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Taking the Wufeng-Longmaxi shale gas in the Sichuan Basin as a typical example, based on the new progress in exploration and development, this study re-examines the “unconventional” of unconventional oil and gas from two aspects: oil and gas formation and accumulation mechanisms, and main features of oil and gas layers. The oil and gas of continuous accumulation and distribution from integrated source and reservoir is unconventional oil and gas, and the study focusing on shale oil and gas in comparison with conventional oil and gas has made progress in five aspects: (1) Unconventional oil and gas have source-reservoir-in-one and in-situ accumulation; according to the theory of continuous oil and gas accumulation, the accumulation power of oil and gas is overpressure and diffusion; for conventional oil and gas, the source and reservoir are different formations, the trapping accumulation is its theoretical foundation, and the accumulation power is characterized by buoyancy and capillary force. (2) The unconventional oil and gas reservoirs are mainly formed in the low-energy oxygen-anaerobic environment, dominantly semi-deep to deep shelf facies and the semi-deep to deep lake facies, simple in lithology, rich in organic matter and clay minerals; conventional oil and gas mainly occur in coarse-grained sedimentary rocks formed in high-energy waters with complex lithology. (3) The unconventional oil and gas reservoirs have mainly nano-scale pores, of which organic matter pores take a considerable proportion; conventional oil and gas reservoirs mainly have micron-millimeter pores and no organic matter pores. (4) Unconventional shale oil and gas reservoirs have oil and gas in uniform distribution, high oil and gas saturation, low or no water content, and no obvious oil and gas water boundary; conventional oil and gas reservoirs have oil and gas of complex properties, moderate oil and gas saturation, slightly higher water content, and obvious oil, gas and water boundaries. (5) Organic-rich shale is the main target of unconventional oil and gas exploration; the sedimentary environment controls high organic matter abundance zone and organic matter content controls oil and gas abundance; positive structure and high porosity control the yields of shale wells; bedding and fracture development are important factors deciding high yield.
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The Junggar Basin is one of the major petroliferous basins with abundant oil and gas resources in onshore China. Around 2010 and thereafter, the hydrocarbon exploration for finding giant fields in the basin faced tough difficulties: in the northwestern margin area, no significant breakthrough has been made for long since seeking to “escape from the step-fault zone and extend to the slope area”; in the central part, the exploration for large lithologic-stratigraphic reservoirs stood still; since the discovery of the Kelameili gas field, no important achievement has been made in gas exploration. Under the guidance of “whole sag-oil-bearing” theory in the petroliferous basin, and based on the long-term study and thinking of the petroleum accumulation conditions and characteristics, the authors proposed several new concepts, i.e., a “thrust-induced second-order fault step” hiding under the northwestern slope area; six “hydrocarbon migrationward surfaces” favorable for hydrocarbon accumulation; promising natural gas resource. These concepts have played an important role in the discoveries of Wells Mahu1 and Yanbei1 as well as the confirmation and expansion of Permian-Triassic billion-ton-scale petroliferous areas in Mahu. The fairway of new discoveries has also appeared for natural gas exploration in Wells Fu26, Gaotan1 and Qianshao2, suggesting that the surrounding regions of the highly matured source kitchen are of high possibility to form gas accumulations.
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Based on field outcrop investigation, interpretation and analysis of drilling and seismic data, and consulting on a large number of previous research results, the characteristics of ancient marine hydrocarbon source rocks, favorable reservoir facies belts, hydrocarbon migration direction and reservoir-forming law in the Ordos Basin have been studied from the viewpoints of North China Craton breakup and Qilian-Qinling oceanic basin opening and closing. Four main results are obtained: (1) Controlled by deep-water shelf-rift, there are three suites of source rocks in the Ordos Basin and its periphery: Mesoproterozoic, Lower Cambrian and Middle-Upper Ordovician. (2) Controlled by littoral environment, paleo-uplift and platform margin, four types of reservoirs are developed in the area: Mesoproterozoic- Lower Cambrian littoral shallow sea quartz sandstone, Middle-Upper Cambrian-Ordovician weathering crust and dolomitized reservoir, and Ordovician L-shape platform margin reef and beach bodies. (3) Reservoir-forming assemblages vary greatly in the study area, with “upper generation and lower storage” as the main pattern in the platform, followed by “self-generation and self-storage”. There are both “upper generation and lower storage” and “self-generation and self-storage” in the platform margin zone. In addition, in the case of communication between deep-large faults and the Changchengian system paleo-rift trough, there may also exist a “lower generation and upper reservoir” combination between the platform and the margin. (4) There are four new exploration fields including Qingyang paleo-uplift pre-Carboniferous weathering crust, L-shape platform margin zone in southwestern margin of the basin, Ordovician subsalt assemblage in central and eastern parts of the basin, and Mesoproterozoic-Cambrian. Among them, pre-Carboniferous weathering crust and L-shape platform margin facies zone are more realistic replacement areas, and Ordovician subsalt assemblage and the Proterozoic- Cambrian have certain potential and are worth exploring.
