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The Sichuan Basin in south-western China is rich in shale oil in the Jurassic strata. Due to its complex geological characteristics, reservoir identification using current log-constrained seismic inversion methods is difficult. Characteristics of the shale oil reservoirs were tested on the basis of the petrophysical experimentation of core samples from the said strata. Thin sections and logging data analysis showed the influencing factors on petrophysical characteristics and clarified the sensitive geophysical parameters for reservoir identification. The Da'anzhai Member reservoirs were determined to have high acoustic velocities, Vp/Vs ratios and Young's moduli, and low Poisson's ratios. Several geological factors have influenced the petrophysical properties of the reservoirs. The Da'anzhai Member reservoirs are characterized by a low content of clay minerals and the development of fractures and laminae. The presence of clay minerals caused general high acoustic velocities of the reservoirs; the presence of fractures and laminae in high-quality reservoirs results in a decrease of the acoustic velocities. Therefore, the relatively low value against the background of high acoustic velocity can be used as the criteria for high-quality reservoirs. Poisson's ratio is obviously different in reservoirs and non-reservoirs. When it is 25.277 and μ > 20.72 GPa), P-wave and S-wave velocity (Vp > 4967 and Vs > 2781 m s−1), wave impedance and Vp/Vs ratio (AI > 13.319 g · cm3 · km · s−1 and Vp/Vs > 1.792) can also provide references for reservoir identification.

Natural fractures, as the main flow channels and important storage spaces, have significant effects on the migration, distribution, and accumulation of tight oil. According to outcrop, core, formation micro image (FMI), cast-thin-section, and scanning electron microscopy data from the tight reservoir within the Permian Lucaogou Formation of the Junggar Basin, tectonic fractures are prevalent in this formation mainly on micro to large scale. There are two types of fractures worth noticing: diagenetic fractures and overpressure-related fractures, primarily at micro to medium scale. The diagenetic fractures consist of bedding fractures, stylolites, intragranular fractures, grain-boundary fractures, and diagenetic shrinkage fractures. Through FMI interpretation and Monte Carlo method evaluation, the macro-fractures could be considered as migration channels, and the micro-fractures as larger pore throats that function as storage spaces. The bedding fractures formed earlier than all tectonic fractures, while the overpressure-related fractures formed in the Middle and Late Jurassic. The bedding fractures and stylolites function as the primary channels for horizontal migration of tight oil. The tectonic fractures can provide vertical migration channels and reservoir spaces for tight oil, and readjust the tight oil distribution. The overpressure-related fractures are fully filled with calcite, and hence, have little effect on hydrocarbon migration and storage capacity. The data on tight oil production shows that the density and aperture of fractures jointly determine the productivity of a tight reservoir.

Based on the data of cores, thin sections, well logs, and test experiments, the characteristics and main controlling factors of lamellation fractures in continental shales of the third and fourth members of the Paleogene Qianjiang Formation in the Qianjiang Depression, Jianghan Basin, are studied. Lamellation fractures mainly develop along laminas in shales. They have various morphological characteristics such as straightness, bending, discontinuity, bifurcation, pinching out, and merging. Lamellation fractures with high density show poor horizontal continuity and connectivity characteristics. The average linear density of the lamellation fractures is mainly between 20 m-1 and 110 m-1, and the aperture is usually less than 160 μm. The density of lamellation fractures is related to their apertures. The smaller the apertures of lamellation fractures are, the higher the density is. The development degree of lamellation fractures is mainly controlled by mineral composition, type, thickness, density of lamination, contents of organic matter and pyrite, lithofacies, structural position, etc. Lamellation fractures develop well, especially under the conditions of medium dolomite content, large lamination density, small lamination thickness, and high total organic carbon (TOC) and pyrite contents. The influences of lithofacies on the lamellation fractures are complex. The lamellation fractures are most developed in carbonaceous layered limestone dolomite and carbonaceous layered dolomite mudstone, followed by stromatolite dolomite filled with carbonaceous pyroxene. The fractures in the massive argillaceous dolomites and carbonaceous massive mudstones are poorly developed. No fractures can be found in the carbonaceous dolomitic, argillaceous glauberites or salt rocks with high glauberite content. Structure is also an important factor controlling lamination fractures. Tectonic uplifts are beneficial to the expansion and extension of lamellation fractures, which increases fracture density. Therefore, when other influence factors are similar, lamellation fractures develop better in the high part of the structure than in the low part.

