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SummaryFracturing is the necessary means of tight oil development, and the most common fracturing fluid is slickwater. However, the Loess Plateau of the Ordos Basin in China is seriously short of water resources. Therefore, the tight oil development in this area by hydraulic fracturing is extremely costly and environmentally unfriendly. In this paper, a new method using supercritical carbon dioxide (CO2) (ScCO2) as the prefracturing energized fluid is applied in hydraulic fracturing. This method can give full play to the dual advantages of ScCO2 characteristics and mixed-water fracturing technology while saving water resources at the same time. On the other hand, this method can reduce reservoir damage, change rock microstructure, and significantly increase oil production, which is a development method with broad application potential.In this work, the main mechanism, the system-energy enhancement, and flowback efficiency of ScCO2 as the prefracturing energized fluid were investigated. First, the microscopic mechanism of ScCO2 was studied, and the effects of ScCO2 on pores and rock minerals were analyzed by nuclear-magnetic-resonance (NMR) test, X-ray-diffraction (XRD) analysis, and scanning-electron-microscope (SEM) experiments. Second, the high-pressure chamber-reaction experiment was conducted to study the interaction mechanism between ScCO2 and live oil under formation conditions, and quantitively describe the change of high-pressure physical properties of live oil after ScCO2 injection. Then, the numerical-simulation method was applied to analyze the distribution and existence state of ScCO2, as well as the changes of live-oil density, viscosity, and composition in different stages during the full-cycle fracturing process. Finally, four injection modes of ScCO2-injection core-laboratory experiments were designed to compare the performance of ScCO2 and slickwater in terms of energy enhancement and flowback efficiency, then optimize the optimal CO2-injection mode and the optimal injection amount of CO2 slug.The results show that ScCO2 can dissolve calcite and clay minerals (illite and chlorite) to generate pores with sizes in the range of 0.1 to 10 µm, which is the main reason for the porosity and permeability increases. Besides, the generated secondary clay minerals and dispersion of previously cemented rock particles will block the pores. ScCO2 injection increases the saturation pressure, expansion coefficient, volume coefficient, density, and compressibility of crude oil, which are the main mechanisms of energy increase and oil-production enhancement. After analyzing the four different injection-mode tests, the optimal one is to first inject CO2 and then inject slickwater. The CO2 slug has the optimal value, which is 0.5 pore volume (PV) in this paper.In this paper, the main mechanisms of using ScCO2 as the prefracturing energized fluid are illuminated. Experimental studies have proved the pressure increase, production enhancement, and flowback potential of CO2 prefracturing. The application of this method is of great significance to the protection of water resources and the improvement of the fracturing effect.

To explore the source and reservoir characteristics of Chang 6 tight oil in the Zhangjiagou area, we have extracted a suite of Chang 6 tight sandstones and the source rocks from the seventh to ninth members of the Upper Cretaceous Yanchang Formation in the Ordos Basin, China, respectively, using chloroform. We examined group components by fractionations of extracted organic matter. Using low-pressure gas adsorptions and gas chromatography-mass spectrometry, respectively, we analyzed the pore structure of the studied samples before and after extraction and the oil source of the separate saturated hydrocarbon components. The results indicate that the porosity of the Chang 6 tight sandstone is mainly distributed in the 8%–14% range, averaging 10.5%, the permeability of the studied reservoir is only approximately 0.16 × 10−3 μm2, and the pore-throat radius is mainly less than 2 μm. The major type of pores of the reservoir includes the residual intergranular pore, secondary intergranular dissolved pore, and intragranular dissolved pore. The micropore volume of the Chang 6 tight sandstone is in the range of 0.0071–0.0092 cm3/g, and the mesopore volume of the Chang 6 tight sandstone is in the range of 0.0237–0.0343 cm3/g. The micropore volume and micropore surface area significantly increased after chloroform extractions, and soluble hydrocarbons could be stored in micropores of the Chang 6 tight sandstone. The three sets of source rocks from the seventh to ninth members of the Upper Cretaceous Yanchang Formation are high quality by the evaluation of source rocks, and the Chang 7 has the highest value of source rocks, followed by Chang 9 and Chang 8. The pentacyclic triterpene characteristics (Ts-C30H-C30*) of Chang 6 crude oil are similar to those of Chang 7 source rock, and the tight oil of the Chang 6 member in the Zhangjiagou area originated from Chang 7 source rocks.

Distributed temperature sensing (DTS) has been used for fracture parameter diagnosis and flow profile monitoring. In this paper, we present a new model for predicting the temperature profile of two-phase flow multistage fractured horizontal wells in the tight oil reservoirs. The homogeneous reservoir flow/heat transfer model is extended to the tight oil reservoir-fracture-wellbore coupled flow/thermal model. The influence of SRV area on reservoir and wellbore is considered, and the Joule-Thomson effect, heat convection, heat conduction, and other parameters are introduced into the improved model. The temperature distributions of reservoir and wellbore with different production times, water cut, and locations of water entry are simulated. The simulated results indicate that the Joule-Thomson effect will cause wellbore temperature to rise; the temperature of fractures with more water production is significantly lower than that of other fractures, and the water outlet location can be judged according to the temperature change of the wellbore. By using the improved temperature prediction model, the DTS monitoring data of two-phase flow multistage fractured horizontal well in the tight reservoir has been calculated and analyzed, and the accurate production profile has been obtained.

The successful development of unconventional hydrocarbons has significantly increased global hydrocarbon resources, promoted the growth of global hydrocarbon production and made a great breakthrough in classical oil and gas geology. The core mechanism of conventional hydrocarbon accumulation is the preservation of hydrocarbons by trap enrichment and buoyancy, while unconventional hydrocarbons are characterized by continuous accumulation and non-buoyancy accumulation. It is revealed that the key of formation mechanism of the unconventional reservoirs is the self-sealing of hydrocarbons driven by intermolecular forces. Based on the behavior of intermolecular forces and the corresponding self-sealing, the formation mechanisms of unconventional oil and gas can be classified into three categories: (1) thick oil and bitumen, which are dominated by large molecular viscous force and condensation force; (2) tight oil and gas, shale oil and gas and coal-bed methane, which are dominated by capillary forces and molecular adsorption; and (3) gas hydrate, which is dominated by intermolecular clathration. This study discusses in detail the characteristics, boundary conditions and geological examples of self-sealing of the five types of unconventional resources, and the basic principles and mathematical characterization of intermolecular forces. This research will deepen the understanding of formation mechanisms of unconventional hydrocarbons, improve the ability to predict and evaluate unconventional oil and gas resources, and promote the development and production techniques and potential production capacity of unconventional oil and gas.

Lucaogou formation in Jimsar sag is host to large quantities of bedding fractures which are known to play a critical role in the enrichment, accumulation, and efficient development of tight oil. In this paper, we examine and finely characterize the development of the bedding fractures found in the upper and lower sweet spots of Lucaogou formation of tight oil reservoir through field outcrop and core observation, cast thin section analysis, and imaging log recognition and investigate the factors affecting their differentiated oil-bearing by means of inclusion temperature measurement, TOC testing, physical property testing, high-pressure mercury injection, and physical simulation experiment. By comparison with the linear density, bedding fractures are more developed in the lower sweet spot. These fractures occur in parallel to the formation boundary and have small aperture. Most of bedding fractures are unfilled fractures. Among the few types of fractures found there, bedding fractures have the best oil-bearing property, but the oil-bearing can differ from one bedding fracture to another. The factors affecting the differentiated oil-bearing of bedding fractures include the temporal coupling of the formation of these fractures with the hydrocarbon generation of the source rocks and the spatial coupling of the bedding fractures with the source rocks. In terms of temporal coupling, mass hydrocarbon generation in Jimsar sag began in Late Jurassic. Inclusion temperature measurement indicates that the bedding fractures there formed in or after Early Cretaceous. Hence, by matching the mass hydrocarbon generation period of the source rocks with the formation period of the bedding fractures, we discovered that the bedding fractures formed within the mass hydrocarbon generation period, which favored the oil-bearing of these fractures. The spatial coupling is manifested in TOC, porosity, permeability, and pore throat, with TOC being the main controlling factor. For TOC, the higher the formation TOC, the better the oil-bearing property of the bedding fractures. For porosity, subject to the TOC level, if the TOC is adequate, the larger the porosity, the larger the chloroform asphalt “A,” accordingly the higher the oil content of the formation, and the better the oil-bearing property of the bedding fractures developed therein. In this sense, in terms of spatial coupling, TOC constitutes the main controlling factor of the oil-bearing property of bedding fractures.

