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.
The Upper Triassic Xujiahe Formation in the northwestern Sichuan Basin, China, is a typical tight gas sandstone reservoir that contains natural fractures and has an average porosity of 1.10% and air ...permeability less than 0.1 md because of compaction and cementation. According to outcrops, cores and image logs, three types of natural fractures, namely, tectonic, diagenetic and overpressure-related fractures, have developed in the tight gas sandstones. The tectonic fractures include small faults, intraformational shear fractures and horizontal shear fractures, whereas the diagenetic fractures mainly include bed-parallel fractures. According to thin sections, the microfractures also include tectonic, diagenetic and overpressure-related microfractures. The diagenetic microfractures consist of transgranular, intragranular and grain-boundary fractures. Among these fractures, intraformational shear fractures, horizontal shear fractures and small faults are predominant and significant for fluid movement. Based on the Monte Carlo method, these intraformational shear fractures and horizontal shear fractures improve the reservoir porosity and permeability, thus serving as an important storage space and primary fluid-flow channels in the tight sandstones. The small faults may provide seepage channels in adjacent layers by cutting through layers. In addition, these intragranular and grain-boundary fractures increase the connectivity of the tight gas sandstones by linking tiny pores. The tectonic microfractures improve the seepage capability of the tight gas sandstones to some extent. Low-dip angle fractures are more abundant in the T3X3 member than in the T3X2 and T3X4 members. The fracture intensities of the sandstones in the T3X3 member are greater than those in the T3X2 and T3X4 members. The fracture intensities do not always decrease with increasing bed thickness for the tight sandstones. When the bed thickness of the tight sandstones is less than 1.0 m, the fracture intensities increase with increasing bed thickness in the T3X3 member. Fluid inclusion evidence and burial history analysis indicate that the tectonic fractures developed over three periods. The first period was at the end of the Triassic to the Early Jurassic. The tectonic fractures developed during oil generation but before the matrix's porosity and permeability reduced, which suggests that these tectonic fractures could provide seepage channels for oil migration and accumulation. The second period was at the end of the Cretaceous after the matrix's porosity and permeability reduced but during peak gas generation, which indicates that gas mainly migrated and accumulated in the tectonic fractures. The third period was at the end of the Eogene to the Early Neogene. The tectonic fractures could provide seepage channels for secondary gas migration and accumulation from the Upper Triassic Xujiahe Formation into the overlying Jurassic Formation.
•Determined origins of natural fractures in tight gas sandstones.•Identified contributions of fractures to reservoir properties.•Documented Influence of fractures on gas migration and accumulation.
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.
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•The FIP method is introduced to improve fracture identification using logs in tight reservoirs.•This method is used to further evaluate fracture development based on FIP.•Results show that the proposed methods are effective for fracture identification and evaluation.
Ordovician tight carbonate rocks in the Tarim Basin are typically ultra-deep, with targets deeper than 7000 m. The fracture networks associated with strike-slip faults are the primary reservoir ...space. Fracture intensity near faults is higher than in wall rock areas and decreases with distance from faults. Based on the relationships of fracture network with the structure of strike-slip faults imaged by seismic data, adjacent to faults (in the ‘fault wall’) there are small-scale wall damage zones (SML SC WALL DMG ZONE) having fault widths is less than 250m, length less than 5 km; large-scale damage zones (LRG SC WALL DMG ZONE) having fault widths are greater than 250m, lengths greater than 5 km; intersection damage zones (INT DMG ZONEs), linking damage zones (LINK DMG ZONEs), overlapping zones between the linking damage zones and intersection damage zones (OL ZONE LINK INT DMG ZONEs).