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Comprehensively utilizing the seismic, logging, drilling and outcrop data, this research studies the characteristics of the Cambrian faults and their control on the sedimentation and reservoirs in the Ordos Basin. The results show that: (1) Three groups of faults striking North-East (NE), near East-West (EW), and North-West (NW) were developed in the Cambrian. The NE and near EW faults, dominated by the normal faults, are the synsedimentary faults and the main faults of the Cambrian. (2) According to the roles of faults in tectonic units and the development scale of the faults, the Cambrian faults can be divided into three grades. The second-grade faults, large in scale, controlled the boundary of the Cambrian sags of the Ordos Basin. The third-grade faults, smaller in scale than the second-grade fault, controlled the high and low fluctuations of local structures. The fourth-grade faults, very small in scale, were adjusting faults developed inside the local tectonic units. (3) The Cambrian faults had strong control on the sedimentation and reservoir of the Cambrian. Controlled by the second-grade and the third-grade faults, the paleogeographical framework of the Cambrian presents combination characteristics of the bulge-sag macro-structures and the high-low differentiation micro-geomorphology. This paleogeographical pattern not only controlled the development of the oolitic beach facies in the Cambrian but also the distribution of high-quality reservoirs. (4) Under the control of the faults, the micro-paleogeomorphological high parts closely adjacent to the margin of the Cambrian sags are the favorable exploration areas.
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Based on the compilation and analysis of the lithofacies and paleogeography distribution maps at present and paleoplate locations during six key geological periods of the Mesozoic and Cenozoic, the lithofacies and paleogeography features and their development laws were expounded. Based on our previous research results on lithofacies and paleogeography from Precambrian to Paleozoic, we systematically studied the features and evolution laws of global lithofacies and paleogeography from the Precambrian and their effects on the formation of source rocks, reservoirs, cap rocks and the distribution of oil and gas worldwide. The results show that since Precambrian, the distribution areas of uplift erosion and terrestrial clastic deposition tended to increase gradually, and increased significantly during the period of continental growth. The scale of coastal and shallow marine facies area had three distinct cycles, namely, from Precambrian to Devonian, from Carboniferous to Triassic, and from Jurassic to Neogene. Correspondingly, the development of shallow carbonate platform also showed three cycles; the lacustrine facies onshore was relatively developed in Mesozoic and Cenozoic; the sabkha was mainly developed in the Devonian, Permian and Triassic. The Cretaceous is the most important source rock layers in the world, followed by the Jurassic and Paleogene source rocks; the clastic reservoirs have more oil and gas than the carbonate reservoirs; the basins with shale caprocks have the widest distribution, the most abundant reserves of oil and gas, and the evaporite caprocks have the strongest sealing capacity, which can seal some huge oil and gas fields.
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Based on seismic and logging data, taking the downthrow fault nose of Binhai fault in Qikou Sag as the object of study, we analyzed fault characteristics, sand body distribution, fault-sand combinations and hydrocarbon accumulation to reveal the hydrocarbon enrichment law in the fault-rich area of fault depression lake basin. The results show that the Binhai Cenozoic fault nose is characterized by east-west zoning, the main part of the western fault segment is simple in structure, whereas the broom-shaped faults in the eastern segment are complex in structure, including several groups of faults. The difference of fault evolution controls the spatial distribution of sand bodies. The sand bodies are in continuous large pieces in the downthrow fault trough belt along the Gangdong Fault in the middle segment of the fault nose, forming consequent fault-sand combination; whereas the fault activity period of the eastern part of the fault nose was later, and the sand bodies controlled by paleogeomorphology are distributed in multi-phase north-south finger-shaped pattern, forming vertical fault-sand combination pattern matching with the fault. The configuration between faults and sand bodies, and oil sources and caprocks determine the vertical conductivity, plane distribution and vertical distribution of oil and gas. Two oil and gas accumulation modes, i.e. single main fault hydrocarbon supply-fault sand consequent matching-oil accumulation in multi-layers stereoscopically and fault system transportation-fault sand vertical matching-oil accumulation in banded overlapping layers occur in the middle and eastern segments of the fault nose respectively, and they control the difference of oil and gas distribution and enrichment degree in the Binhai fault nose.