Wettability is an essential property of reservoirs that is of great importance for enhancing oil recovery (EOR) and oil migration. The wettability of reservoirs is generally believed to be strongly affected by mineral compositions but it is not always the case. An integrated study of petrography and wettability was carried out to determine the impact of chlorite minerals on the wettability of the sandstone reservoirs in the Upper Triassic Yanchang Formation. Chlorites are found to be commonly present in the reservoir sandstones as detrital grains, rim-shaped cements, and biotite-chloritized forms with the pore peripheries being largely coated by chlorite, which is the main mineral in direct contact with pores. At pore scale, the wetting state of chlorites can either be oil-wet or water-wet in the tight sandstone reservoirs depending on wettability alteration by oil charge. Chlorites in contact with pores occupy a large of proportions of oil-wet pore walls and are crucial for the formation of oil-wetting state of reservoir sandstones. At core scale, the contents of chlorites in direct contact with pores do not correlate well with the Amott-Harvey index due to other factors such as heterogeneity, oil-bearing degrees of samples.

Tight oil reservoirs are key research targets of petroleum geological exploration. Due to their strong heterogeneity, reservoir classification is fuzzy and efficiency is low, which affects reservoir evaluation accuracy. This study aims to improve the accuracy of the evaluation of microscopic pore throats of tight reservoir. Tight oil reservoir is classified on the basis of microscopic pore-throat grading with machine learning technology including Box-Cox transformations, Grey relational analysis, Q-cluster analysis, and discriminant analysis, in combination with traditional measures of reservoir quality in the Fuyu oil layer, Bayanchagan area, Songliao Basin. The results show that Class I reservoirs are high-quality, medium compaction-strong dissolution-weak cementation reservoirs, with large pore-throat radii, concentrated from 0.16 μm to 1.00 μm. Class II reservoirs have medium potential, with strong compaction-medium dissolution-medium cementation. Pore throats have relatively uniform distribution with low connectivity, and radii mainly between 0.016 μm to 0.16 μm. The Class III reservoir has the lowest potential and strong heterogeneity, with strong compaction, weak dissolution, and strong cementation. Small pore-throat radii range from 0.002 μm to 0.016 μm. We infer that this method can effectively evaluate tight oil reservoirs and provide a basis for the prediction of favorable areas for tight oil exploration and development.

Taking the tight oil of the Zhongnan sag in the Ordos Basin, Jimusar sag in the Junggar Basin and Qingxi sag in the Jiuquan Basin as study objects, based on field survey, dissection of tight oil reservoirs, sample test, modeling experiment and comprehensive analysis, this study reveals that the tight oil accumulates at start-up pressure, advances under differential pressure, diffuses at alternating fast and low speeds, charges in stepped large area and migrates rapidly through fractures, and enriches in dominant fractures and pores. The root cause of ladder-like charge is the multiple scales of pores. The widespread source rock with high hydrocarbon generation intensity is the material basis for tight oil enrichment; the dominant source reservoir assemblage is the basic unit for tight oil enrichment; fractures and beddings are conducive to local rapid migration of tight oil; fractures and pores work together to control the enrichment of tight oil. Two typical accumulation models of tight oil are established, namely “source reservoir in coexistence, four optimal factors controlling enrichment around central area, and large-scale continuous distribution” for a large freshwater lake clastic rock basin and “source reservoir integration, four optimal factors controlling enrichment, central area distribution, small in size but high in enrichment degree “ for a small saline lake diamictite depression.

In view of the difficult problems encountered in the development of tight oil reservoirs, using natural gas as an energy supplementary agent and adopting Huff-N-Puff (HNP) production methods have shown great application potential in the development of such reservoirs. In this study, we took the Chang-7 tight oil cores as the research object. Then, we choose natural gas (methane or the associated gas) as the injection agent and used an experimental simulation device to perform natural gas Huff-N-Puff experiment in tight cores. Finally, we analyzed the factors that affect the enhanced oil recovery factor through parallel comparative experiments. The results show that the natural gas HNP development method can effectively increase oil production based on primary depletion production, and its effective production periods were concentrated in the 1st and 2nd rounds. The flooding mechanism of natural gas HNP process focuses on interfacial aggregation and interfacial slippage of crude oil, which are conducive to enhance oil production. Moreover, when the gas agent was CH4, it was not necessary to reserve too long soaking time during CH4 HNP process; when the gas agent was associated gas, a longer soaking time could be appropriately reserved. Additionally, the higher pressure CH4 injection would aggravate asphaltene precipitation, which will hinder migration of oil and gas in the pore throat of tight cores. Besides, we established the corresponding numerical model via using CMG software. Generally, the CH4 HNP process with higher gas injection pressure had higher oil recovery. However, the ultimate oil recovery under 30 MPa gas injection pressure was lower than that under 28 MPa gas injection pressure. Therefore, the appropriate gas injection pressure should be selected in accordance with reservoir conditions during CH4 HNP process, making its benefits overweigh its harms.

Accurate modeling of the distribution of induced fractures and pre-existing natural ones in unconventional reservoirs is essential for the analysis of the productivity of horizontal wells after fracturing. A novel approach is proposed here to establish a three-dimensional geological model of induced fractures, natural fractures and the horizontal well using a discrete random distribution method, based on micro-seismic data and natural fracture properties from the S oilfield. Taking the stress sensitivity into consideration, a coupled model calculating the fluid flow in the horizontal wellbore, the reservoir matrix and fractures were established to simulate the productivity of the S oilfield. This model was calibrated by the production data in the S oilfield, and the productivity of horizontal well under different natural fracture intensities, hydraulic fracture spacing and lengths was analyzed. The results show that the area without stimulation in the tight oil reservoir can rarely be exploited. The fluid pressure in the horizontal wellbore cannot be treated as uniform, especially when the production pressure keeps decreasing; otherwise, the cumulative production will be larger than the actual one. Increasing the hydraulic fracture length and natural fracture intensity and decreasing the fracture spacing are all beneficial to the daily and cumulative oil production. However, these methods accelerate the decline of the daily production. The production decline rate with higher natural fracture intensity was about 4 times that of lower natural fracture intensity. The natural fracture intensity and the fracture spacing are factors that are more influential to the productivity compared to the fracture length.

By using the latest geological, seismic, drilling and logging data, this article studies the basic conditions for the formation of the total petroleum system and the orderly coexisting characteristics and accumulation models of conventional & unconventional reservoirs in the Lower Permian Fengcheng Formation in the Junggar Basin. Controlled by thermal evolution, hydrocarbon generation and expulsion process of the high-quality source rocks in alkaline lake as well as the characteristics of multi-type reservoirs (conglomerate, sandstone, dolomite and shale), conventional structure-lithologic reservoirs and tight oil and shale oil reservoirs controlled by source-reservoir structure have been formed. On the plane, mature conventional reservoirs, medium-high mature tight oil, and medium-high mature shale oil reservoirs coexist orderly from the slope area around Mahu sag to the sag. Based on the orderly coexisting characteristics of conventional and unconventional reservoirs in the Fengcheng Formation, it is clear that oil and gas in the Fengcheng Formation accumulate continuously over a large area in three accumulation models: integrated source-reservoir, source-reservoir in close contact, and separated source-reservoir model. The three accumulation models differ in relationship between source-reservoir structure, reservoir lithology and spatial distribution, hydrocarbon migration, oil and gas type. It is pointed out that the conventional & unconventional oil and gas should be explored and developed as a whole to achieve an overall breakthrough of the total petroleum system. This study is expected to enrich the geological theory of oil and gas enrichment in continental basins and to provide an analogy for exploration and research in other hydrocarbon-rich sags.

The Lower Cretaceous Xiagou Formation is an important tight oil reservoir in the Qingxi Depression of the Jiuxi Basin. The micro-nanopore system within the reservoir requires a comprehensive analysis to improve the production of tight oil there. Nuclear magnetic resonance (NMR) experiments have been widely used for the petrophysical characterization of sandstones and carbonates. In the present study, the NMR experiment was applied to obtain the characteristics of the micro-nanopore system and permeability in the Lower Cretaceous Xiagou pelitic dolomite reservoir. According to the distribution shape of the transversal relaxation time (T2) obtained under the 100% water-saturated condition (Sw), the samples are divided into four groups: (i) group I, two obvious peaks (P1 and P2); (ii) group II, an obvious high peak of P1 at 0.1˜1.0 ms and a relatively low peak of P2; (iii) group III, an obvious high peak of P2 and a relatively low peak of P1; and (iv) group IV, three peaks. In general, the distribution shape of T2 under the initial condition (Sini) is unimodal, with all its peaks lower than those under the Sw condition. The NMR T2 spectrum reflects the distribution of the rock pore radius. Most of the pore radius distributions are bimodal, and the main pore radius ranges from 10 nm to 70 nm. Three patterns can be identified and determined based on the distribution of the pore radius: I—unimodal distribution, II—bimodal distribution and III—trimodal distribution. The results indicate that the porosity in the Xiagou reservoir ranges from 1.17% to 6.89%, with an average of 3.33%. The permeability ranges from 0.03×10−3 μm2 to 22.56×10−3 μm2, with an average of 2.95×10−3 μm2.