Increasing fracture intensity can be incorporated into fracture network models using well data and seismic data. We used the bounding box and scan line methods to evaluate fracture network connectivity and predict flow. The reliability of the results was verified by interference well tests. The fracture network connectivity based on the bounding box and scan line method is consistent with interference well test data, demonstrating that the bounding box and scan line method can effectively evaluate fracture network connectivity. The fracture network connectivity ranges from high to low in this order: overlapping zones between linking and intersecting zones, linking, intersecting, and large- and small parallel zones. Based on outcrop pattern and 3D discrete element simulation results we infer that connectivity is caused by stress concentration and perturbation in the evolution of strike-slip fault. The LINK DMG ZONE raises the displacement gradient and causes local rotation of the stress field, resulting in increased intensity, complex fracture directions, and high connectivity of fractures. The slip gradient of the INT DMG ZONE grows significantly due to stress perturbations, culminating in more fractures and increased connectivity. The OL ZONE LINK INT DMG ZONE generates more complex fracture networks with better connectivity.
•Strike-slip faults in ultra-deep carbonates buried more than 7000 m.•Fracture network characteristics in different types of strike-slip fault damage zones.•The bounding box and scanning line (BBSL) method to analyze fracture network connectivity.•Fracture network connectivity variations in different types of strike-slip fault damage zones.•Effect of strike-slip fault evolution on fracture network connectivity.
The fault-bend fold, a typical structure in foreland thrust belts, is suitable for hydrocarbon accumulation. Natural fractures are ubiquitously developed and usually interlaced to form a complex ...network in fault-bend folds, which can play a fundamental role in hydrocarbon migration and enrichment. This study utilized outcrops and the discrete element method (DEM) to simulate and analyze the characteristics, distribution patterns, and development mechanisms of natural fractures in the fault-bend fold. The study anticline, located in the southern margin of the Junggar Basin, is a well exposed fault-bend fold. Statistical results of dips and dip direction of fracture in different structural positions show that the fold-related fractures strike NWW-SEE parallel to the axis of the study fold. The fractures include layer-parallel shortening related fractures (LPSF), interlayer slipping related fractures (ILSF), active hinge parallel shearing related fractures (AHSF), and curvature-related fractures (CF). The LPSF and ILSF are strata-bound fractures, whereas the CF and AHSF are not strictly confined in layers. Furthermore, results of the DEM and outcrop measurements demonstrate that LPSF are formed at the embryonic stage. ILSF and AHSF are formed in the early stage, and the mid-late stage is the main formation period of CF. By integrating strata deformation history with fracture types and development characteristics, a development pattern of fractures within the fault-bend fold has been established, and five deformation panels are developed (panels I–V). From panels I to V, the fracture area density increases consecutively, and panel I (unfolded) is limited to regional fractures. Next, LPSF and ILSF are more highly developed in panel V (forelimb) than in panels IV (strongly folded layers of the backlimb), III (core), and II (weakly folded layers of the backlimb). Moreover, CF are predominantly found in panel III, and AHSF are mostly developed in panel IV. Overall, this study investigated the characteristics of fractures in deformation panels of the fault-bend fold and thus provides guidance for locating favorable reservoirs in foreland thrust belts.
•Discrete element method (DEM) and outcrop observation were used to investigate fracture characteristics.•The types, formation mechanism, and distribution rules of the fault-bend fold-related fracture were discussed.•A comprehensive fracture development pattern of the fault-bend fold was established.
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.