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Permeability prediction using linear regression of porosity always has poor performance when the reservoir with complex pore structure and large variation of lithofacies. A new method is proposed to predict permeability by comprehensively considering pore structure, porosity and lithofacies. In this method, firstly, the lithofacies classification is carried out using the elastic parameters, porosity and shear frame flexibility factor. Then, for each lithofacies, the elastic parameters, porosity and shear frame flexibility factor are used to obtain permeability from regression. The permeability prediction test by logging data of the study area shows that the shear frame flexibility factor that characterizes the pore structure is more sensitive to permeability than the conventional elastic parameters, so it can predict permeability more accurately. In addition, the permeability prediction is depending on the precision of lithofacies classification, reliable lithofacies classification is the precondition of permeability prediction. The field data application verifies that the proposed permeability prediction method based on pore structure parameters and lithofacies is accurate and effective. This approach provides an effective tool for permeability prediction.
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Based on well logging responses, sedimentary patterns and sandstone thickness, the distribution characteristics of meandering river sedimentary sand body of Neogene Minghuazhen Formation NmⅢ2 layer in the west of Shijiutuo Bulge, Chengning Uplift, Bohai Bay Basin were investigated. A new approach to calculate the occurrence of the sand-mudstone interfaces using resistivity log of horizontal well was advanced to solve the multiple solution problem of abandoned channel’s orientation. This method uses the trigonometric function relationship between radius, dip and length of the resistivity log to calculate the occurrence qualitatively - quantitatively to help determine the true direction of the abandoned channels. This method can supplement and improve the architecture dissection technique for meandering river sandbodies. This method was used to study the dip angle and scale of the lateral accretion layers in point bar quantitatively to help determine the spatial distribution of lateral accretion layers. The fine architecture model of underground meandering river reservoir in the study area has been established. Different from traditional grids, different grid densities for lateral accretion layers and bodies were used in this model by non-uniform upscaling to establish the inner architecture model of point-bars and realize industrial numerical simulation of the whole study area. The research results can help us predict the distribution of remaining oil, tap remaining oil, and optimize the waterflooding in oilfields.
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Different configurational orders of sand bodies and interlayers in lacustrine nearshore sand bar reservoirs frequently interact, causing complicated genesis and distribution of argillaceous sediments, as well as other issues. This paper investigates the spatial configuration of sand and mud in the sand bar reservoir, and analyzes its internal structure. Modern sand bar deposits in the Xiashan Lake, Shandong Province, China, were analyzed and compared with the sand bar reservoirs of the Member 2 of the Paleogene Shahejie Formation in the Banqiao Sag, China. The configurational mode of sand bar deposits was explored from the perspective of the spatial distribution and composition relationships between sand and mud. Based on the alternate deposition characteristics of sand and mud in the longitudinal direction, lacustrine nearshore sand bars can be divided into three sedimentary combination patterns: thin-sand and thin-mud interbed pattern, thick-mud thick-sand pattern, and thin-mud thick-sand pattern. Their mud components manifest as the deposition of fine-grained lithofacies of multiple genetic types. These include (semi-)deep lacustrine mud, sand and mud interbedded beach, argillaceous sediments in the water retention area behind the bar, and fall-silt seams that resulted from flood discharge. By summarizing the specific developmental locations and sequential relationships of each fine-grained argillaceous facies in modern sand bar deposits, a depositional process-based argillaceous sediment composition model is proposed. Based on this, this paper discusses the spatial configuration of sand bodies and argillaceous sediments in sand bar reservoirs, and introduces the typical stratigraphic structures of sand bars in two environments, i.e., vertical superposition and lateral migration. In lacustrine nearshore sand bar reservoirs, the deposition and preservation degrees of mud mainly depend on three factors: accommodation space change, frequency of base-level cycles, and exposure-erosion time. These in turn influence the continuity and relative contents of sand and mud in reservoirs. The distribution of argillaceous sediments forms different orders of interlayers, which affects the heterogeneity and fluid percolation of sand bar reservoirs. Clarifying the space-matching relationship of sand and mud in sand bar deposits provides geological models and information parameters for the refined characterization and modeling of the internal configuration of sand bar reservoirs. Furthermore, this work offers guidance for the optimal adjustment of reservoir development strategies or the optimization of reservoir development plans.
