Opening-mode Fractures Research Articles

Fracture length data for geothermal applications

Fracture lengths govern permeability and are unknowns in geothermal assessment. Along their lengths, fracture widths vary due to growth by linkage. Under the influence of diagenesis, narrow widths seal, breaking porosity continuity and reducing open length. The largest range of widths and thus susceptibility to fill occurs where fractures are linked by narrow segments. Outcrops of a geothermal target, Cambrian Potsdam quartz arenite, contain opening-mode fractures having lengths spanning five orders of magnitude from 0.082 mm to 17.9 m. Combined lengths measured at a range of scales can be described by power laws, but at a given image resolution, lengths are best fit by exponential functions. Owing to preferential sealing of small fractures, open fractures follow exponential functions, but values depend on rules for designating fractures as continuous. En échelon segments, offset 10 mm, are connected by narrow fractures or microfractures (hard linked) not evident on outcrop 1-m-elevation LiDAR or 30-m-height drone images. A rule that identifies where narrow but probably connected segments yields lengths that are meaningful for flow simulation. Depending on diagenesis, continuity rules can halve or double average and maximum length values. Length values from outcrop for geothermal applications should be adjusted based on wellsite-specific diagenesis information.

Calcite U[sbnd]Pb dating and geochemical constraints on fracture opening in organic-rich shales

Gas-bearing, organic-rich shales commonly host numerous opening-mode fractures; however, their formation mechanism remains controversial, with competing arguments of tectonic-origin and/or hydrocarbon generation pressurization-origin. Here, we studied fracture fillings in shale reservoirs of the lower Silurian Longmaxi Formation in the Luzhou area, southern Sichuan Basin, SW China. Using in-situ UPb geochronology, rare earth elements (REEs) and C-O-Sr isotope geochemistry, and fluid inclusion analyses, we investigated the timing and geochemical attributions of fracture fills and identify the mechanism of fracture formation. The results show that, the cements that occupy fractures in the Longmaxi Formation shales contain mainly calcite and quartz. The calcite cements show crack-seal and fibrous textures, indicating that they are syn-kinematic mineral deposits. The 87Sr/86Sr values of the calcite cements essentially overlap with those of their proximal host shales. This result, combined with slight depletions in δ13CPDB and relatively uniform fluid δ18OSMOW isotopic features, indicate that the fluids from which the calcite precipitated were largely derived from their surrounding host shales. Abundant methane inclusions are present in fracture cements, with trapping pressures of 104.5–157.5 MPa and pressure coefficients of 1.92–2.43, suggesting they were trapped in an overpressurized fluid system. In-situ UPb dating of calcite cements yielded ages of ca. 160 Ma and ca. 110 Ma, which coincide with the timing of thermal cracking of oil to gas during burial. In combination with the overpressurized, geochemically closed fluid system, the fractures were most likely triggered by gas generation. Our study emphasizes that natural fracturing induced by hydrocarbon generation overpressurization is an essential mode of brittle failure in tectonically quiescent basins worldwide.

Santos Basin as an Example of a Shear-Driven Core Complex in a Transform Marginal Plateau

