfactants for preparing microemulsions still necessitated surfactant mass fractions of 1% to 5% [23]. With advancements in surfactant development, system blending, and oil displacement theory, it is now possible to form middle-phase microemulsions using anionic-nonionic surfactants with mass fractions of less than 0.3%, significantly reducing system costs [23]. In laboratory settings, methods such as salinity regulation and formula optimization have enabled the formation of middle-phase microemulsions at low surfactant concentrations. For instance, the physical simulation experiments conducted by the CNPC research team (Fig. 4 ) demonstrated that, on the basis of a polymer flooding ultimate recovery efficiency of 59.1%, the use of a middle-phase microemulsion with a surfactant mass fraction of 0.3% could further enhance the recovery efficiency by 34.8 percentage points to 93.9% [23]. Currently, pilot tests are being conducted in several oilfields, including Daqing, Changqing, Jilin and Xinjiang.
Fig. 4. Physical simulation experiments on middle-phase microemulsion flooding [23]. |
2.2.3. Bio-chemical surfactant flooding
The bio-chemical surfactant flooding technology enhances oil displacement efficiency and quality by combining biosurfactants with chemically synthesized surfactants. This synergistic blend of chemical and biological surfactants increases molecular density and enhances interfacial activity. The effective combination of the two types of surfactants reduces interfacial tension, alters rock wettability, and improves oil displacement efficiency. The inclusion of biosurfactants can reduce the required volume of chemical surfactants, thereby lowering operational costs. The CNPC research team [24] developed a notable oil displacement system that combines lipopeptide biosurfactants with petroleum sulfonate chemical surfactants, significantly reducing surfactant costs. A pilot field test of a ternary blend (rhamnolipid-alkylbenzene sulfonate-alkali) was conducted in the Daqing Saertu Oilfield, NE China. This test projected a potential increase in recovery by 25.8 percentage points and a reduction in total chemical costs by 8.56%, demonstrating promising results [24].
2.2.4. High-temperature, high-salinity surfactant emulsification profile control
Under high-temperature and high-salinity conditions, conventional chemical agents often fail. To address this problem, the CNPC research team developed a multifunctional betaine-based emulsification profile control surfactant system tailored for high-temperature, high-salinity, and low-permeability reservoirs. This system employs multiple mechanisms, including interfacial tension reduction through interfacial regulation, in-situ emulsification droplet blockage to enhance microscopic sweep efficiency, and wettability alteration to strip oil films, thereby improving oil displacement efficiency and expanding the sweep volume [21]. In the pilot test area in the southwestern part of Luo 1 block of Changqing Oilfield (with a permeability of 0.86×10-3 μm²), the daily oil production increased from 17.1 t to 27.2 t, and the overall water cut decreased from 83.6% to 65.5%, indicating promising initial results. Expansion tests are currently underway in multiple blocks [21].
The Sinopec research team introduced a viscosity-enhancing emulsion surfactant flooding technology, developed a system characterized by a resistance to high temperature, emulsification and viscosity enhancement, and strong oil-washing performance, and established a combined oil displacement method utilizing viscosity-enhancing emulsion surfactants and low-tension surfactants [25]. Laboratory physical simulation experiments indicate that multiple rounds of alternating injections of emulsion surfactants and low-tension surfactants can increase the oil recovery by more than 15 percentage points [25]. This technology is particularly applicable to ultra- high temperature, low-permeability reservoirs where conventional chemical flooding techniques are insufficient [25].
2.2.5. Nano intelligent oil displacement
The research and development approach for nano intelligent oil displacement centers on creating advanced nanomaterials with exceptional performance characteristics. These nano-sized displacement agents are designed to be sufficiently small, enabling near-complete reservoir sweep. They exhibit strong hydrophobicity and oleophilicity, possessing intrinsic driving forces that allow them to actively seek out and attach to oil droplets, thus achieving intelligent oil detection. Moreover, these agents possess capabilities of robust emulsification and oil-dispersed aggregation capabilities, continuously identifying and coalescing new oil droplets or emulsifying residual oil. This process captures and disperses remained oil, to forming oil walls or oil-rich zones that can be effectively displaced [26]. Extensive exploratory research has been conducted along these lines.
2.3. Gas flooding
Field tests involving CO2 flooding, natural gas flooding, and air flooding in Jilin Oilfield, Tarim Oilfield, and Changqing Oilfield achieved successful outcomes. The core and supporting technologies of gas flooding are undergoing continuous upgrades, and the progresses in new mechanisms and methods for gas flooding are gaining ground.
2.3.1. Micro/nano bubble flooding
Low-permeability reservoirs, characterized by small pore and throat sizes, require high water injection pressures, making injection challenging. The severe heterogeneity of these reservoirs often leads to the formation of dominate water flow channels and gas channeling phenomena, resulting in low sweep efficiency for conventional water or gas flooding. Additionally, the injectivity of chemical flooding is significantly restricted under these conditions.
Micro/nano bubbles form a uniform and stable system with water as the continuous phase and gas as the dispersed phase. The bubbles can be controlled at the micro/nano-scale, maintaining a gas-to-water ratio not exceeding 1:2. These bubbles can penetrate variously shaped and sized tiny pores in a dispersed manner, undergoing continuous deformation and effectively utilizing gas elastic energy for micro-scale oil displacement. This process enhances the transport of residual oil and alters the flow direction, ultimately enhancing the recovery [27-28].