A nanoscale pore throat system develops extensively in rocks of unconventional reservoirs serving as both source and reservoir rock. The nanoscale pores provide the main storage spaces, accounting for 70% to 80% of the total unconventional tight reservoirs in China. As one of most important unconventional petroleum accumulations, tight oil has accumulated in more than 20 lacustrine strata since the Permian in China. Three types of tight oil reservoirs were identified based on the lithology and provenance in the lacustrine basins, including terrigenous sandstone, endogenous carbonate rocks and mixed sedimentary rocks. The micro/nanopore structures of these tight rocks were investigated with the application of optical microscopy, scanning electron microscopy (SEM), mercury injection capillary pressure (MICP), gas adsorption (GA) and nuclear magnetic resonance (NMR). The results indicated that the pore systems were connected by nanoscale throats dominated the storage spaces of the lacustrine tight oil reservoirs, while there were obvious differences among these three tight rocks, including pore types, pore size and movable fluid distribution. (i) The terrigenous sandstones, which were represented by the Triassic Chang 7 tight sandstones in the Ordos Basin and Cretaceous Quantou tight sandstones in the Songliao Basin, were mainly arkoses, and their storage space was mainly composed of dissolution pores and intraclay mineral pores. Feldspar, rock fragments and carbonate cements were the majority of the dissolved components, and the diameter of dissolution pores ranged from 1 micron to 50 microns. Abundant intrakaolinite and illite/smectite mixed layers pores were developed, and the pore size was 10 nm to 500 nm. The MICP and GA data suggested that storage spaces were connected by throats with diameters of 10 nm˜300 nm. (ii) The endogenous carbonate rocks, which were represented by the Jurassic Da’anzhai limestones in the Sichuan Basin, were the tightest rocks with porosities of less than 5% and permeabilities of less than 0.01×10−3 μm2. The calcite dissolution pores and fractures with diameters of 10 nm˜500 nm were the most important storage spaces. The majority of pore systems were connected by throats with diameters of 6 nm˜100 nm based on the MICP and GA data. (iii) The tight mixed sedimentary rocks, which were represented by the Permian Lucaogou Formation in the Junggar Basin, were complex in lithologic composition, and dolostones and dolomite sandstones were the most important exploration targets. The interdolomite pores were the dominant storage spaces, in which abundant illite/smectite mixed layers were filled, and the pore size ranged from 50 nm to 50 microns. The MICP and GA data showed that the storage space was dominated by throats with diameters of 10 nm˜200 nm, and their volumetric contributions could reach over 70%. These results could provide a reference for future tight oil research and exploration in China.

Hydraulic fracturing and acidification are among the most commonly used methods for stimulating the tight oil reservoirs and improving oil recovery. Therefore, examining the effects of water immersion and acidification on tight oil reservoirs is important for oilfield development plans. Core flooding testing, which analyzes the influence of core permeability variations before and after acid injection on the reservoir quality, is the conventional research method; however, it is difficult to observe the changes in minerals and pores caused by acidulation and water immersion in situ. In this study, we conduct field-emission scanning electron microscopy (FE-SEM), MAPS, the quantitative evaluation of minerals through scanning electronic microscopy (QEM-SCAN), and describe the types of pores in tight sandstone. Further, the effects of water immersion and acidification on pores in tight sandstone were studied. The results indicate that: (1) intergranular pores, intragranular dissolution pores, clay mineral intercrystalline pores, and micro-cracks were developed in the Gaotaizi tight sandstone in Songliao Basin, with the intergranular pores observed to be dominant; (2) the hydration of clay minerals induced by water injection caused plugging of pores at the nanometer– micrometer scale, and plane porosity is slightly reduced (˜0.86%); (3) acidification resulted in the dissolution of carbonate minerals, increasing the porosity of the reservoir, therefore, the increase in porosity is influenced by the carbonate mineral content. We recommend that future studies should investigate the content, type, and distribution of carbonate minerals in the operation area. During the process of reservoir stimulation, such as acidification and CO2 injection- and-production, the influence of carbonate minerals dissolution on oil production should be considered.

A series of theoretical explorations and field tests have been carried out to efficiently develop the Mahu tight conglomerate oilfield in the Junggar Basin. Concepts of steered-by-edge fracturing and proactive fracturing interference were proposed. A series of innovative technologies were developed and implemented including optimization of 3-D staggered well pattern, proactive control and utilization of spatial stress field, and synergetic integration of multiple elements. Different from shale, the unique rock fabric and strong heterogeneities of tight conglomerate formation are favorable factors for forming complex fractures, small space well pattern can proactively control and make use of interwell interference to increase the complexity of fracture network, and the “optimum-size and distribution” hydraulic fracturing can be achieved through synergetic optimization. During pilot phase of this field, both depletion with hydraulically fractured vertical wells and volume fracturing in horizontal wells were tested after water injection through vertical wells, then the multi-stage fracturing with horizontal well was taken as the primary development technology. A series of engineering methods were tested, and key development parameters were evaluated such as well spacing, lateral length, fractures spacing, fracturing size, and fracturing operation process. According to geoengineering approach, the 100 m/150 m tridimensional tight-spacing staggered development method was established with systematic integration of big well clusters, multiple stacked pay zones, small well spacing, long lateral length, fine perforation clustering, zipper fracturing and factory operation. According to half-year production performance, 100 m/150 m small spacing wells outperformed 500 m/400 m/300 m spacing wells. Its average estimated ultimate recovery (EUR) of wells was identical with those best wells from large-spacing area. Compared with the overall performance of Mahu oilfield, the drainage efficiency and estimated recovery factor of this pilot were significantly boosted with improved economics.

This study applied vacuum-impregnated casting thin sections, fluorescence slices, scanning electron microscopy (SEM), pressure-controlled mercury porosimetry (PCP), rate-controlled mercury porosimetry (RCP), X-ray diffraction of clay minerals, overburden pressure, and conventional physical property strategies to determine the microscopic characteristics of the Chang 6 member, a typical tight sandstone reservoir in the Jingbian oilfield in the Ordos Basin, China. We also analyzed the controlling effects of pore structure on reservoir quality and oiliness. The results showed that the pore types of the Chang 6 sandstone reservoir can be divided into four categories: residual intergranular pores, dissolution pores, intercrystalline pores between clay minerals, and microfractures. The pore size of the Chang 6 sandstone reservoir ranged from 20 to 50 μm. We employed PCP and RCP strategies to characterize the pore structure of the Chang 6 reservoir. The pore radius was less than 2 μm, and on average, the throat radius was less than 0.3 μm. The reservoir physical properties were affected by diagenesis, particularly compaction, and the average porosity failure rate was 56.3%. Cementation made the reservoir more compact, dissolution improved the physical properties of the reservoir locally, and fracturing effectively improved the reservoir seepage ability; however, its influence on porosity was limited. The pore structure controlled the quality of the reservoir. The physical properties of the reservoir were closely related to the oil-bearing properties. The lower limits of porosity and permeability of industrial oil flow in the reservoir were 7.5% and 0.15 mD, respectively. These results provide an additional resource for the exploration and development of tight oil in the Ordos Basin.

It is important to determine the reasonable injection and production rates in the development of multilayer tight oil reservoir with water flooding treatment. Based on the INSIM (interconnection-based numeric simulation model), a connected network model, a new method is designed to evaluate the water injection efficiency of different layers in water flooding reservoirs and to optimize the injection-production system to produce more oil. Based on the types of sedimentary facies and corresponding injection-production data, the interwell connections are divided into four major categories (middle channel, channel edge, middle channel bar, and channel bar edge) and twelve subclasses. This classification standard of interwell connections could help to significantly improve the accuracy of judging the dominant flow path without constructing a complicated geological model. The interaction of interwells such as injection-production correlation and water injection efficiency could be revealed by simulating the production performance and computing the layer dividing coefficient and well dividing coefficient. A numerical example is used to validate this method by comparing results from FrontSim and this method, and the computational efficiency of this method is several dozen times faster than that of the traditional numerical simulation. This method is applied to quickly optimize the production schedule of a tight oil reservoir with the water flooding treatment, that is, the water injection rate of multilayer reservoirs could be optimized subtly by the injection efficiency of different layers, and the target of producing more oil with lower water cut could be achieved.