The Upper Triassic Xujiahe Formation is a typical tight gas reservoir in which natural fractures determine the migration, accumulation and production capacity of tight gas. In this study, we focused on the influences of natural fractures on the tight gas migration and production. We clarified characteristics and attributes (i.e. dips, apertures, filling degree and cross-cutting relationships) of the fractures based on image logging interpretations and core descriptions. Previous studies of electron spin resonance, carbon and oxygen isotopes, homogenization temperature of fluid inclusions analysis and basin simulation were considered. This study also analysed the fracture sequences, source of fracture fillings, diagenetic sequences and tight gas enrichment stages. We obtained insight into the relationship between fracture evolution and hydrocarbon charging, particularly the effect of the apertures and intensity of natural fractures on tight gas production. We reveal that the bedding fractures are short horizontal migration channels of tight gas. The tectonic fractures with middle, high and nearly vertical angles are beneficial to tight gas vertical migration. The apertures of fractures are controlled by the direction of maximum principal stress and fracture angle. The initial gas production of the vertical wells presents a positive correlation with the fracture abundance, and the intensity and aperture of fractures are the fundamental factors that determine the tight gas production. With these findings, this study is expected to guide the future exploration and development of tight gas with similar geological backgrounds.

Kernel Fisher discriminant analysis (KFD) can map well-log data into a nonlinear feature space to make a linear nonseparable problem of fracture identification into a linear separable one. Commonly, KFD uses one kernel. However, the prediction capacity of KFD based on one kernel is limited to some extent, especially for a complex classification problem, such as fracture identification in tight sandstone reservoirs. To alleviate this problem, we have used a multiple kernel Fisher discriminant analysis (MKFD) method to recognize fracture zones. MKFD uses multiscaled Gaussian kernel functions instead of a single kernel to realize optimal nonlinear mapping. To assess the effectiveness of MKFD in fracture identification for complex reservoirs, we chose a data set from tight sandstone reservoirs in China to implement comparison experiments. In the experiments, we used the MKFD with 20 Gaussian kernels to map the original well logs into nonlinear feature spaces so that we could obtain appropriate features for fracture identification. The comparison results demonstrated that the accuracy of fracture identification by MKFD improved about 13.4% over KFD and that MKFD also outperformed KFD in the blind well test, although the improvement of the generalization ability of MKFD was not very obvious. Overall, MKFD can provide an accurate means for the identification of fracture zones in tight reservoirs. We also evaluate the problems for fracture identification by MKFD.

Fractures are of great significance to tight oil and gas development. Fracture identification using conventional well logs is a feasible way to locate the underground fractures in tight sandstones. However, there are three problems affecting its interpretation accuracy and practical application, namely weak well log responses of fractures, a lack of specific logs for fracture prediction, and relative change omission in log responses. To overcome these problems and improve fracture identification accuracy, a fracture indicating parameter (FIP) method composed of a comprehensive index method (CIM) and a comprehensive fractal method (CFM) is introduced. The CIM tries to handle the first problem by amplifying log responses of fractures. The CFM addresses the third one using fractal dimensions. The flexible weight parameters corresponding to logs in the CIM and CFM make the interpretation possible for wells lacking specific logs. The reconstructed logs in the CIM and CFM try to solve the second problem. It is noted that the FIP method can calculate the probability of fracture development at a certain depth, but cannot show the fracture development degree of a new well compared with other wells. In this study, a formation fracture intensity (FFI) method is also introduced to further evaluate fracture development combined with production data. To test the validity of the FIP and FFI methods, fracture identification experiments are implemented in a tight reservoir in the Ordos Basin. The results are consistent with the data of rock core observation and production, indicating the proposed methods are effective for fracture identification and evaluation.

Natural fractures are important storage spaces and fluid-flow channels in tight-oil sandstones. Intraformational open fractures are the major channels for fluid flow in tight-oil sandstones. Small faults may provide fluid-flow channels across different layers. According to analogous outcrops, cores, and borehole image logs, small faults and intraformational open fractures are developed in the tight-oil sandstones of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, China. Among them, high dip-angle intraformational open fractures are the most abundant. Northeast-southwest–trending fractures are the principal fractures for fluid flow because that is the present-day maximum horizontal compressive stress direction. Combined with production data, horizontal wells, striking normal to or at a large angle relative to the major flow pathways, are beneficial for tight-oil production improvement. Fractures with high dip angles are the main factor that influences initial oil production. Linkage and tip damage zones are more favorable for oil production improvement than wall damage zones. This study provides an example of natural fracture characterization and unravels fracture contributions to reservoir physical properties and oil production of tight-oil sandstones, which could provide a geological basis for oil exploration and development in tight sandstones.