The CNPC research team developed a micro/nano bubble oil displacement technology, encompassing oil displacement theories, experimental methodologies, apparatus design, and application processes [27]. The Research Institute of Innovative Technology for the Earth (RITE) in Japan conducted laboratory evaluations on this technology, though no field tests were performed [27]. Systematic studies on the generation and characteristics of micro bubbles were carried out by the Chinese Academy of Sciences and various universities, yet no field evaluations of oil displacement effectiveness were conducted [27]. In 2020, PetroChina Changqing Oilfield Company conducted a field test at the Wuliwan site, implementing micro/nano bubble flooding in a unit with 4 injectors and 19 producers. As a result, the daily oil production of the central wells increased from 0.2 t to over 1.5 t, while the water cut decreased from 92.3% to 73.2%. Additionally, the natural decline rate of the test well group dropped from 10.5% to 6.0%, and the water cut rise rate fell from 1.8% to -0.5%. The cumulative oil increasement in the test area exceeded 10 000 t. Currently, an expanded test involving 16 injectors and 68 producers is underway, demonstrating promising application prospects [27].
2.3.2. CO2 miscible flooding
CO2 enhanced oil recovery (EOR) has been extensively applied in the United States, with an annual oil production reaching the scale of 1 500×104 t [29]. However, the continental sedimentary reservoirs in China differ significantly from the marine sedimentary reservoirs in the United States. While the CO2 flooding mechanisms, technologies, and practices from the United States can serve as a reference, they cannot be directly copied. By using the established "multi-dimensional, multi-scale, dynamic- static combined, quantitative characterization" CO2 injection physical simulation method and platform, the CNPC research team proposed some new insights into the mechanisms of CO2 miscible flooding in continental sedimentary reservoirs [29⇓⇓⇓-33]. These insights involve four aspects. First, the mass transfer and miscibility between CO2 and C₇-C₁₅ fractions, which are abundant in continental oil, are also strong. This finding challenges the prevailing foreign notion that only C₂-C₆ fractions have strong mass transfer and miscibility with CO2, significantly enhancing the potential for CO2 miscible flooding in continental sedimentary reservoirs. Second, after CO2 dissolves into crude oil, the cyclic and branched hydrocarbons contribute more to oil swelling, even though these components are present in smaller quantities. These hydrocarbons are crucial for oil swelling. Third, large hydrocarbon pore volume (HCPV) injection of CO2 could multiply contact with oil and extract hydrocarbons to achieve miscibility. This highlights that a large HCPV cyclic gas injection strategy can significantly increase recovery rates. Fourth, the microscopic pore-throat displacement mechanism of gas flooding was elucidated, clarifying the displacement rules and limits of the matrix-fracture system during CO2 flooding. Continuous gas injection into matrix core samples can effectively displace micro pores smaller than 0.1 μm, while sustained gas injection into microfractured core samples can effectively utilize small pores ranging from 0.1 μm to 1.0 μm.
2.3.3. Multi-media assisted CO2 sweep volume expansion
Expanding the sweep volume by controlling gas breakthrough is one of the prominent challenges in the large- scale application of CO2-EOR in continental heterogeneous reservoirs. The CNPC research team addressed this issue by establishing a multi-dimensional method for evaluating CO2 profile control system. They leveraged the new mechanisms of enhanced water-alternating-gas (WAG) multiphase coupling, pore-throat matching, and stepwise expansion of the CO2 sweep volume, and developed three types of enhanced WAG chemical agent systems: acid-thickening agent, acid-resistant foam, and in-situ emulsification agent. Laboratory experiments demonstrated that these systems can increase oil displacement efficiency by an additional 12.76 percentage points beyond the baseline of CO2 flooding [34]. Currently, this technology is being tested in the Hei 125 block of Jilin Oilfield, where a foam enhanced WAG pilot test is underway. The designed test cycle spans six months, with a gas-to-liquid ratio of 1:1 and an alternating cycle of 15 d. Preliminary favorable results were achieved currently. Foam enhanced WAG exhibits notable capabilities in reducing the gas-to-oil ratio and suppressing gas channeling, thereby holding substantial potential for significantly improving the CO2 flooding effect.
2.3.4. Top natural gas injection for stable gravity drainage
Top natural gas injection for stable gravity drainage follows the primary oil displacement mechanisms as component mass transfer to enhance miscibility and gravity segregation to increase sweep volume. Compared to conventional water and gas flooding, this method can significantly improve oil recovery. A quintessential case of successful top gas injection is the thick and blocky Hawkins Dexter sandstone reservoir with bottom-water in the United States [35]. After achieving nearly 60% recovery through water flooding, the integration of nitrogen gravity drive and bottom water buoyancy drive sustained a high and stable production for over a decade, boosting the recovery by more than 20 percentage points. Benefiting from the high dip angle of the reservoirs and the abundant natural gas sources in the vicinity, the Tarim Oilfield developed a comprehensive technology of top natural gas injection for gravity drainage, which was successfully applied in such reservoirs as Donghetang Formation [36]. The CNPC research team [36] integrated top natural gas injection with gas storage construction, achieving a dual functionality of increasing oil recovery while realizing peak shaving and gas supply assurance with the storage facility. A synergistic test of gas storage and top natural gas injection for gravity drainage (Fig. 5 ) was conducted in a pilot area, achieving a threefold increase in oil production and nearly a 30-percentage-point improvement in recovery of central wells, with a cumulative gas injection of 760 million cubic meters, a cumulative oil production of 1.14 million tons, a cumulative gas storage of 510 million cubic meters, and a natural gas peak shaving and supply assurance capacity exceeding 1.0×106 m³/d, demonstrating significant effects [36].
Fig. 5. Production curves of top natural gas injection in DH reservoir, Tarim Basin [36]. |
2.4. Thermal recovery
The primary thermal recovery techniques for heavy oil in China include cyclic steam stimulation (CSS), steam flooding, steam-assisted gravity drainage (SAGD), and in-situ combustion. These techniques contributed an annual heavy oil production of over 10 million tons for many years [19]. On this basis, new thermal recovery methods have been developed in recent years, and the thermal recovery techniques been extended to conventional black oil and light oil reservoirs.