The tight lacustrine carbonate reservoir of the Da’anzhai Member, Lower Jurassic Ziliujing Formation, in the central Sichuan Basin is a typical tight oil reservoir, and it is one of the crucial petroleum exploration targets in the Sichuan Basin. The porosity of the limestone ranges from 0.5% to 2%, and the permeability ranges from 0.001 to 1 mD. The Da’anzhai limestone experienced multiple diageneses, including compaction, cementation, dissolution, and recrystallization. Different diageneses occurred in the burial process due to the various fabrics and depositional environments, eventually forming distinct rock types; therefore, the pore evolution and hydrocarbon charging characteristics are inconsistent. In our research, there are two stages of major maturation and hydrocarbon expulsion in the source rocks of the Da’anzhai Member. The first large-scale expulsion of hydrocarbon is oil-based and gas-supplemented, whereas the second expulsion is dominated by gas. Hydrocarbon-filling characteristics are different in different types of reservoir rocks. Compared with the bioclastic grainstone and crystalline limestone, we have considered that the argillaceous shell packstone and bioclastic packstone deposited in the shallow and semideep lake environment still contain residual intergranular pores, which have not become fully compacted and are partly filled with hydrocarbons. The presence of hydrocarbon fluid hindered the secondary porosity reduction and was helpful for reserve space preservation.

The significance of source rocks for oil and gas accumulation has been indisputably acknowledged. Moreover, it has been gradually realized that there is difference between hydrocarbon generation capacity and hydrocarbon expulsion capacity, and this has prompted research on hydrocarbon expulsion efficiency. However, these studies dominantly highlight the results of hydrocarbon expulsion, and investigation into the corresponding process and mechanism is primarily from a macroscopic perspective. Despite its wide acceptance as the most direct hydrocarbon expulsion mode, hydrocarbon expulsion through micro-fractures is still not sufficiently understood. Therefore, this study obtains observations and performs experiments on two types of source rocks (mudstones and shales) of the Chang 7 oil group of the Yanchang Formation in Ordos Basin, China. Microscopy reveals that organic matter is non-uniformly distributed in both types of source rocks. Specifically, mudstones are characterized by a cluster-like organic matter distribution, whereas shales are characterized by a layered organic matter distribution. Thermal evolution simulation experiments demonstrate that the hydrocarbon generation process is accompanied by the emergence of micro-fractures, which are favorable for hydrocarbon expulsion. Moreover, based on the theories of rock physics and fracture mechanics, this study establishes micro-fracture development models for both types of source rocks, associated with the calculation of the fracture pressure that is needed for the initiation of fracture development. Furthermore, the relationship between the fluid pressure, fracture pressure, and micro-fracture expansion length during micro-fracture development is quantitatively explored, which helps identify the micro-fracture expansion length. The results indicate that the development of micro-fractures is commonly impacted by the morphology and distribution pattern of the organic matter as well as the mechanical properties of the source rocks. The micro-fractures in turn further affect the hydrocarbon expulsion capacity of the source rocks. The results of this study are expected to provide theoretical and practical guidance for the exploration and exploitation of tight oil and shale oil.

Horizontal wells have been used for water flooding operations for the purpose of pressure maintenance and improved oil recovery, e.g., in tight oil reservoirs. Injection profiling along the well lateral is required to determine the effectiveness of water flooding operations and to maintain high sweep efficiency. Recent improvements in downhole temperature monitoring tools allow monitoring the transient temperature along horizontal waterflooding wells at a relatively low cost. Temperature data can be analyzed to infer the injection profile along wellbore and locate high permeability regions that cause non-uniform rate distribution along the wellbore. In this work, an analytical model is developed to describe the transient temperature in the reservoir during cold fluid (water) injection via a horizontal well during injection and warmback periods. The analytical solution assumes linear flow in the reservoir and accounts for heat transfer by different mechanisms including convection, conduction, and heat gain from the surrounding impermeable strata. The inversion procedure is introduced to evaluate injection profiling using analytical solution–based type curves. Different cases are considered using a thermally coupled numerical reservoir simulator to verify the analytical approach and illustrate the potential application of the inversion technique. We show that the analytical approach introduced in this work is an efficient and robust technique to infer the injection profile along horizontal wells.

Ball-sealer in-stage diversion in horizontal wells is a key technique to realize the uniform stimulation of fractured sections in tight oil and gas reservoirs. So far, however, there are fewer research results on the propagation morphologies of multi-cluster fractures after the implementation of different ball-sealer in-stage diversion processes during the fracturing treatment, which results in less theoretical support for the preparation of field ball-sealer in-stage diversion process and measures and impacts its application effects in the fracturing field. To deal with this situation, this paper established a fully coupled “wellbore–perforation–fracture propagation” model of horizontal wells on the basis of the boundary element method. Then, a method for calculating the allocation of ball sealers was proposed. Finally, the number of ball sealers, diversion time and number of diversions during the intra-stage temporary plugging and diversion under the condition of initial heterogeneous stress field and their effects on the propagation of multi-cluster fractures were simulated. And the following research results were obtained. First, the flow restriction of perforation friction can counterbalance the intake difference caused by the induced stress interference so that the friction difference applied on the fluid flow in each fracture cluster is reduced. Second, when the effect of the heterogeneous distribution of the initial stress field is taken into consideration, the liquid intake of each fracture cluster changes greatly and even ineffective perforation clusters without liquid incoming appear in the high-stress region. And after the ball is injected, new fractures are initiated from the ineffective perforation clusters. Third, when the initial minimum horizontal principal stress difference (Δσh) is higher than 3 MPa, it is beneficial to reduce the non-uniform propagation of each fracture cluster by increasing the number of ball sealers appropriately in the middle stage of the construction (over half of the total perforations of each stage) or carrying out temporary plugging in the early–middle stage (including ball injection in batches in the early–middle stage). Fourth, when Δσh is lower than 2 MPa, it is necessary to reduce the number of ball sealers or inject balls in the middle–late stage, or the non-uniform propagation of each fracture cluster will be aggravated.

Carbonate cementation is one of the significant tightness factors in Chang 6 reservoir of the western Jiyuan (WJY) area. Based on the observation of core and thin sections, connecting-well profile analysis as well as carbon and oxygen isotope analysis, it is found that ferrocalcite is the main carbonate cements in the Chang 6 reservoir of the WJY area. The single sand body controls the development of carbonate cements macroscopically. Both carbonate cements and calcite veins hold similar diagenetic conditions: the dissolution of plagioclase is the main calcium source and the de-acidification of organic acids is the main carbon source. The diagenetic stage is identified as the mesogenetic A stage. The sedimentary environment is of low salinity. Accordingly, the development model of carbonate cementation in Chang 6 reservoir is summarized into three types: “eggshell pattern,” “cutting pattern,” and “favorable reservoir pattern.” The development degree of carbonate cementation affects the physical properties of reservoir.

With the exploration of tight oil and gas, shallow-water deltaic reservoirs have been attracting more and more attention. The sedimentary architecture of a shallow-water delta shows distinctive differences with that of a deep-slope delta. These differences may be associated with the mechanism and characteristics of the deposition in the area where the sediments unloaded. Based on modern sedimentary research of the Poyang Lake in China, this paper focuses on the processes of river flow entering a lake with a low dip angle. We conducted six sets of numerical simulations with different initial sedimentary flow velocities using Fluent software for analyzing the hydrodynamics and the sediment transportation in the shallow-water delta. We combined the simulation results with an analysis of the geomorphology of the Gangjiang Delta to reveal the deposition along the shoreline of the lacustrine shallow-water delta. The numerical simulation shows that the shallow-water delta is dominated by bed friction with an extensive hydrodynamical boundary layer. The bed shear stress, which varies with the changes in river flux, dominated the sediment transport and deposition at the shallow-water delta front, where the effluent flow mixes with lake water. The distributary channels show characteristics of repeatedly occurred erosion, scouring, filling, and reoccupation. We argue that the depositional characteristics are associated with the changes in bed shear stress controlled by variation of flow velocity. Mouth bars are less likely to grow to a reasonable scale because of the seasonal scouring of extreme floods. Moreover, the lake flow potentially reworks the mouth bars. Consequently, mouth bar deposits were difficult to preserve as hydrocarbon reservoirs in ancient shallow-water delta.