Measurements of in situ stress in a single well from borehole breakouts, hydraulic fracturing, multipole acoustic logs and differential strain analysis of core indicate that the orientation of the maximum horizontal stress is northwest-southeast in thick channel-fill sandstones in the central-western Bonan Oilfield, while the orientation is northeast-southwest in the thin interbed siltstones and mudstones of the floodplain in the eastern Bonan Oilfield. This result shows that the orientation of the maximum horizontal stress in the thin interbed of siltstones and mudstones is in accordance with the regional stress orientation obtained by the focal mechanism of a natural earthquake, but has a 30°–40° variation with the thick channel-fill sandstones. Finite element simulation suggests that the main reason for the variation in the orientation of the maximum horizontal stress is the diversity of overall mechanical properties, especially modulus of elasticity, of the thick channel-fill sandstones and the interbedded thin layer of siltstones and mudstones. The average Young's modulus over the stratigraphic column governs stress rotations. The transformation of the orientation of the maximum horizontal stress from the central-western to the eastern locations is at the channel boundary. This research provides a case in which the variation in the orientation of the maximum horizontal stress is affected by thick channel-fill sandstones. It shows that lithological changes can cause variations in the direction of in-situ stress.

Based on cores, image logs and thin sections, five sets of fractures are developed in the study area, where faults are developed. Most of fractures are open without fillings, and some fractures are filled with calcite, quartz, bitumen, pyrite and mud. Fractures are mainly controlled by lithology, mechanical stratigraphy and faults. Based on mutual crosscutting relationships of fractures, mineral filling sequence of fracture fillings, fluid inclusion and carbon-oxygen isotope analysis of calcite fillings in fractures, and quartz spintronic resonance analysis of quartz fillings in fractures, in combination with thermal and burial history, the formation sequence and time of fractures were analyzed. The results show that fractures mainly formed over three period, that is, the late Triassic, Middle to Late Jurassic, and Late Cretaceous to Paleogene. Then，combined with the paleostress evolution and fracture characteristics of the study area, the formation mechanism of fractures was discussed.

Fault damage zones around faults have a significant influence on fluid flow in tight-oil sandstones because they commonly act as localized conduits. Faults are developed in the tight-oil sandstones of the Upper Triassic Yanchang Formation in the southwest Ordos Basin, China. We integrate cores, image logs, and conventional logs from vertical wells to characterize subsurface fault damage zones in the tight-oil sandstones of the Upper Triassic Yanchang Formation in the southwest Ordos Basin, China. The results indicate that fault damage zones are intensively fractured or intensely broken in the cores. These fault damage zones present borehole collapse and widen sinusoidal curves in the image logs. The fractures in fault damage zones are predominant high dip angles. The fracture intensity decays with the increasing orthogonal distance from the faults within a fault damage zone. In fault damage zones, acoustic log (AC) values and compensated neutron log (CNL) values increase; density log (DEN) values decrease, dual induction log (ILD and ILM) and laterolog 8 (LL8) values decrease, the caliper log (CAL) presents borehole enlargement, and comprehensive fracture index log (CFI) values are greater than 0.43 and average 0.78. To identify fault damage zones by conventional logs in vertical wells, it is critical to distinguish fault damage zones from the background fractured zones. The ILM, CNL, ILD, LL8, and AC logs would be more useful than DEN logs for the distinction between background fractured zones and fault damage zones. The responses of fault damage zones in conventional logs are more intensive than those of background fractured zones, and the heights of fault damage zones are much greater than those of background fractured zones, which can be used for the distinction between fault damage zones and background fractured zones.

Fractures are the main fluid-flow pathways in tight-oil sandstones, and they have a significant influence on tight-oil distribution, exploration, and development. Cores and image logs are commonly unavailable because of their high costs, so employing conventional logs for fracture detection is imperative for tight-oil sandstones. We compared the fracture-response characteristics of conventional logs based on two data sets, one from 8 cored wells with fracture intensities greater than 1 m−1 (3.3 ft−1) and the other from 11 cored wells with fracture intensities less than 0.5 m−1 (1.6 ft−1), with a case study of the Upper Triassic Yanchang Formation in southwest Ordos Basin, China. The results indicate that when tight-oil sandstones are more intensely fractured, the caliper log, acoustic log, compensated neutron log, density log, dual induction logs, and laterolog 8 present fracture responses to some extent. However, it is difficult to make a distinction between fractured and nonfractured zones using conventional logs in sandstones with smaller fracture intensities. The fracture-response intensities of conventional logs are weak, and they are influenced by fracture abundance, fracture occurrence, fracture scale, and mineral-filling degree. Moreover, lithology, fluids, and rock physical properties can cause fracturelike responses. Hence, some ambiguity exists when using conventional logs to directly identify fractures. Accompanying fracture-sensitive conventional logs with some methods to enhance fracture-response intensity and eliminate nonfracture influence could enable fracture identification in tight-oil sandstones.