2.4.1. Multi-media assisted steam flooding/cyclic steam stimulation
The multi-media assisted steam flooding/cyclic steam stimulation technique involves an introduction of gaseous media such as N₂, CO2, flue gas or air into steam, the primary medium of steam flooding/CSS. This is further complemented by the addition of high-temperature resistant surfactant and foam as liquid media. The incorporation of the gaseous media serves to enhance energy and pressure, reduce thermal loss, and improve thermal efficiency. The high-temperature resistant surfactants and foam liquids help to increase oil displacement efficiency and control profile within the reservoir.
Laboratory researches conducted in CNPC demonstrated that multi-media assisted steam flooding can reduce steam consumption by approximately 20% and increase the sweep volume by over 18% [37]. This technique is most widely applied in mature CSS blocks. Since 2017, it has been implemented in 3 769 wells in the Liaohe and Xinjiang oilfields in China, achieving a cumulative oil increment of 81.9×104 t [37]. Currently, efforts are underway to develop and improve the carbon capture enhanced thermal recovery (CCETR) technology, which mixes the ammonia-captured flue gas from steam boiler with steam for injection into the reservoir, thereby enhancing the thermal recovery efficiency while reducing the carbon emissions [37].
2.4.2. Multi-component thermal fluid recovery for complex heavy oil
The multi-component thermal fluid recovery technique developed by the Sinopec research team is a composite development technology incorporating chemical agents (e.g. high-temperature viscosity reducer and oil displacement agent) and gas (e.g. CO2 and N₂) on the basis of thermal recovery. It aims to achieve high efficiency, wide coverage, and long-term viscosity reduction. The primary mechanisms include steam-agent coupled viscosity reduction, nitrogen insulation and energy enhancement, and thermal agent alternating for assisted displacement [38]. This technique is suitable for recovering ultra-heavy oil from reservoirs as deep as 2 000 m and as thin as 2 m [38].
CO2 enhanced thermal recovery technique leverages the mechanisms of supercritical CO2 dissolution to reduce viscosity and lower the initiation pressure. When combined with steam, CO2 drives viscosity reducer deep into the reservoir, disrupting the network structure of the ultra-heavy oil's resins and asphaltenes. This process broadens the response range of the viscosity reducer, and has witnessed preliminary results in the development of typical deep ultra-heavy oil reservoirs in Shengli Oilfield in China [38]. Nitrogen thermal recovery technology involves sequentially injecting viscosity reducers, nitrogen, and steam into horizontal wells with heavy oil from thin layers. After a soak period, the well is then produced. This method has successfully lowered the development thickness limit for ultra-heavy oil reservoirs to 2 m in Xinchun Oilfield [38].
2.4.3. Air injection thermal assisted miscible flooding
As early as the 1980s, the Buffalo Oilfield in the United States experimented successfully with air injection to enhance oil recovery [39]. The primary objective of this project was to supplement reservoir pressure after depletion development. Air was injected into the reservoir without ignition, with a mechanism similar to that of nitrogen flooding.
Air injection thermal assisted miscible flooding is a novel technology recently developed by CNPC through dedicated research efforts [40⇓-42]. The theoretical foundation of this technology is based on the following experimental findings: at temperatures above 200 °C (varying with the gas/oil properties), the miscibility pressure of air medium and crude oil decreases with increasing temperature, and at temperatures between 300 °C and 450 °C, various gaseous media can achieve miscibility with crude oil under reservoir pressure conditions [39]. According to experiments on the miscibility pressure of flue gas and crude oil from Jilin Moliqing reservoir, the miscibility pressure is 35 MPa at 300 °C, and drops to just 15 MPa at 400 °C [39]. The Moliqing reservoir, with a burial depth of 2 850 m, can achieve efficient miscible flooding with flue gas at 25 MPa and 350 °C [39]. Based on these principles, the key to achieving miscible flooding is to raise the reservoir temperature to 300 °C or higher. Based on the concept of heavy oil in-situ combustion, injecting air into the reservoir and achieving controlled underground ignition and heating can enable air injection thermal assisted miscible flooding in light oil reservoirs.
The air injection thermal assisted miscible flooding technology has improved in various aspects, including indoor mechanism research, auxiliary agents, tool development, and field test. (1) The miscible model of intermediate-temperature oxidation for air injection into thin oil is proposed and validated. (2) The technique of low- temperature oxygen consumption initiation for air injection thermal assisted miscible flooding is developed, and a combination formulation system consisting of oil soluble catalyst and oxygen consumption agent is created, enabling the rapid oxygen consumption and heat generation within 50 min to safely reach over 300 °C in low-temperature reservoirs. This technique was successfully implemented in five wells in the Moliqing Oilfield in Jilin and the Jiyuan Oilfield in Changqing, achieving 100%. (3) Key supporting processes to prevent gas channeling, represented by special packers and flow-reversing gas anchors, are developed. (4) Pilot tests of air injection thermal assisted miscible flooding was conducted in such as Jilin and Changqing oilfields, showing initial favorable results. After two years of testing in the Moliqing ultra-low permeability reservoir in Jilin Oilfield, the injection-production relationship remained stable, with the average single well production increased from 2-3 t/d to 5-10 t/d [39].
2.4.4. In-situ conversion of heavy oil
The technology of in-situ conversion of heavy oil involves injecting a catalytic system into the reservoir, triggering the chain-breaking reaction of heavy oil at a certain temperature to achieve viscosity reduction and efficient low-carbon development. This technology has been continuously studied abroad for many years, with the approach of using "hydrogen gas + solid catalyst + underground electric heating" to reduce the conversion temperature from 400-450 °C to 350 °C [43-44]. In 2010, the CNPC team proposed a low-temperature, long-lasting conversion reaction pathway, constructed a targeted reaction mechanism, and developed a liquid catalyst. They established a new in-situ conversion process assisted by steam, reducing the conversion temperature to below 300 °C. This innovation eliminates the reliance on electric heating and hydrogen gas, extending the conversion range from the vicinity of the wellbore to the deeper parts of the reservoir [44].