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Regarding to the problem on the reservoir-cap rock assemblage evaluation in the carbonate-evaporite paragenesis system, this study examined the dolomite and reservoirs genesis and the characteristics of reservoir-cap rock assemblage. Based on the literature research of the global carbonate reservoirs and the case study on four profiles of carbonate-evaporite succession, together with geological and experimental work, three aspects of understandings are achieved. (1) Lithology of carbonate-evaporite paragenesis system is mainly composed of microbial limestone/bioclastic limestone, microbial dolomite, gypsum dolomite and gypsum salt rock deposited sequentially under the climatic conditions from humid to arid, and vice versa, and an abrupt climate change event would lead to the lack of one or more rock types. (2) There developed two kinds of dolomite (precipitation and metasomatism) and three kinds of reservoirs in the carbonate-evaporite system; and the carbon dioxide and organic acid generated during early microorganism degradation and late microbial dolomite pyrolysis process, and early dolomitization are the main factors affecting the development of microbial dolomite reservoirs with good quality. (3) In theory, there are 14 types of reservoir-cap rock assemblages of six categories in the carbonate-evaporite system, but oil and gas discoveries are mainly in four types of reservoir-cap rock assemblages, namely “microbial limestone/bioclastic limestone - microbial dolomite - gypsum dolomite - gypsum salt rock”, “microbial limestone/bioclastic limestone - gypsum salt rock”, “microbial dolomite - gypsum dolomite - gypsum salt rock” and “gypsum dolomite - microbial dolomite - tight carbonate or clastic rock”. These four kinds of reservoir-cap rock assemblages should be related with the climate change rules in the geologic history, and have good exploration prospects.
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The evolution process and petroleum significance of two groups of fault structures, the NW-SE trending and near EW trending ones in the Cenozoic of Dongping-Niuzhong area of the Altyn slope, Qaidam Basin, were investigated using high precision 3-D seismic data. The NW-SE faults were generated in Oligocene, causing the formation of a series of folds related to transpression faults in the Niuzhong and Dongping area. After the Miocene, with the continuous extension of the Altyn Tagh strike-slip fault zone, the EW trending faults began to develop massively in Altyn slope. The activity of near EW trending faults and large-scale uplift of the bedrock in the northern Niuzhong area shared most of the compression torsion in Niuzhong and Dongping area, consequently, the activity of NW-SE trending faults weakened significantly after the Miocene. Then good hydrocarbon source rocks developed in the inherited Jurassic sags. The faults were effective pathways for oil and gas migration in Dongping and Niuzhong areas, and the oil and gas charging time matched well with the formation period of the NW-SE trending faults and their related structures, making the fault-related anticlines favorable targets for oil and gas accumulation. The Niuzhong area has been less affected by the Cenozoic movement after the Miocene, and thus has better conditions for gas reservoir preservation.
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The effect of expanding swept volume by iNanoW1.0 nanoparticles in ultra-low permeability core was studied by low-field nuclear magnetic resonance (LF-NMR) technology, and the mechanism of expanding swept volume was explained by oxygen spectrum nuclear magnetic resonance ( 17O-NMR) experiments and capillarity analysis. The results of the LF-NMR experiment show that the nano-sized oil-displacement agent iNanoW1.0 could increase the swept volume by 10%-20% on the basis of conventional water flooding, making water molecules get into the low permeable region with small pores that conventional water flooding could not reach. 17O-NMR technique and capillary analysis proved that iNanoW1.0 nanoparticles could weaken the association of hydrogen bonds between water molecules, effectively change the structure of water molecular clusters, and thus increasing the swept volume in the low permeable region. The ability of weakening association of hydrogen bonds between water molecules of iNanoW1.0 nanoparticles increases with its mass fraction and tends to be stable after the mass fraction of 0.1%.