Tight oil reservoir development is faced with the key technical problem that “water cannot be injected and oil cannot be produced” yet. With the diphenyl ethers water-soluble (gemini) surfactants as water phase shell and C10–C14 straight-chain hydrocarbon compounds as oil phase kernel, a nanofluids permeation flooding system was prepared by microemulsion technology, and its characteristics and EOR mechanisms were evaluated through experiments. The system has the following five characteristics: (1) “Small-size liquid”: the average particle size of the system is less than 30 nm, which can greatly reduce the starting pressure gradient of water injection, and effectively enter and expand the sweep volume of micro-nano matrix; (2) “Small-size oil” : the system can break the crude oil into “small-size oil” under the flow condition, which can greatly improve the percolation ability and displacement efficiency of the crude oil in the micro-nano matrix; (3) Dual-phase wetting: the system has contact angles with the water-wet and oil-wet interfaces of (46±1)° and (68±1)° respectively, and makes it possible for capillarity to work fully under complex wetting conditions of the reservoir; (4) High surface activity: the interfacial tension between the system and crude oil from a tight oil reservoir in Xinjiang is 10−3–10−2 mN/m, indicating the system can effectively improve the displacement efficiency of oil in fine pore throats; (5) Demulsification and viscosity reduction: the system has a demulsification and viscosity reduction rate of more than 80% to inversely emulsified crude oil from a tight oil reservoir in Xinjiang, so it can improve the mobility of crude oil in the reservoir and wellbore. The system can be used to increase oil production by fracturing in tight reservoirs, replenish formation energy by reducing injection pressure and increasing injection rate, and enhance oil recovery by displacement and cyclic injection, providing key technical support for effective production and efficient development and recovery enhancement of tight reservoirs.

Tight oil reservoirs are complex geological materials composed of solid matrix, pore structure, and mixed multiple phases of fluids, particularly for oil reservoirs suffering from high content of in situ pressurized water found in China. In this regard, a coupled model considering two-phase flow of oil and water, as well as deformation and damage evolution of porous media, is proposed and validated using associated results, including the oil depletion process, analytical solution of stress shadow effect, and physical experiments on multi-fracture interactions and fracture propagation in unsaturated seepage fields. Then, the proposed model is used to study the behavior of multi-fracture interactions in an unsaturated reservoir in presence of water and oil. The results show that conspicuous interactions exist among multiple induced fractures. Interaction behavior varies from extracted geological profiles of the reservoir due to in situ stress anisotropy. The differential pressures of water and that of oil in different regions of reservoir affect interactions and trajectories of multi-fractures to a considerable degree. The absolute value of reservoir average pressure is a dominant factor affecting fracture interactions and in favor of enhancing fracture network complexity. In addition, difference of reservoir average pressures in different regions of reservoir would promote the fracturing effectiveness. Factors affecting fracture interactions and reservoir treatment effectiveness are quantitatively estimated through stimulated reservoir area. This study confirms the significance of incorporating the two-phase flow process in analyses of multi-fracture interactions and fracture trajectory predictions during tight sandstone oil reservoir developments.

Capillary force and boundary layer effect are the main causes of non-Darcy flow in tight oil reservoir. This paper proposes a non-Darcy flow dynamics characterization method for low-speed water flooding in tight oil reservoirs. It applies constant-speed mercury injection and casting thin section experiments to quantitatively characterize the micro-pore throat structure parameters, and uses the visual experimental device to measure the boundary layer thickness and fit the expression of the relationship between boundary layer thickness and displacement pressure gradient and fluid viscosity. The results show that the ratio of boundary layer thickness to microtubule radius changes exponentially with the pressure gradient and fluid viscosity and that the boundary layer thickness decreases gradually with the increase of pressure gradient. Given the capillary force and boundary layer thickness, the flow rate of single capillary is calculated. On this basis, the equation of nonlinear seepage dynamic characteristics per unit area of core is derived by taking into account the throat distribution frequency and throat size characteristics. The new seepage flow model can reflect the nonlinear seepage flow law of tight oil reservoir and provide reference for parameter formulation during water flooding development of tight oil reservoir.

The Woodford–Mississippian “Commingled Production” is a prolific unconventional hydrocarbon play in Oklahoma, USA. The tight reservoirs feature variations in produced fluid chemistry usually explained by different possible source rocks. Such chemical variations are regularly obtained from bulk, molecular, and isotopic characteristics. In this study, we present a new geochemical investigation of gasoline range hydrocarbons, biomarkers, and diamondoids in oils from Mississippian carbonate and Woodford Shale. A set of oil/condensate samples were examined using high-performance gas chromatography and mass spectrometry. The result of the condensates from the Anadarko Basin shows a distinct geochemical fingerprint reflected in light hydrocarbon characterized by heptane star diagrams, convinced by biomarker characteristics and diamantane isomeric distributions. Two possible source rocks were identified, the Woodford Shale and Mississippian mudrocks, with a variable degree of mixing. Thermal maturity based on light hydrocarbon parameters indicates that condensates from the Anadarko Basin are of the highest maturity, followed by “Old” Woodford-sourced oils and central Oklahoma tight oils. These geochemical parameters shed light on petroleum migration within Devonian–Mississippian petroleum systems and mitigate geological risk in exploring and developing petroleum reservoirs.

To deal with the stress interference caused by simultaneous propagation of multiple fractures and the wettability reversal and physical property changes of the reservoir caused by fracturing fluid getting in during large-volume fracturing of tight oil reservoirs through a horizontal well, a non-planar 3D fracture growth model was built, wettability reversal characterizing parameters and change of relative permeability curve were introduced to correct the production prediction model of fractured horizontal well, a fracturing design optimization software (FrSmart) by integrating geological and engineering data was developed, and a fracturing design optimization approach for tight oil reservoirs based on fracture control was worked out. The adaptability of the method was analyzed and the fracture parameters of horizontal wells in tight oil reservoirs were optimized. The simulation results show that fracturing technology based on fracture control is suitable for tight oil reservoirs, and by optimizing fracture parameters, this technology makes it possible to produce the maximum amount of reserves in the well-controlled unit of unconventional reservoirs. The key points of fracturing design optimization based on fracture control include increasing lateral length of and reducing the row spacing between horizontal wells, increasing perforation clusters in one stage to decrease the spacing of neighboring fractures, and also avoiding interference of old and new fracturing wells. Field tests show that this technology can increase single well production and ultimate recovery. Using this technology in developing unconventional resources such as tight oil reservoirs in China will enhance the economics significantly.

Studying hydrocarbon charging is quite important for searching exploration targets and confirming well locations. In this paper, the north slope of the Minfeng sub-sag in the Bohai Bay Basin was taken as an example. The Wells Yanxie 233, Yongxie 932 and Yan 22 were selected for on-site carbon isotope detection. Then, based on sufficient carbon isotope data which were acquired on the drilling site using the brand-new carbon isotopic measuring instrument, the carbon isotope data and composition data of natural gas produced in this area were compared. And combined with the evolution of source rocks, the geochemical characteristics of crude oil, the depositional environment of reservoirs and the physical properties, single-well charging characteristics and regional charging area of natural gas were analyzed. Finally, the feasibility of on-site carbon isotope detection method to discriminate hydrocarbon charging was discussed. And the following research results were obtained. First, deep hydrocarbon charging happened in the Purely Purely Lower Sha 4 Member in Well Yanxie 233, and its natural gas is the mixture of the oil cracking gas of deep layers and the thermal cracking gas of autochthonous source rocks. Second, the natural gas in the third and fourth Members of Shahejie Formation in Well Yongxie 932 is the thermal cracking gas of autochthonous source rocks, but deep gas charging occurred in particular hole sections. Third, the carbon isotope of associated gas in Well block Yan 22 is high in the central area and low in both sides and high in the south and low in the north, which is accordant with the distribution characteristics of reservoir physical properties, indicating that the charging of high-maturity natural gas is under the control of reservoir physical properties. Fourth, the oil in Well block Yan 22 is the product of autochthonous source rocks in the mature stage while the natural gas is the autochthonous oil-associated gas combined with the charging of deep high-maturity product. It is concluded that there is a high-maturity hydrocarbon charging area in the northwest of the northern slope of the Minfeng sub-sag, and it is a favorable hydrocarbon exploration target. What's more, the on-site carbon isotope rapid detection technology can provide a large number of continuous three-dimensional carbon isotope data, and it can be used to quickly analyze the characteristics of hydrocarbon charging and determine the source and origin of hydrocarbon, so as to provide reference for hydrocarbon development deployment.