This technology has been piloted in the Fengcheng heavy oil field in Xinjiang, demonstrating significant effects on irreversible viscosity reduction, production increment, and carbon emission reduction. The viscosity of the produced oil decreased from 50 000 mPa·s to as low as 21 mPa·s. The test well group is predicted to have an increase in recovery by at least 20 percentage points over the CSS baseline recovery of 24%. Additionally, the steam consumption and carbon emissions per ton of oil produced were reduced by 60%, with an input-output ratio of 1:10 [44].
2.4.5. Offshore heavy oil thermal recovery
Approximately 6.3×108 t offshore heavy oil in China requires thermal recovery at present, which is very different from onshore thermal recovery due to the constraints of offshore platform locations, space, and costs. Offshore thermal recovery with large well spacing faces a series of challenges, such as limited thermal field expansion, significant heat loss in deep and large wellbores, and high safety requirements for platform wellbores [45]. Over the past ten years, the CNOOC research team developed a theoretical and technical system for high-intensity thermal recovery of offshore heavy oil with large well spacing. It established a thermal injection model characterized by large well spacing, high injection rate, high injection intensity, and high injection dryness, and developed a method for evaluating CSS productivity over well spacings greater than 200 m. Additionally, CNOOC created a long-lasting sand control technology for high- intensity injection and production, and an integrated large-volume injection-production technology with electric submersible pump operating at 350 °C. CNOOC also developed a compact platform equipment for offshore thermal recovery, significantly reducing the footprint and lowering the cost of large-scale thermal recovery [45]. In 2008, the first successful offshore implementation of multi- component thermal fluid and CSS was achieved, with a cumulative production of 23 000 t for a single well in the first cycle, validating the feasibility of efficient offshore heavy oil thermal recovery technology. Currently, large- scale thermal recovery of heavy oil has been implemented in eight blocks in the Bohai Sea, with an annual production exceeding 50×104 t and continuing to grow [45].
3. Continental shale oil development and EOR methods
The primary extraction technologies and development modes for marine tight oil and shale oil in North America are upgrading continuously, enabling the shale oil production in the United States to reach 3.78×108 t in 2022 [46]. Considering the characteristics of continental sedimentary reservoirs in China, it is not feasible to duplicate the technologies from North America. Therefore, based on the foreign technologies, a technical system suitable for the continental tight oil and shale oil in China has developed primarily. It achieves an annual production at the scale of 1 000×104 t. The continental shale oil resources and development potential in China are substantial [46], and significant progress and remarkable results have been achieved in development theoretical research and field tests. The Changqing Oilfield has established a production demonstration base with an annual capacity of 200×104 t shale oil. Additionally, three national-level shale oil development demonstration zones have been set up in Xinjiang, Daqing, and Shengli oilfields. Key technologies that support effective shale oil development, such as horizontal drilling, fracturing stimulation, and factory-like operations, are continuously iterating and upgrading. Notably, significant progress has been made in core technologies, including novel fracturing methods, well placement techniques, and EOR methods.
3.1. Phase characteristics and flow mechanisms in nanoporous pores
In unconventional reservoirs represented by shale, the pore throat radii are extremely small, and the free movement of fluid molecules is influenced and restricted by the pore walls. Due to the challenges of directly simulating and validating these phenomena through laboratory experiments, many scholars performed research using molecular dynamics simulations. According to recent studies, when the ratio of pore size to fluid molecule size is less than 50, the confinement effect becomes significant [1]. Specifically, this is reflected in the shift of critical characteristic points of fluids in confined nanoporous spaces [1-2]. As the pore size decreases, the saturation pressure of the mixed fluid lowers, the phase diagram envelope shifts inward, and this shift becomes more and more pronounced. The occurrence of two phases in small pores is delayed in terms of time and pressure points. Taking Well GYYP-1, which is developed by depletion, in the Gulong shale oil field as an example, when the gas-oil ratio is 500 m³/m³, there is a notable phenomenon of spatial phase state differences in the formation (Fig. 6 ) [47]. In nanopores, the fluid is in a condensate gas state with a strong potential to be recovered. In larger pores, the fluid tends to be in a volatile two-phase state. This spatial phase state results in an "oil in large pores, gas in small pores" phenomenon, which facilitates the flow of fluid in small pores. From the characteristic changes in the phase diagram envelope with pore size, maintaining the formation pressure at a certain level can effectively promote the full mobilization of fluid in nanopores.
Fig. 6. Fluid phase characteristics at different pore scales in Well GYYP-1 [47]. |
During the development of continental shale oil, the fluid flow space encompasses various scales of media, including organic pores, inorganic pores, natural fractures, and induced fractures. The mechanisms for initiating crude oil flow and its flow behaviors are relatively complex. In the case of Gulong shale oil, hydraulic fracturing creates a multiphase, multiscale flow model centered on induced fractures, bedding fractures, and matrix imbibition. In this model, fluid within the bedding fractures is mobilized first towards the induced fractures. As the pressure in the bedding fractures decreases, the pore media begin to replenish the fractures. This pressure change, along with the variations in pore space, causes a significant amount of dissolved gas to be released from the fluid. This process effectively supplements the local energy and provides the driving force for fluid flow within the bedding fractures and nanopores. The hierarchical flow pattern from matrix pores to bedding fractures to induced fractures significantly reduces the fluid flow distance within a single medium, thereby effectively lowering the flow resistance.
The aforementioned phase characteristics and flow mechanisms were indirectly validated by production history matching. However, further direct validation is required through in-situ sampling, nondestructive testing, and physical simulation experiments. This will help to refine the understanding of these mechanisms and improve the associated mathematical models.