Natural fractures, which serve as the main flow channels and important storage spaces, have significant effects on the formation, distribution and development of shale gas. We found three types of natural fractures developed in the Paleozoic marine shales of the southeastern Sichuan Basin, including tectonic fractures, diagenetic fractures and abnormal high-pressure-related fractures. Tectonic fractures can be further divided into intraformational open fractures, transformational shear fractures and bed-parallel shear fractures, whereas diagenetic fractures can be divided into bed-parallel lamellated fractures and shrinkage fractures. We determined that the formation of shale fractures is determined by the brittle-mineral content, shale texture, strata attitude, fluid pressure and geological structure. Brittle minerals, e.g., quartz, feldspar and dolomite, are necessary for the formation of shale fractures. Lamellation could change the mechanical property of fractures, which caused the formation of bed-parallel shear fractures. Geological structure is a key factor determining the maturity of shale fractures. The distribution and development of shale gas is barely influenced by shrinkage fractures and abnormal high-pressure-related fractures due to the low transport effectiveness. Intraformational open fractures, transformational shear fractures, bed-parallel shear fractures and lamellation fractures are significant to shale gas. The denser intraformational open fractures and lamellation fractures can enrich the degree of shale gas. We determined that the scale of shear fractures is the key factor influencing gas preservation rather than the density of natural fractures. Transformational shear fractures determine the gas preservation in areas with low dip-angle strata, whereas bed-parallel shear fractures determine the gas preservation in areas with high dip-angle strata.

Fracture identification using conventional logs is a cost effective way of identifying fracture zones in reservoirs. However, there are challenging problems including complex well log responses and small amount of labelled data available from cores or image logs, making it difficult to build a prediction model with a good generalization capability. To address these problems, a semi-supervised learning method termed Laplacian support vector machine (LapSVM) is introduced in this work, which is a combination of the supervised kernel method and the unsupervised clustering method. LapSVM inherits SVM's capability of handling nonlinear problems and overcomes partially the issue of limited labelled data by using the unsupervised clustering technique with the help of abundant well log information. To examine the effectiveness of LapSVM for fracture identification in tight reservoirs, a dataset from the tight sandstones of the Ordos Basin in China is used. Both statistical and geological evaluations indicate that LapSVM outperforms other three nonlinear SVM methods tested. It has been demonstrated that LapSVM can provide an accurate and effective means for the identification of fracture zones in tight reservoirs.

Waterflooding is an important functional process for low-permeability reservoir development. However, production practice shows that water breakthrough and floods along natural fractures are ubiquitous in low-permeability reservoirs. Therefore, controlling the water injection pressure to prevent water breakthrough and floods along natural fractures is an effective measure for improving the waterflooding development effect. In this paper, an approach is proposed for determining the water injection pressure based on the opening pressure of natural fractures in fractured low-permeability reservoirs. The opening pressures of natural fractures calculated by the analytical method in the paper and the formation-parting pressures are compared based on the production performance in two different fault blocks F16 and Z3 of the Zhouqingzhuang Oilfield in the Bohai Bay Basin, China. The results show that the calculated opening pressures of the natural fractures in fault blocks F16 and Z3 are 31.4 and 42.9 MPa, respectively, and they are close to the opening pressures of natural fractures obtained from the step-rate tests in injection wells (28.6 and 41.1 MPa); whereas, the formation-parting pressures (44.5 and 47.6 MPa) are greater than the opening pressures of natural fractures. This suggests that the opening pressures of natural fractures can be used, instead of the formation-parting pressure, for the maximum threshold of the water injection pressure. Its effectiveness has been confirmed via comparison to the production performances of the other two wells in the Zhouqingzhuang Oilfield and several fractured low-permeability reservoirs in the Ordos Basin, China. This study will have beneficial applications in the design of waterflooding development in low-permeability reservoirs characterized by the presence of natural fractures.

Elliptic borehole breakouts are usually used to determine the orientation of in situ stress in deep sedimentary basins. The long axes of borehole breakouts are generally perpendicular to the maximum horizontal principal compression stress (SHmax). However, the azimuth of borehole breakouts is found perpendicular to the chief strike (but not to SHmax) of natural fractures in tight reservoirs, Anpeng field of Nanxiang Basin, China. Based on the core data and acoustic and resistivity borehole image logs, the natural fractures are intensively striking at east-west orientation where borehole breakouts occurred in north-south. If the borehole breakouts are induced only by in situ stresses surrounding the well and the borehole breakouts are known at north-south, SHmax should be perpendicular at east-west, but according to analyses of the earthquake focal mechanism in circumjacent regions, hydraulic fracturing data, drilling-induced fracture data, and the production performance data, SHmax is in the northeast-southwest direction. This contradiction indicates that the influence of natural fractures may cause a serious deviation of the azimuth of borehole breakouts. Therefore, in this case, it is unreliable to determine the orientation of in situ stress only by borehole breakouts in fractured tight reservoirs. In addition, the main fluid flow direction is not parallel to the dominant natural fracture, which is controlled by in situ stress in tight reservoirs.