Experimental works have proved that imbibition under forced pressure (FP, the difference between hydraulic fluid pressure and original pore pressure) has a positive effect on fossil hydrogen energy development in tight oil reservoir. However, the knowledge of the influence of imbibition under forced pressure (forced imbibition, FI) on fracturing fluid flowback and water retention is still limited. In this paper, experiments were designed and conducted to reveal the mechanism of fracturing fluid flowback and water retention under imbibition effect in tight sandstones. As a comparison, unconsolidated sandstones were also investigated in this study. Core samples were divided into two categories: the imbibition ones (treated by imbibition) and the filtration ones (treated by displacement), in accordance with the real oil-water distribution after well shut-in. An imbibition core and a filtration core were stitched together to conduct a flowback experiment. During the experiment, fluid distribution in different pore sizes was monitored continuously by using a low-field nuclear magnetic resonance device. Results show that the flowback recovery in tight sandstones is much lower than that in unconsolidated sandstones due to the difference of pore structure. Meanwhile, forced imbibition leads to higher oil recovery than spontaneous imbibition (SI) in tight sandstones since forced pressure enhances water imbibition. The water imbibed into small-macro and macro pores contributes the major flowback recovery, but the imbibed water in micro pores is rather difficult to displace and finally retains in these pores during the flowback process. Overall, forced imbibition not only enhances oil recovery but also increases water retention, explaining the mechanism of well productivity increase by using the shut-in method in the field. This study can help to clarify the influence of forced imbibition on fracturing fluid flowback and enhancement of fossil hydrogen development, and further provide guidance for flowback designs.

In order to study the geochemical characteristics of fine-grained sedimentary rocks and clarify its relationship with the tight oil reservoir, the Chang7 Member of Triassic Yanchang Formation in Longdong area was taken as an example to be studied by rock pyrolysis, isotopic determination, maceral analysis, gas chromatography and gas chromatography–mass spectrometry. Lacustrine organic-rich fine-grained sedimentary rocks can be divided into organic-rich shale and organic-rich mudstone according to their lithology and texture. The results show that the organic-rich shale was deposited in a quiet and anoxic deep lacustrine environment, the organic matter was of high abundance and mainly sourced from plankton and benthic algae (type I–II1). Organic-rich mudstone mainly deposited in the semi-deep lacustrine environment, where the water was relatively shallow and the salinity was low, the organic matter was of low abundance and came from the mixed source of plankton and terrestrial clastic (type II1–II2). The Chang7 tight oil is widely distributed in the turbidite sand bodies, and it was mainly sourced from the Chang7 organic-rich shale.

Relative permeability (kr) and the capillary pressure (Pc) are the central key elements defining the multiphase fluids flow behavior in the porous media. However, the dynamic capillarity should consider the dynamic relative permeability and the dynamic capillary pressure while performing waterflooding process in extremely low permeable formations. In order to improve the oil production, the advanced horizontal well drilling along with multiple hydraulic fracturing is generally instigated to penetrate the unconventional resources. The aim of this study is to consider the dynamic capillarity in a commercial reservoir simulation, while utilizing the data gained from the dynamic and steady experiments of the relative permeability and the capillary pressure impacts during waterflooding process in the core plugs of unconventional tight oil reservoirs. The commercial reservoir simulation conducted sensitivity analyses using Computer Modeling Group simulator. The outcomes show that the well production of the reservoir is overestimated while implementing steady data for forecasting due to which the oil saturation decreases more equally and further rapidly. Additionally, the forecast of the well production estimated to breakthrough sooner. However, neglecting the dynamic capillarity causes a huge breakthrough of water influx. Therefore, the core objective of this study is to probe the consequences of taking into consideration the dynamic capillarity in ultra-low permeable formations while giving an alternative perspective to forecast the production of the hydraulically fractured unconventional tight oil reservoirs.

Tight oil siltstones are rocks with complex structure at pore scale and are characterized by low porosity and low permeability at macroscale. The production of tight oil siltstone reservoirs can be increased by hydraulic fracturing. For optimal fracking results, it is desirable to map the ability to fracture based on seismic data prior to fracturing. Brittleness is currently thought to be a key parameter for evaluating the ability to fracture. To link seismic information to the brittleness distribution, a rock physics model is required. Currently, there exists no commonly accepted rock physics model for tight oil siltstones. Based on the observed correlation between porosity and mineral composition and known microstructure of tight oil siltstone in Daqing oilfield of Songliao basin, we develop a rock physics model by combining the Voigt–Reuss–Hill average, self‐consistent approximation and differential effective medium theory. This rock physics model allows us to explore the dependence of the brittleness on porosity, mineral composition, microcrack volume fraction and microcrack aspect ratio. The results show that, as quartz content increases and feldspar content decreases, Young's modulus tends to increase and Poisson ratio decreases. This is taken as a signature of higher brittleness. Using well log data and seismic inversion results, we demonstrate the versatility of the rock physics template for brittleness prediction.

Continental shale oil has two types, low-medium maturity and medium-high maturity, and they are different in terms of resource environment, potential, production methods and technologies, and industrial evaluation criteria. In addition, continental shale oil is different from the shale oil and tight oil in the United States. Scientific definition of connotations of these resource types is of great significance for promoting the exploration of continental shale oil from “outside source” into “inside source” and making it a strategic replacement resource in the future. The connotations of low-medium maturity and medium-high maturity continental shale oils are made clear in this study. The former refers to the liquid hydrocarbons and multiple organic matter buried in the continental organic-rich shale strata with a burial depth deeper than 300 m and a Ro value less than 1.0%. The latter refers to the liquid hydrocarbons present in organic-rich shale intervals with a burial depth that in the “liquid window” range of the Tissot model and a Ro value greater than 1.0%. The geological characteristics, resource potential and economic evaluation criteria of different types of continental shale oil are systematically summarized. According to evaluation, the recoverable resources of in-situ conversion technology for shale oil with low-medium maturity in China is about (700–900)×108 t, and the economic recoverable resources under medium oil price condition ($ 60–65/bbl) is (150–200)×108 t. Shale oil with low-medium maturity guarantees the occurrence of the continental shale oil revolution. Pilot target areas should be optimized and core technical equipment should be developed according to the key parameters such as the cumulative production scale of well groups, the production scale, the preservation conditions, and the economics of exploitation. The geological resources of medium-high maturity shale oil are about 100×108 t, and the recoverable resources can to be determined after the daily production and cumulative production of a single well reach the economic threshold. Continental shale oil and tight oil are different in lithological combinations, facies distribution, and productivity evaluation criteria. The two can be independently distinguished and coexist according to different resource types. The determination of China's continental shale oil types, resources potentials, and tight oil boundary systems can provide a reference for the upcoming shale oil exploration and development practices and help the development of China's continental shale oil. Key words: shale oil, medium-high maturity, low-medium maturity, resource potential, tight oil, boundary, shale oil revolution

The selection of refracturing candidate is one of the most important jobs faced by oilfield engineers. However, due to the complicated multi-parameter relationships and their comprehensive influence, the selection of refracturing candidate is often very difficult. In this paper, a novel approach combining data analysis techniques and fuzzy clustering was proposed to select refracturing candidate. First, the analysis techniques were used to quantitatively calculate the weight coefficient and determine the key factors. Then, the idealized refracturing well was established by considering the main factors. Fuzzy clustering was applied to evaluate refracturing potential. Finally, reservoirs numerical simulation was used to further evaluate reservoirs energy and material basis of the optimum refracturing candidates. The hybrid method has been successfully applied to a tight oil reservoir in China. The average steady production was 15.8 t/d after refracturing treatment, increasing significantly compared with previous status. The research results can guide the development of tight oil and gas reservoirs effectively.