3.2. CO2 pre-pad fracturing technology for shale oil
Shale oil reservoirs are characterized by fine pore throats and high displacement pressures, and CO2 is more effective than water in penetrating microfractures and nanopores. CO2 can enhance the elastic energy of the formation, expand the scope of fracturing range, improve fracturing performance, and increase the mobility of crude oil. CO2 pre-pad fracturing technology has been successfully applied in North America and has also been partly applied to the development of shale oil in China. In the Jimsar shale oil region, CO2 pre-pad fracturing showed significant production enhancement in both low-viscosity and high-viscosity areas. In 2022, a CO2 pre-pad fracturing energy storage test was conducted at Well JHW71-11 in a high-viscosity area, achieving a 27% increase in cumulative oil production over one year for 1 000 m of horizontal section, and extending the natural flow period by more than 300 d. The test results show the potential of the technology for broader application [2]. In the Changqing shale oil region, test wells using CO2 pre-pad fracturing maintained higher pressure levels compared to conventional fracturing wells, with initial daily oil production reaching 20.6 t, demonstrating a significant production enhancement effect [2]. In the Jiyang shale oil region, the formation of complex fracture networks is challenging, with limited stimulation scope and difficulty in vertical penetration across layers. The application of CO2 pre-pad fracturing technology, which includes pre-pad fracturing with CO2, acid etching to reduce initial pressure, high-volume imbibition replacement, and multi-stage fracture network support, achieved remarkable results [2].
3.3. Intensive controlled fracturing and small well spacing 3D superimposed well placement for shale oil
At present, the development of shale oil typically adopts wide well spacing, long fracture lengths, few fracturing stages, and numerous fracturing clusters. This results in insufficient control over reserves between wells and fractures. Although initial production per well is high, it is challenging to effectively mobilize the reserves between wells and fractures, leading to low estimated recovery for the block and a need for improvement in overall development efficiency. The new approach to fracturing and well spacing design involves creating controlled intensive fractures with a half-length of 100-150 m (depending on the reserves controlled by a single well) radiating along the horizontal section. This forms an approximately cylindrical or square columnar intensive fracture body centered on the horizontal wellbore. By developing blocks superimposing multiple columnar intensive fracture bodies with holistic 3D well placement pattern, it is expected to effectively reduce well spacing, significantly enhance producing degree, and enhance the recovery [2]. This method has been tested in the fracturing and development of shale oil in the Changqing Oilfield, achieving remarkable success [2].
3.4. Cross-layer fracturing for increasing vertical fracture height
The continental shale oil reservoirs in China are characterized by frequent alternations of sandstone and mudstone, with individual sandstone bodies being thin and exhibiting unstable distribution. Laminar shale oil reservoirs often contain numerous low-angle bedding fractures, necessitating the increase of vertical fracture height to connect more of these bedding fractures. Cross-layer fracturing presents a promising solution to this issue. This technique has already been employed in the extraction of unconventional gas such as shale gas and coalbed methane in North America and Australia [2]. However, its application in shale oil extraction has not yet been widely adopted. In the Changqing Oilfield, the Hua H100 platform was designed with 14 cross-layer fracturing stages. Well H5 utilized a hydraulic jet perforating and continuous coiled tubing drag fracturing process across 8 stages, while Well H23 employed custom equal-diameter directional perforating and bridge-shooting combined fracturing technology across 6 stages. By applying acid treatment and pulse plug techniques, high-stress mudstone sections were successfully fractured, allowing fractures to propagate into relatively low-stress sandstone sections. The fractures continued to extend and expand, completing the designed proppant addition. Ultimately, 12 of the 14 stages achieved successful cross-layer fracturing, with a success rate of 85.7%, significantly increasing shale oil productivity [2].
Microwave vibration followed by fracturing is another method designed to achieve cross-layer fracturing and increase vertical fracture height. Specifically, a microwave tool is deployed to a specified shale formation within a horizontal well. High-power microwaves are then released vertically into the formation, causing rapid heating of the rock. When the thermal stress generated within the rock exceeds its strength limit, the rock fractures and disintegrates. Subsequent vertical fracturing can then be applied to achieve cross-layer fracturing, thereby increasing the vertical fracture height [2]. Currently, this method is undergoing in-depth mechanistic research, as well as laboratory and field tests, to further refine and validate its efficacy.
3.5. Waterless fracturing for shale oil
In shale oil reservoirs, only oil and gas phases are typically present, with no water phase. The current practice of large-scale hydraulic fracturing introduces significant amounts of water into the reservoirs. Although this can enhance the recovery of some shale oil through increased pressure and stimulation, it also inevitably causes damage such as water locking. Consequently, the recovery factor using solely hydraulic fracturing methods generally remains below 10%. Waterless fracturing, such as using liquid CO2 in place of traditional water-based fracturing fluids, offers the potential to improve recovery rates significantly while simultaneously conserving water resources. The CO2 dry sand fracturing technology, first applied in North America in the 1980s, has undergone continuous refinement and improvement, and currently, it boasts advantages such as the absence of a water phase, no residue, and rapid flowback, markedly reducing reservoir damage [48]. In September 2022, the Jilin Oilfield designed and executed a medium-scale CO2 dry fracturing operation, injecting nearly 50 m3 of sand and over 1000 m3 of liquid. The test results showed a rapid oil flow, an extended production period, and a significant increase in production [2]. Similarly, the Longdong Shale Oil Demonstration Base in Changqing Oilfield performed CO2 fracturing combined with soluble ball seats for fine intensive volumetric fracturing. The trial significantly boosted formation energy, and prolonged the effective production duration of oil wells, saving approximately 10 000 m3 of water per well, with 1.2×104 m3 of CO2 was sequestered [2].
3.6. Early energy replenishment to enhance shale oil recovery
Currently, shale oil extraction relies on a fracturing-based energy replenishment model, which results in a generally low recovery and suboptimal development effect. This issue is particularly pronounced in shale oil reservoirs with natural fractures; as extraction pressure decreases, these fractures tend to irreversibly close, obstructing flow channels and making restoration difficult. Therefore, it is imperative to replenish reservoir energy as early as possible to maximize recovery. Potential early energy replenishment methods include repeated fracturing, and gas huff-n-puff/displacement. Typically, CO2 huff-n-puff is the most recommended approach. If multiple cycles of huff-n-puff or displacement can be achieved, it could significantly enhance shale oil recovery [49].