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To identify the type of main flow channels of complex porous media in oil and gas reservoirs, the “main flow channel index” is defined as the ratio of comprehensive permeability obtained from well test to matrix permeability obtained from core analysis or well logging. Meanwhile, a mathematical model is established based on equivalent flow assumption, the classification method for main flow channels is put forward, and quantitative characterization of main flow channels is realized. The method has been verified by analysis of typical gas reservoirs. The study results show that the “main flow channel index” can quantitatively classify types of flow channels. If the index is less than 3, the matrix pore is the main flow channel; if the index is between 3 and 20, the fracture is the main flow channel and the matrix pore acts as the supplement one; if the index is more than 20, the fracture is the only seepage channel. The dynamic analysis of typical gas reservoirs shows that the “main flow channel index” can be used to identify the type of flow channel in complex porous media, guiding the classified development of gas reservoirs, and avoiding development risk.
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The relationship between NaCl concentration and the phase change behavior of microemulsion of anionic surfactant was characterized by the salinity scan experiments. The wettability of Winsor Ⅰ type surfactant solution (WⅠ solution) and the effect of NaCL concentration on phase change behavior of WI solution and imbibition in oil-wet porous media were investigated by microfluidic experiments in this study. The WⅠ solution and Winsor I type microemulsion are similar in wetting phase with stronger wettability than other phases. Two main mechanisms of WⅠ solution enhancing imbibitions recovery in oil wet porous media are the wetting phase drive and residual oil solubilization. Under the salinity condition of Winsor I type microemulsion, the NaCl concentration has strong impact on the imbibition mechanism of WI solution, the higher the NaCl concentration, the complex the imbibition process and the higher the imbibition efficiency will be. The NaCl concentration has strong impact on the solubilization ability to oil of the WI solution, the higher the NaCl concentration, the stronger the solubility of the WI solution to residual oil will be.
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The multidimensional analysis engine data management platform is constructed using big data distributed storage and parallel computing, data warehouse modeling technology, realizing the optimal management and instant query of distributed oil and gas production dynamic big data. The centralized management and quick response of the production data of more than 36×10 4 oil, gas and water wells is realized. Multidimensional analysis subject model of oil, gas and water well production is built to pretreat the relevant data. At the level of China National Petroleum Corporation (CNPC), the rapid analysis and applications such as oil and gas production tracking, early production warning of key oilfields, analysis of low production wells and long shutdown wells, classification of reservoir development laws have been realized, and the processing time has been shortened from 1 d to 5 s. The basic unit of oil and gas production analysis is refined from oilfield to single well, making the production management more detailed. The process can be traced step by step according to CNPC, oil field company, field, block and single well, and the oil and gas production performance of each unit can be mastered in real time.
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The conventional foaming agents have the problems of poor adaptability and high cost during the application in different types of gas fields, especially in high temperature, high salinity, high acidic gas and high condensate oil and gas fields. In this study, the Gemini foaming agent was used as the main agent to enhance foaming and foam stability of the foaming agent, the grafted nanoparticles were used as foam stabilizer to further improve the foam stability, and the characteristic auxiliaries were added to make the foaming agent suitable for different types of gas reservoirs. Two types and six subtypes of nanoparticle foaming agents have been prepared for the main gas fields of China. The experimental evaluation results show that the overall temperature resistance, salinity resistance, H2S resistance, CO2 resistance and condensate resistance of the nanoparticle foaming agents can reach 160℃, 250 000 mg/L, 100 mg/L, 100% and 40%, respectively. The new foaming agents have been used in 8685 wells in China. Compared with conventional foaming agent, the average gas flow rate per well increased by 62.48%, the pressure difference (casing-tubing) decreased by 18.9%, and the cost dropped by 45%. The effect of reducing cost and increasing efficiency is obvious.
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The wellbore stability of a vertical well through the sandstone reservoir layers of the Asmari oil-bearing formation in south-west Iran is investigated. The safe drilling-fluid density range for maintaining wellbore stability is determined and simulated using FLAC3D software and a finite volume model established with drilled strata geomechanical features. The initiation of plastic condition is used to determine the safe mud weight window (SMWW) in specific sandstone layers. The effects of rock strength parameters, major stresses around the wellbore and pore pressure on the SMWW are investigated for this wellbore. Sensitivity analysis reveals that a reduction in cohesion and internal friction angle values leads to a significant narrowing of the SMWW. On the other hand, the reduction of pore pressure and the ratio between maximum and minimum horizontal stresses causes the SMWW to widen significantly. The ability to readily quantify changes in SMWW indicates that the developed model is suitable as a well planning and monitoring tool.