The secondary migration mechanism, enrichment factors of Jurassic tight oil in central Sichuan Basin were well investigated through physical simulation experiment of reservoir formation, casting and fluorescent thin sections, field emission scanning electron microscope (FESEM) and environment scanning electron microscope (ESEM). The results show that migration of Jurassic tight oil in central Sichuan Basin is a low-velocity non-Darcy flow through low-efficient migration path under the huge migration driving force, and has three migration and seepage stages, i.e. viscous flow stage, nonlinear seepage stage, and quasi-liner seepage stage. Microscopically, the migration pathway of tight oil is the pore-fracture composite conduction; macroscopically, the migration mode of tight oil is the large-scale short–distance migration. Distribution of favorable zones of tight oil is controlled by distribution of high-quality source rocks. The hydrocarbon-generation strength of 0.4 × 106 t/km2 can be as a threshold to determine favorable zone of tight oil in the study area. The reservoirs with high permeability and high porosity can form tight oil sweet spots, and the development degree of fractures is closely related to well with high yield of tight oil well. Keywords: Migration pathway, Migration driving force, Non-Darcy seepage, Pore-fracture composite conduction, Tight oil sweep spot, Jurassic tight oil, Central Sichuan Basin

Continental tight oil is a promising unconventional resource found in recent years and an important supplement to the growth of domestic petroleum reserves and production in China. Guided by the research objectives set by the China National Science and Technology Major Project “Enrichment Law and Key Technologies of Exploration and Development of Tight Oil,” and based on laboratory experiments and field tests by eight PetroChina petroleum companies, three signs of progress in theoretical technology and practical exploration and development have been made to continental tight oil in China. (1) Forming conditions: It is found that laminated organic-rich shale is primary source rock. Furthermore, many types of favorable reservoirs, such as terrigenous clasts and internal clasts, are developed and accumulate into two kinds of large-scale and continuous distribution of in-source and near-source assemblages. (2) Enrichment Law: Favorable reservoir facies zones, being near the hydrocarbon source center, and having a supportive tectonic background are three common factors controlling oil enrichment and high production. The proven tight oil resources are 10.65 × 109 t, whereas 40 enrichment zones have been identified and a number of drillable “sweet sections” have been found. (3) Key technologies of exploration and development: Key technologies have been developed involving multi-scale tight reservoir characterization, resource classification evaluation, seismic response and engineering evaluation of “sweet sections,” as well as reservoir stimulation and effective development. The research results support the rapid continental tight oil in China. By the end of 2018, proven tight oil geological reserves were 437 × 106t, while proved, controlled and predicted reserves were 3.019 × 109t, and the new production capacity was 3.31 × 106t. It is suggested that follow-up studies should focus on three fields—clastic rocks, peperite-sedimentary tuff, and lacustrine carbonate rocks. The above should be done in five aspects – enrichment law, sweet area evaluation and prediction, key development technology, efficient reservoir stimulation, and practical application in key basins so as to support steady integration of geology and engineering for developing continental tight oil in China. Keywords: Continental strata, Tight oil, Sweet section, Exploring oil inside source kitchen, Enrichment law, Key technology, Unconventional oil

Through reviewing the development history of tight oil and gas in China, summarizing theoretical understandings in exploration and development, and comparing the geological conditions and development technologies objectively in China and the United States, we clarified the progress and stage of tight oil and gas exploration and development in China, and envisaged the future development orientation of theory and technology, process methods and development policy. In nearly a decade, relying on the exploration and development practice, science and technology research and management innovation, huge breakthroughs have been made. The laws of formation, distribution and accumulation of tight oil and gas have been researched, the development theories such as “multi-stage pressure drop” and “man-made reservoirs” have been established, and several technology series have been innovated and integrated. These technology series include enrichment regions selection, well pattern deployment, single well production and recovery factor enhancement, and low cost development. As a result, both of reserves and production of tight oil and gas increase rapidly. However, limited by the sedimentary environment and tectonic background, compared with North America, China's tight oil and gas reservoirs are worse in continuity, more difficult to develop and poorer in economic efficiency. Moreover, there are still some gaps in reservoir identification accuracy and stimulating technology between China and North America. In the future, Chinese oil and gas companies should further improve the resource evaluation method, tackle key technologies such as high-precision 3D seismic interpretation, man-made reservoir, and intelligent engineering, innovate theories and technologies to enhance single well production and recovery rate, and actively endeavor to get the finance and tax subsidy on tight oil and gas. Key words: tight oil and gas, development history, theoretical and technological advancement, man-made oil and gas reservoir, enhancing recovery factor, development orientation

Perthite is a special type of skeleton mineral in tight oil sandstone which cannot be ignored. However, few attention was paid to the secondary pores in perthite and their contributions in tight oil reservoir. This study reveals the perthite's significance in unconventional oil flow characterizes comprehensively and quantitativel by combining the Field Emission Scanning Electron Microscope (FE-SEM) with high resolution, Energy Dispersive Spectrometer (EDS) analysis, high precision image processing, comprehensive parameters construction and calculation. Typical perthite samples of Chang 7 tight oil reservoir of Ordos basin were selected for this study. Our results demonstrate that the growth of K-feldspar and Na-feldspar in perthite is complementary. The mixing process of the two types of stripes promotes each other rather than inhibiting each other. As to the development of secondary pores of perthite, there are clear differences in the area and number of pores, medium differences in the porosity, radius and perimeter, and small differences in other parameters. The more regular and uniform growth of Na-feldspar, the more likely the perthite is to form regular and normalized secondary pore. At least 56.7% of the secondary pore of perthite contributes to oil flow in the process of oil migration or development, and its scientific significance cannot be ignored. The conclusion could provide the geological basis for the effective development of the unconventional hydrocarbon reservoirs.

The exploration of unconventional oil and gas, especially the exploration process of tight oil, is closely related to the evolution of tight reservoirs and the accumulation process. In order to investigate the densification and accumulation process of the Fuyu tight oil reservoir in the Sanzhao depression, Songliao Basin, through the new understanding of reservoir petrological characteristics, diagenesis and diagenetic sequence are combined with a large number of inclusions: temperature measurement, spectral energy measurement, and single-well burial history analysis, and then contrastive analysis with current reservoir conditions. The results prove that diagenesis is dominated by compaction and cementation, and the restoration of paleoporosity shows that its porosity reduction rate reached 67% and the densification process started in the early Nenjiang Formation and was finalized at the end of the Nenjiang Formation. The accumulation of the Fuyu oil layer generally has the characteristics of two stages and multiple episodes, and the main accumulation period is the end of the Mingshui Formation. The end of the Nenjiang Formation, where the main body of the reservoir is densified, is just a prelude to the massive expulsion of hydrocarbons in the Songliao Basin, which makes the Fuyu oil layer have the characteristics of first compacting and then accumulating. Through the above analysis, it can be seen that the accumulation of oil and gas in the Fuyu oil layer, Sanzhao depression, is more dependent on the fault-dominated transport system. In addition, it is believed that tight oil accumulation should have the characteristics of short-distance oil enrichment around the fault, and the development area of fracture deserts near the fault sand body should be the key area for further exploration.

Tight-oil reservoirs have low porosity and permeability, with microcracks, high clay content, and a complex structure resulting in strong heterogeneities and poor connectivity. Thus, it is a challenge to characterize this type of reservoir with a single geophysical methodology. We propose a dual-porosity-clay parallel network to establish an electrical model and the Hashin-Shtrikman and differential effective medium equations to model the elastic properties. Using these two models, we compute the rock properties as a function of saturation, clay content, and total and microcrack porosities. Moreover, a 3D elastic-electrical template, based on resistivity, acoustic impedance, and Poisson’s ratio, is built. Well-log data is used to calibrate the template. We collect rock samples and log data (from two wells) from the Songliao Basin (China) and analyze their microstructures by scanning electron microscopy. Then, we study the effects of porosity and clay content on the elastic and electrical properties and obtain a good agreement between the predictions, log interpretation, and actual production reports.

Pore network modeling based on digital rock is employed to evaluate the mobility of shale oil in Qingshankou Formation, Songliao Basin, China. Computerized tomography technology is adopted in this work to reconstruct the digital rock of shale core. The pore network model is generated based on the computerized tomography data. We simulate the dynamics of fluid flow in a pore network model to evaluate the mobility of fluid in shale formation. The results show that the relative permeability of oil phase increases slowly in the initial stage of the displacement process, which is mainly caused by the poor continuity of the oil phase. In the later stages, with the increase in the oil phase continuity, the range of relative permeability increases. With the increase of organic matter content, the permeability of the water phase remains unchanged at low water saturation, but gradually increases at high water saturation. At the same time, it can be seen that, with the increase in organic matter content, the isosmotic point of the oil–water phase permeability shifts to the left, indicating that the wettability to water phase gradually weakens.