The introduction of CO2 into oil reservoirs can induce the expansion of crude oil volume, extracts light components from the crude oil, and achieves miscible displacement. During the puff process, CO2 dissolved gas precipitates, releasing elastic energy. The resulting continuous phase CO2 gas flow strips and carries away remaining oil in various forms. CO2 huff-n-puff tests conducted in Changqing Oilfield, Xinjiang Oilfield, Dagang Oilfield and others have achieved promising results. A pilot test of CO2 huff-n-puff energy replenishment and displacement test was conducted in three typical wells in the Kong 2 member of the Guandong area. The test involved huff-n-puff in the central well while synchronously soaking and blowing the wells on either side. A total of 276 t of CO2 was injected, and all three wells demonstrated increased production. The daily production of the well group rose from 10.8 t before the huff-n-puff to a peak of 23.6 t, effectively realizing energy replenishment from the central well and displacement from neighboring wells. For this test, the effective period reached as long as 459 d, with an oil increment of 1 962.5 t [2].
4. Challenges, prospects and potentials
4.1. Fundamental research techniques and methods
The primary focus of fundamental research is to further deepen the understanding of oil reservoirs, enhancing the capability and proficiency in reservoir characterization and simulation. This encompasses innovations in research techniques, methods, software, and tools. Continental oil reservoirs in China are characterized by severe heterogeneity, especially the low-permeability and ultra-low-permeability reservoirs, tight oil and shale oil, which have been discovered and developed in large numbers in recent years. These reservoirs possess more complex characteristics, often requiring fracturing stimulations before development can commence. Accurately understanding these reservoirs and simulating extraction processes are exceedingly challenging tasks that necessitate ongoing reinforcement of fundamental research.
In-situ sampling for non-destructive testing is the most direct method for understanding oil reservoirs. The primary challenge lies in developing high-temperature, high- pressure resistant non-metallic sampling tools and cross-sampler instruments capable of detection and analysis with micro/nano precision. It is imperative to intensify efforts in the development and testing phases, swiftly refine prototype instruments and their associated analytical techniques, and conduct experimental validations. Continuous improvements in analytical precision are necessary to expedite the application of these tools in the field. This will provide the most effective means for directly understanding the physical properties of subsurface in-situ rocks, as wells as the fluid state and phase occurrence characteristics.
Physical simulation of micro/nano pore systems is crucial for deeply understanding the mechanisms of fluid flow and extraction for subsurface unconventional oil and gas. The current microfluidic experimental systems and methods still face numerous challenges that need resolution. These include ensuring strict sealing and the absence of minute deformations under high-temperature and high-pressure conditions, achieving precise control and accurate measurement of fluid injection and extraction during laboratory experiments, observing interfacial phenomena between different fluids during the experimental process, and establishing the relationship between fluid flow in microscopic models and actual flow in micro/nano pore throats. Further research into micro/nano-scale indoor physical simulation systems and methods is needed to support the in-depth study of subsurface fluid flow and extraction mechanisms.
Large-scale domestic industrial software such as HiSim and FrSmart demonstrate significant advantages when applied to the simulation studies of the complex oil and gas reservoirs in China. However, compared to similar foreign software, they still exhibit deficiencies in aspects such as software functionality, interface design, application experience, and operational maintenance. It is essential to continuously expand and enhance the existing software functions, particularly by strengthening multi- platform reservoir stimulation design, geological modeling, and numerical simulation methods for micro/nano pores, natural fractures, and induced fractures. Additionally, it is crucial to refine software modules that simulate the multi-scale flow extraction processes of unconventional oil and gas, such as shale oil. Accelerating the domestication and broader application of these tools while continually improving them through practical use is imperative.
4.2. EOR methods for mature oilfields
4.2.1. Modified water flooding
For the foreseeable future, water flooding will continue to account for the majority of oil production in China. Modified water flooding to enhance recovery remains a fundamental approach for further developing mature oilfields.
Mature oilfields with medium to high permeability face challenges such as limited improvement in recovery through water injection, high water cut in oil wells, poor economic viability of development, and imminent well abandonment. Single-well injection and production technology can delay the shutdown of wells with extremely high water cut, effectively alleviate the water treatment pressure in high water cut oilfields, reduce the scale of surface collection and transportation systems, and lower energy consumption. However, issues such as complex processes and high production management requirements still persist. It is necessary to continuously strengthen research and experiment, focusing on the directions to structure miniaturization, function integration, and intelligent management. This technology should be developed into a key method for effectively extending the life of mature oilfields.
In low-permeability, ultra-low-permeability, and tight oil fields, techniques such as "nano-water" flooding, polymer microsphere flooding, and ion water flooding have shown promising potential for improving injectivity, enhancing extraction efficiency, and increasing profitability. However, there are still challenges such as limited improvement in recovery, short effective periods, and dispersed production of chemical agents. It is necessary to further improve the performance of nano-displacement agents, deepen the mechanistic understanding, and optimize displacement systems and design schemes. Efforts should be made to continuously expand the application scale and reduce the cost of agents. Additionally, research should focus on advanced technologies such as "nano-water+" polymer flooding, deeper nano-polymer microsphere profile control flooding, and ion water + microbubble composite flooding. The aim is to achieve a greater improvement in water flooding recovery rates.
4.2.2. Chemical flooding
Currently, conventional chemical flooding methods and supporting techniques such as polymer flooding, strong alkali/weak alkali ternary flooding, and binary flooding have been successfully applied in Daqing Oilfield, predominantly in Class I and IIA reservoirs. However, further targeted research is needed for post-chemical flooding reservoirs, as well as Class IIB/III, conglomerate, and low-permeability reservoirs, to select appropriate chemical flooding methods and systems. The goal is to enhance reservoir adaptability and improve oil displacement efficiency and profitability. Establishing an industrial chain and advantageous industry clusters for "chemical agents-transportation-oil displacement" in major application areas will promote large-scale and efficient application of these technologies.