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A flow mathematical model with multiple horizontal wells considering interference between wells and fractures was established by taking the variable width conductivity fractures as basic flow units. Then a semi-analytical approach was proposed to model the production performance of full-life cycle in well pad and to investigate the effect of fracture length, flow capacity, well spacing and fracture spacing on estimated ultimate recovery (EUR). Finally, an integrated workflow is developed to optimize drilling and completion parameters of the horizontal wells by incorporating the productivity prediction and economic evaluation. It is defined as nested optimization which consists of outer-optimization shell (i.e., economic profit as outer constraint) and inner-optimization shell (i.e., fracturing scale as inner constraint). The results show that, when the constraint conditions aren’t considered, the performance of the well pad can be improved by increasing contact area between fracture and formation, reducing interference between fractures/wells, balancing inflow and outflow between fracture and formation, but there is no best compromise between drilling and completion parameters. When only the inner constraint condition is considered, there only exists the optimal fracture conductivity and fracture length. When considering both inner and outer constraints, the optimization decisions including fracture conductivity and fracture length, well spacing, fracture spacing are achieved and correlated. When the fracturing scale is small, small well spacing, wide fracture spacing and short fracture should be adopted. When the fracturing scale is large, big well spacing, small fracture spacing and long fracture should be used.
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Hydraulic fracturing is a key technology in shale gas extraction, whether hydraulic fracturing induces earthquakes has become a hot topic in the public and the focus of scholars' research. The urgency of shale gas mining and the catastrophic nature of earthquakes highlight the urgent need to study this issue. The Changning anticline at the southern margin of the Sichuan Basin is a key area for shale gas exploitation. Taking this as an example, this paper applies the velocity model of the study area to reposition the M5.7 magnitude earthquake on December 16, 2018 and the M5.3 magnitude earthquake on January 03, 2019 and their aftershock sequence in this area. Using shale gas exploration drilling and reflection seismic data to carry out structural analysis, and recovering the tectonic geological setting of earthquake occurrence by restoring the formation process of the Changning anticline, to further explore the seismic mechanism. Our results show that the Changning anticline is a large basement fault-bend fold, and the displacement of the fault forming the anticline is 18 km, and the Changning anticline absorbs 33% of the fault slip. The Silurian Longmaxi Formation of the Changning anticline experienced larger-parallel shearing along underlying basement faults, forming a micro-fracture system. The footwall ramp of the basement fault is reactivated at present, earthquakes in this area mostly occur along the footwall ramp of the basement fault and above and below it. The anticlinal and synclinal hinge zones are also the earthquake concentration areas, but the earthquake magnitude decreases upwards along the kink-band, and small earthquakes below M2.0 occur in the Silurian Longmaxi Formation. So far, the earthquake in the Changning anticline mainly occurred in the southern limb of the anticline, which is a natural earthquake formed along the footwall ramp of the basement fault. The earthquakes in the Changning area are possible related to the geo-tectonic setting for the southeast outward compression of the Qinghai-Tibet Plateau at present, the moderate or large-scale earthquakes in the southwest Sichuan Basin are mainly due to the reactivation during late Quaternary of the earlier formed faults. It is suggested to carry out scientific monitoring of seismic activities in shale gas development zones.
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Two main challenges exist in enhancing oil recovery rate from tight oil reservoirs, namely how to create an effective complicated fracture network and how to enhance the imbibition effect of fracturing fluid. In response to the challenges, through modeling experiment in laboratory and evaluation of field application results, a set of integrated efficient fracturing and enhanced oil recovery (EOR) techniques suitable for tight oil development in China has been proposed. (1) Fracturing with temporary plugging agents to realize stimulation in multiple clusters, to form dense fracture network, and thus maximizing the drainage area; (2) Supporting induced fractures with micro-sized proppants during the prepad fluid fracture-making stage, to generate dense fracture network with high conductivity; (3) Using the liquid nanofluid as a fracturing fluid additive to increase oil-water displacement ratio and take advantage of the massive injected fracturing fluid and maximize the oil production after hydraulic fracturing.