Tight sandstone reservoirs have extremely low porosity and permeability. Bedding-parallel fractures (BPFs) contribute prominently to the storage and seepage capability. However, the distribution of ...BPFs is remarkably heterogeneous, impeding the prediction and modeling of sweet spots. BPFs are controlled fundamentally by laminations, which are widely distributed in lacustrine tight reservoirs and provide most weakness planes. Based on core and thin section data, BPFs of the upper Triassic Chang 7 tight oil reservoir are characterized microscopically. The lamination combination unit, which is defined by distinctive lamination assemblage and relatively stable lamination thickness and space, is utilized as a homogeneous unit to measure the density of lamination and related BPFs. The influence of laminations on BPFs is discussed further. Results show that most bedding-parallel fractures are unfilled, with apertures generally <40 μm, mainly <10 μm. Larger apertures correlate with low filling degrees. The distribution of BPFs is intricately controlled by lamination type, density, and thickness. (1) BPFs tend to develop along different types by a priority sequence which reflects their mechanical strength. The development degree of BPFs also depends on the mechanical contrast with adjacent laminations; (2) When controlled by a single type of lamination, the density of BPFs increases with lamination density under a turning point and then decreases; (3) BPFs prefer to develop along the thinner lamination and are usually inside it, while controlled by thick lamination, BPFs tend to extend along the edge. The change in the thickness of laminations leads to a change in the development position of BPFs, indicating that the position of the weak plane controls the development position of BPFs; (4) When multiple types of lamination coexist, the type and thickness of laminations jointly influence the development of BPFs. Plastic thin laminations are conducive to the development of BPFs, while brittle thick laminations are not conducive. When the thickness of the plastic lamination is close to or less than that of the brittle, the influence of lamination type dominates BPFs, while the thickness of the plastic laminations is much larger than the brittle, the influence of lamination thickness will dominate.
The present-day in-situ stresses affect the drilling design, well pattern deployment, well completion modification, hydraulic fracturing and water injection of tight-oil sandstones. The measurement ...data of these stresses are commonly unavailable because of their high costs and limited core samples, therefore employing conventional logs for these stress determination is imperative for tight-oil sandstones. Firstly, the suitable calculation models for the present-day in-situ stress calculation by conventional logs were selected according to the geological characteristics of the sixth member of the Yanchang Formation (Chang 6) in Heshui area of the southern Ordos Basin, China. Then, the dynamic rock mechanical parameters were determined by conventional logs, and corrected by the static rock mechanical parameters obtained from the triaxial rock mechanical tests. Moreover, the pore fluid pressure was determined by the empirical formula method. Finally, the maximum and minimum horizontal compressive stresses (σH and σh), and the vertical stress (σv) of six wells were calculated according to the selected models of these stresses, respectively. The present-day in-situ stresses, determined by the proposed method in the paper, were verified by those obtained from acoustic emission tests and finite-element numerical simulations with the relative errors of less than 10%. The results show that the magnitudes of σH, σh and the horizontal differential stress (σH−h) in the study area mainly range from 32 to 43 MPa, 23 to 37 MPa and 5 to 8 MPa, respectively. The magnitude of the three-dimensional present-day in-situ stress increases with the increase of depth. The average gradients of σH, σv and σh are 0.018, 0.014 and 0.015 MPa/m, respectively, that is σH>σv>σh. In this stress state, the hydraulic fractures, with a trend of little expansion towards multiple directions, are commonly developed at a small angle intersecting with the direction of σH in the study area.
Analysis of natural fractures is essential for understanding the heterogeneity of basement reservoirs with carbonate rocks since natural fractures significantly control key attributes such as ...porosity and permeability. Based on the observations and analyses of outcrops, cores, borehole image logs, and thin sections from the Mesoproterozoic to Lower Paleozoic in the Jizhong Sub-Basin, natural fractures are found to be abundant in genetic types (tectonic, pressure-solution, and dissolution) in these reservoirs. Tectonic fractures are dominant in such reservoirs, and lithology, mechanical stratigraphy, and faults are major influencing factors for the development of fractures. Dolostones with higher dolomite content are more likely to have tectonic fractures than limestones with higher calcite content. Most tectonic fractures are developed inside mechanical units and terminate at the unit interface at nearly perpendicular or high angles. Also, where a thinner mechanical unit is observed, tectonic fractures are more frequent with a small height. Furthermore, the dominant direction of tectonic fractures is sub-parallel to the fault direction or oblique at a small angle. In addition, integrating diverse characteristics of opening-mode fractures and well-testing data with oil production shows that, in perforated intervals where dolostone and limestone are interstratified or dolostone is the main lithologic composition, fractures are developed well, and the oil production is higher. Moreover, fractures with a larger dip angle have bigger apertures and contribute more to oil production. Collectively, this investigation provides a future reference for understanding the importance of natural fractures and their impact on oil production in the carbonate basement 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.
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