The newly developed methods such as super binary flooding, low-concentration anionic-nonionic surfactant middle-phase microemulsion flooding, bio-chemical surfactant flooding, and high-temperature high-salinity surfactant emulsification profile control flooding have achieved remarkable results in laboratory and pilot tests, showcasing promising application prospects. However, there are still issues such as the inactivation or reduced efficacy of multi-agent composite systems due to chromatographic separation in the formation, high chemical agent concentrations and costs, strong emulsification of produced fluids making treatment difficult, and incomplete regional industrial chains lacking economies of scale. It is essential to further deepen the mechanistic research, develop more efficient and applicable chemical systems, and expand the application scale in suitable reservoirs to create demonstration models.
The anticipated increase in recovery with low-concentration anionic-nonionic surfactant middle-phase microemulsion flooding is substantial, making it a key focus in current research as a successor to traditional chemical flooding technologies. The prominent issue with this technology is that the surfactant composite systems currently used form middle-phase microemulsions during the oil displacement process to enhance oil displacement efficiency. However, the adsorption capacity of formation porous media for different surfactants varies, leading to an imbalance in the proportion of chemical agents upon entering the formation, thereby failing to achieve the designed middle-phase microemulsion flooding effect. Consequently, future research should focus on developing single and efficient surfactants or highly efficient composite systems, broadening the concentration range for forming middle-phase microemulsions, and ensuring the stability of the middle-phase microemulsion system during the oil displacement process to improve efficiency.
The goal of nano intelligent oil displacement is to achieve near-complete displacement of remaining oil, with the potential to become a strategic alternative or disruptive technology for enhancing oil recovery. This technology holds the promise of achieving ultimate recovery rates and has very broad application prospects. Significant research and testing have been conducted along this technical route, and the developed "nano-water" displacement agents have made important progress, addressing the issue of "difficult injection" in low-porosity, low-permeability reservoirs. However, realizing true nano intelligent oil displacement remains a distant goal. The main challenge is that the developed nano chemical agent systems still lack the performance of "strong oleophilicity and strong hydrophobicity," and cannot yet achieve intelligent oil displacement with automatic oil-seeking and water-avoiding capabilities. The next step involves deeply studying the mechanisms of "nano oil" followed by the further development of "nano-water" and "nano-water+" displacement systems. The ultimate objective is to develop nano intelligent displacement agents with multiple functions, including sufficiently small size, strong oleophilicity, strong hydrophobicity, and the ability to disperse and aggregate oil. This will pave the way for achieving intelligent comprehensive oil displacement in reservoirs.
4.2.3. Gas flooding
For ultra-low permeability to tight oil reservoirs where water injection is ineffective, gas injection can establish an efficient displacement system. In mature oilfields, CO2 miscible flooding holds a significant potential. When combined with CCUS, it can achieve multiple benefits, including CO2-EOR and CO2 storage. For reservoirs with a certain inclination, top gas injection for stable gravity-driven recovery can significantly improve recovery rates. In recent years, China has made remarkable progress in gas flooding technology, with multiple field tests achieving success. Currently, the annual oil production from gas flooding has reached the level of 10 million tons. It is anticipated that within the next decade, gas injection for oil recovery will scale up to an annual production of 100 million tons [2], making a crucial contribution to maintaining stable oil production in China.
The development of CO2 flooding and CCUS technology progress rapidly. Currently, the annual CO2 injection exceeds 200×104 t in China, achieving an annual oil production of over 70×104 t. This led to the establishment of a series of miscible, near miscible, and immiscible oil displacement technologies. Several 1 000×104 t-scale CCUS bases are under construction, which will significantly contribute to achieving the "dual carbon" goals and increasing oil production [2]. Although CO2 flooding technology is relatively mature, the industrialization of CCUS still faces challenges. These include the incomplete establishment of technical standards, high CO2 capture cost, and an underdeveloped CCUS full industry chain. It is essential to further refine the technical standards system, optimize and regulate CO2 flooding schemes, and promote the industrialization of CCUS through joint efforts from enterprises at national and local levels.
The micro/nano bubble flooding technology developed for low-permeability reservoirs can increase recovery rates by 8-20 percentage points compared to water flooding. This technology features a simple process, no need for chemical additives, a long-lasting effectiveness period, and low implementation costs. Using purely physical methods for foaming (mainly nano-scale pore plate and ultrasonic methods), it consists only of gas and water, making it environmentally friendly. This technology also has good compatibility with other technologies and can use CO2, N2, hydrocarbon gases, flue gases, and various modified waters. Although this new technology has shown promising results in field applications, some aspects still need improvement. These include a more in-depth understanding of the oil displacement mechanism, a comprehensive evaluation of the stability of bubbles after entering the reservoir, upgrades to the injection tools, and optimization of key parameters such as the optimal gas-to-water ratio. The next steps should focus on combining laboratory research with field tests, rapidly expanding the scale of application, and conducting technical adaptability assessments.
Field tests of top gas injection for stable gravity-driven recovery achieved remarkable results, making it a highly effective technology in significantly improving recovery rates in reservoirs with a certain inclination. This technology holds broad application prospects. However, its application is challenging due to the high reservoir conditions required (such as a larger inclination or thickness of the oil layer), and the need for very slow gas injection to avoid gas channeling and form a sizable gas cap. Therefore, it is essential to further research reservoir adaptability and the technical-economic boundaries of extraction, continuously optimize injection and production parameters, and expand the scale of application.
4.2.4. Thermal recovery
China has successfully developed and applied a series of technologies for extracting medium to deep heavy oil, shallow heavy oil, and ultra-heavy oil, including cyclic steam stimulation, steam flooding, SAGD, and in-situ combustion. It is essential to continuously refine and upgrade these technologies and expand their application scope to support the sustained annual production of over 10 million tons of heavy oil through thermal recovery [2].