Mobility is the main factor restricting the production of tight oil. In order to explore the influence of pore throat structure and fluid seepage on the mobility, six tight sandstone samples are selected by high-pressure mercury intrusion, nuclear magnetic resonance, water driving oil experiments, and oil-water relative permeability experiments to discuss the influence of pore structure and multiphases on the mobility of tight oil. The results indicate that with the increase in effective porosity, more oil and water are exchanged, and the mobility of the oil phase is enhanced. The large pore is positively correlated with the mobility of tight oil while the relationship between the mobility of small pore and effective porosity remains unclear. Particularly, the mobility of the tight oil is determined by the matching relationship between the pore throat radius and the sorting of the tight reservoir. Specifically, the smaller the two-phase copermeation zone, the greater the bound water saturation; the greater the slope of the oil phase permeability curve, the less the space for the two phases to flow together; the more the oil blocked by water in the reservoir, the worse the phase mobility. The mobility of tight oil can be divided into four categories by pore throat radius, pore throat sorting coefficient, and bound water saturation.

The alkaline lake source rocks of the Fengcheng Formation are developed in the Mahu Sag of the Junggar Basin. Different from traditional continental fresh water and saltwater lake source rocks, alkaline lake source rocks lack targeted evaluation criteria, and it is unknown whether their hydrocarbon generation models are consistent with traditional models. Therefore, in the present study, evaluation standards and hydrocarbon generation models of alkaline lake source rocks are discussed based on geological and organic geochemical data and a systematic summary of the geochemical characteristics of the Fengcheng Formation source rocks. The Fengcheng Formation source rocks are mainly diamictite with mixed argillaceous rock and dolomite, most total organic carbon (TOC) values range from 0.2–1.4%, and the kerogen is primarily oil-prone type II, reaching low- to high-maturity stages. Based on the types of organic matter in source rocks and the relationships between organic matter abundance parameters, the evaluation standard of alkaline lake source rocks is proposed. The Fengcheng Formation is mainly composed of good to excellent source rocks (55.5%) with high hydrocarbon generation potential. The single-peak hydrocarbon generation model of the Fengcheng Formation is similar to that of traditional freshwater or saltwater lakes, with a high hydrocarbon generation rate, two to five times that of the traditional model, its main particularity is in the formation of naphthenic crude oil from the kerogen of bacteria and algae. A new understanding of the hydrocarbon generation potential and model of alkaline lake source rocks in the Fengcheng Formation can provide support for tight oil and shale oil exploration in the Mahu Sag.

It is well known that long-term water injection may induce fractured channel(s), and that the fracture geometry would change with the decrease of bottom-hole pressure (BHP) during shut-in. This results in difficulties in modelling BHP behavior. This paper presents a pressure-transient procedure to analyze the BHP performance of water injectors by taking the dynamic behavior of the water injection fractured channel into consideration. Perturbation theory is adopted to solve the non-linear equations caused by decreasing fracture conductivity, while the finite-difference method is used to include the shrinking conductive fracture length during the shut-in period. Then, Duhamel’s principle is deployed to characterize the bi-storage effect; that is, fracture-storage caused by fracture closure and wellbore storage because of wellbore after-flow. Since the mobility outside of channel walls are much poorer than that in the channel, the walls are modeled as two parallel sealed boundaries. Therefore, the method of images is lastly applied to obtain the BHP response. The bi-storage phenomenon is characterized by two unit slopes in the pressure-derivative curve, and the variable fracture-storage is identified as a new flow regime in water injectors that is caused by fracture shrinkage. The interpreted storage coefficient will be much larger than the true value if the fracture-storage flow is mistakenly regarded as wellbore-storage flow. Because of the fractured channel walls and decreasing fracture conductivity, the pressure-derivative curve would increase in late time. Finally, two cases from the Changqing Oilfield are discussed to demonstrate the capabilities of the proposed approach.

Fracability is a property that indicates how easy reservoir rocks can be fractured in hydraulic fracturing operations. It is a key parameter for fracturing design and evaluation. In order to utilize continuous logging data to predict fracability, synchronous tests of dynamic and static mechanical parameters of rocks under different confining pressures were conducted on 13 tight sandstone samples derived from the central Junggar Basin, China. A modified formula between dynamic and static mechanical parameters was established. Fracability of the tight reservoir in the Junggar Basin was then evaluated based on brittleness index, fracture toughness, and fracability index. The effectiveness of fracturing was analyzed combined with the oil testing curve after hydraulic fracturing. The results show that: (1) The distribution of oil-bearing formations in the studied area coincides well with stratum of higher fracability index. (2) The critical fracability index is determined to be 0.3, three formations are selected as fracturing candidates, and a thin mudstone interbed is identified in the oil-bearing formation. (3) Well testing curve verifies the reliability of the fracability evaluation method and the accuracy of the modified formula between dynamic and static mechanical parameters. This study provides useful information for improving fracturing operations of tight oil and gas reservoirs.

In recent years, tight oil exploration has made significant progress in the lower part of Shahejie Formation ( $$ {\text{Es}}_{3} ^{{\text{L}}} $$ ) in the Shulu Sag, Bohai Bay Basin, Eastern China, which shows good exploration prospects for tight oil. However, accurate evaluation of tight oil resource potential is influenced by a lack of studies and an incomplete understanding of hydrocarbon expulsion from marlstone source rocks. This study investigated the geological and geochemical characteristics of marlstone source rocks, their hydrocarbon generation and expulsion, and the tight oil resource. Results show that the marlstone source rocks were deposited in a reducing to weakly oxidizing lacustrine environment with low-middle salinity, distributed widely in the central and southern troughs, with the maximum thickness greater than 700 m. The marlstone source rocks have relatively high organic matter abundance (0.06–7.97% of total organic carbon content with an average value of 1.51%), are dominated by type II and I kerogen, and are at the immature to mature stage (0.3%

Through molecular dynamic simulations, the mechanism of CO2 extracting hydrocarbon in rough surface was investigated. In the present study, the entrance effect of CO2 molecules and the destruction of the miscible zone were considered as the critical factors in the extraction process. Subsequently, seven assistants were added to explore the main factors of the stability of miscible zone. The parameters of viscosity and solubility were chosen to characterize the properties of displacement agents and the dissolving capacity of CO2 was proved to be the key to improving tight oil recovery in nanopores. In addition, when the roughness of the surface was adjusted from 2.2 to 3.9, the effects of the injection pressure on residual oil were different, laying emphasis on the significance of reservoir structure for CO2 to enhance oil recovery. Moreover, our work also provided a molecular-level understanding of the CO2 extraction of hydrocarbon in rough surface, and the results had some promise for the enhancement of oil recovery in CO2 displacing engineering.

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. Key words: tight oil, hydraulic fracturing, imbibition recovery, temporary plugging agent, micro-sized proppant, nanofluid, surfactant, enhanced oil recovery

The oil in the Jurassic Da'anzhai reservoirs in the Sichuan Basin is unconventional tight oil, which accumulated in or near source rocks, and did not experience extensive migration in a large-scale long distance. The first submember, second submember and third submember of Da'anzhai Member are dominated by shell limestone which is widely and continuously distributed, and are typical near-source lacustrine shell limestone tight reservoirs. Complex lithology, multiple types of reservoir space and complicated pore structure are developed in these reservoirs. The effective reservoir space mainly includes micro-pores and micro-fractures with strong fabric selectivity. The petrophysics experiment reveals that the average connected matrix porosity of tight oil reservoir in Jurassic Da'anzhai Member is about 2.13%, lower than that of other tight oil reservoirs but higher than the average effective porosity (0.97%) from previous single alcohol-saturated method. According to production performance data, the Da'anzhai shell limestone reservoir is not a simple porous or fractured reservoir, but has complex pore-throat-fracture association or storage-seepage mode. Because the development of fossil shells controls the development of micro-fractures, fluids are difficult to enter into but easy to escape from the reservoirs. Although the pore-throat is fine, the sorting is poor and the displacement pressure is high, the movable fluid saturation and mercury ejection efficiency of the reservoir in the Da'anzhai Member is only slightly lower than that of some storage-seepage modes, and higher than that of Oil-bearing Group 7 of Yanchang Formation in the Ordos Basin. The reservoir in the Da'anzhai Member is one of the few tight oil reservoirs with high natural productivity. The tight oil in the shell limestone of the Da'anzhai Member has great development potential, but its extensive and effective development also has some challenges, such as high seepage resistance of matrix and ineffective single development mode. The development mode of the Da'anzhai tight oil should draw lessons from the Bakken Formation in North America and Oil-bearing Gourp 7 of Yanchang Formation in the Ordos Basin, and thus, effective development technologies based on volume fracturing and fine operation for shell limestone tight oil in the Da'anzhai Member in Sichuan Basin are developed to realize the development of profit and scale. Keywords: Tight oil, Storage space type, Pore structure, Pore throat, Effective porosity, Movable fluid saturation, Development potential, Effective development mode, Shell limestone, Da'anzhai member, Sichuan basin