Air thermal miscible flooding technology can overcome challenges such as interfacial tension and oil-gas adsorption, extending the application of thermal recovery techniques to low-permeability reservoirs, tight oil, and high water-cut reservoirs. This technology offers efficient energy replenishment/displacement and profitable development for otherwise difficult-to-recover reserves, showing great potential to significantly enhance crude oil recovery rates. Currently, the main issues are the insufficient scale and number of field tests, low control levels of supporting technologies, especially ignition processes, and associated safety risks. Additionally, implementation parameters need further optimization. Continuous field tests in various types of reservoirs are necessary to gain experience and upgrade the technology. At the same time, laboratory research findings should be validated to gradually develop a comprehensive set of supporting technologies and processes. The goal is to establish a widely applicable development mode and technical standards system.
In-situ conversion of heavy oil is a disruptive extraction technology, and a process for in-situ conversion at temperatures below 300 °C has already been developed. However, there are still issues with the immaturity of in-situ conversion processes for different reservoir types and well patterns, unclear application condition boundaries, and the need to improve economic efficiency. Further research into the modification mechanisms and adaptability analysis of the processes is necessary to continually enhance modification effectiveness and profitability. The goal is to quickly establish a high-efficiency, significantly recovery-enhancing in-situ conversion model, expand its application scale, and orderly promote its application to other heavy oil resources.
4.3. Continental shale oil development and EOR methods
Unlike the marine shale oil in North America, the continental shale oil in China is highly heterogeneous, making effective development more challenging. Significant breakthroughs have been achieved in shale oil development in Changqing Oilfield, Xinjiang Oilfield, Daqing Oilfield, Shengli Oilfield, and Dagang Oilfield. The primary extraction mode involves horizontal drilling, hydraulic fracturing, and factory-like operations. A series of extraction technologies tailored to different types of shale oil were formed, with annual shale oil production exceeding 300×104 t, marking the initial realization of effective shale oil extraction [2]. However, there are still significant issues, including, low single-well production and cumulative oil production, rapid production decline, and low block recovery (less than 10%), major technologies should be improved and upgraded for higher development level.
In recent years, newly developed techniques, such as block holistic 3D extraction, CO2 pre-pad fracturing, intensive uniform fracturing, waterless fracturing, vertical fracture height fracturing, early energy replenishment, and CO2 huff-n-puff/displacement, have shown significant advantages and broad application prospects. However, these new technologies suffer from suboptimal implementation parameters, inadequate operation control levels, and a lack of suitability evaluations. Additionally, there is a shortage of CO2 gas sources. To address these challenges, it is crucial to accelerate breakthroughs in fracturing stimulation techniques, and to continuously iterate and upgrade supporting technologies. This involves rapidly developing fracturing and extraction models that are suited to different types of shale oil, as well as a series of effective development and EOR technologies. The goal is to achieve integrated, large-scale, 3D, and profitable block development, hopefully achieving recovery of over 20%. Efforts should also be made to quickly scale up China's annual shale oil production to over 100 million tons, establishing it as a reliable replacement resource for maintaining stable long-term oil production.
5. Conclusions
In recent years, significant advancements have been made in mechanism understanding and technological methods for enhancing oil recovery in oilfields. Remarkable progress has been achieved in EOR technologies such as fundamental research techniques, modified water flooding, chemical flooding/gas flooding/thermal recovery, and shale oil development. Some of these advancements have progressed to field tests, achieving promising initial results and showcasing vast application prospects. Advancements in fundamental research methods, such as in-situ sampling non-destructive testing, subsurface fluid understanding, physical simulation of micro/nano pore systems, and multi-scale geological modeling and numerical simulation, will further enhance the accurate comprehension of various reservoirs and the capability to simulate and optimize development processes. Research on new methods for improving oil recovery in mature oilfields continues to make important progress. In particular, new methods such as super chemical flooding, nano intelligent flooding, CO2 miscible flooding, top gas injection gravity drainage, air thermal miscible flooding, and heavy oil in-situ conversion are expected to evolve into strategic alternatives or even revolutionary EOR techniques for oilfields. The breakthroughs in new fracturing methods for various shale oils, holistic 3D development modes, and early energy replenishment methods for improving recovery will substantially elevate the development level of different shale oils. These advancements will vigorously promote large-scale shale oil production and development.
It is recommended that the nation and petroleum companies further invest in technological innovation. A strategic, goal-oriented approach should be adopted, targeting three layers: "application within 5 years", "application within 5 to 10 years", and "application after 10 years". This involves implementing a dynamic three-generation technology innovation and development system encompassing "supporting applications", "key research trials" and "advanced reserves". By continuously iterating and upgrading, a well-ordered series of new EOR technologies can be developed and seamlessly integrated, thereby ensuring that China maintains its leading position in the development and application of EOR technologies.
It is recommended to further strengthen research efforts on fundamental research methods and techniques. Particular emphasis should be placed on in-situ sampling and non-destructive testing tailored to various complex reservoirs, physical simulation systems and methods, equipment and tools for essential supporting technologies, geological modeling, and numerical simulation, as well as industrial software development. It is crucial to continuously explore new mechanisms and methods for EOR, accelerate the research and breakthrough on key core technologies, and improve corresponding supporting technologies.
It is recommended to increase the intensity of field tests for new EOR methods. This includes conducting pilot verification tests, expanding well group tests, and industrial application tests. Efforts should be made to establish supporting technologies and standards system, development modes, and corresponding industrial chains. These actions will help to continuously improve the recovery rates of various reservoirs, support and lead chemical flooding and thermal recovery to sustain annual production levels of over 1 000×104 t each in a long term, and to expedite the production of gas flooding and shale oil to reach annual production scales of 1 000× 104 t each. These measures will robustly support the long-term stable production of crude oil in China.