It is proposed a new model on the kinematics of strain partitioning for the breakup of the Santos and Namibe conjugate basins. The model is based on observed strike-slip corridors and low-angle detachments with metamorphic core complexes, which accommodated the deformation in a mega relay zone. Through detailed reconstructions of this segment of the South Atlantic, collecting multidisciplinary data from previous researchers, and considering the relative relationship between Africa and South America during the breakup process, it is herein reexamined key evidence of how the Brazilian side became so wide, and acted as an accommodation zone during the Aptian. The 600 km Long transpressional-dextral Proterozoic Ribeira Belt is the cradle of the transtensional-sinistral Santos-Namibe strike-slip rift propagator. These conjugate basins evolved as a large-scale relay zone, developing an oblique-left-lateral extensional corridor during the Aptian, balancing mechanically coeval deformations from two sub-parallel spreading branches, traveling from North and South, but hundreds of kilometers apart from each other. Proterozoic inheritance, and the dynamic clockwise rotation of South America (far-field stresses) controlled strain partitioning between the Campos/Benguela basins and the Pelotas/Walvis basins. The onset of seafloor spreading around the Falkland (Malvinas) Island, triggered the relative clockwise rotation of the southernmost tip of the South America plate, and the intrusion of transversal dike swarms of the Ponta Grossa Arch, which is interpreted as fissural magmatism, comparable to a regional opening mode(type I) fracture system. Plate kinematic transport direction inferred from plate reconstructions is mainly EW. The step-over oblique-slip of this relay zone widened the Santos Basin in the NW-SE direction, often mistakenly misinterpreted as the extension direction in the Santos Basin. This NW path is the direction of the maximum elongation within an E-W shear corridor. Our work details a new and unprecedented strike-slip structural framework of the Santos Basin, with large-scale basement-involved folding around the Outer High, which evolved to an obliquely sheared active low-angle detachment system, simultaneously influenced by the thermal anomaly of the Tristan-Gough plume, responsible for magmatic thermal weakening and thermal-induced uplift. Magmatic underplating may have facilitated the doming process. The Santos Basin is located at the heart of a Transform Marginal Plateau, as previously proposed. It is composed of a magmatic crust, with fragmented slices of continental crust, obliquely sheared during successive transform movements, with possible magmatic underplating. This kinematically linked system of normal faults, strike-slip faults, flexural folds, and detachment faults has direct impact on understanding the properties of world-class oil and gas reservoirs in the Brazilian Pre-Salt Supergiant Province. With the ongoing regional transgression, the active structural highs were the site of deposition of the carbonate reservoirs that host an in-place volume around a hundred billion barrels of hydrocarbons, considering the whole province.

Characteristics and effectiveness of deep and ultradeep tight sandstone fractures: Insights from geologic and geophysical data analysis

Effective natural fractures are those that contribute to reservoir storage and conductivity. In this study, the effectiveness of fractures in deep and ultradeep reservoirs (depths > 6 km) is evaluated by using geophysical image logs, cores, microstructures, mechanical tests, and geologic evidence of the tectonic context (including current in situ stress) and sedimentary faces and diagenesis. Intraformational open-mode fractures are the most common fracture type in this tectonically active region, and their effectiveness is affected by the coupling between past tectonic activity, in situ stress, and chemical reactions such as mineral precipitation or dissolution (diagenesis). Our results show that the effectiveness of fractures is mainly related to the aperture and filling, and fractures formed by early tectonic movement are more likely to be filled by minerals, reducing their effectiveness. Strata near orogenic belts in strongly cemented, tight diagenetic facies exhibit a greater abundance of mineral-filled fractures, whereas dissolution increases the fracture apertures, produces secondary pores in host rocks, and roughens the fracture walls. The effective normal stress acting on the fracture surface decreases when the fracture is parallel to the maximum horizontal stress component, so the fracture has a large aperture and, therefore, is more effective. The results of our laboratory measurements reveal that the contribution of fractures to the reservoir space is limited, and the reservoir space provided by fractures accounts for only 13% of all types of reservoir space, whereas the presence of fractures increases reservoir permeability by 1–2 orders of magnitude. Fractures improve the effectiveness of the reservoir by connecting the dispersed pores in the reservoir matrix. Fractures with a low angle to the maximum horizontal stress component have greater apertures and permeabilities and are the main channels for fluid flow.

Implication of fast shear wave azimuth and critically stressed fractures in a coalbed methane reservoir

The orientation of the fractures and stresses within coal seams plays a critical role in gas production from coalbed methane reservoirs. In this study, we used resistivity images and sonic logs to investigate these parameters, aiming to (1) establish the relationship between fracture orientations and the polarization angles of fast shear waves and (2) detect active fractures in the coal seam. Shear waves in anisotropic formations are split into fast and slow components, with Alford’s rotation method used to determine the polarization angles of the fast shear wave. We found that the fast shear wave aligns with the direction of higher fracture intensity. Subsequently, we incorporated the poroelastic strain model to estimate the vertical ([Formula: see text]), maximum horizontal ([Formula: see text]), and minimum horizontal ([Formula: see text]) stresses in the wellbore. These stress magnitudes aided in identifying the faulting regime and were corroborated by vertical opening mode fractures. Validation of [Formula: see text] and [Formula: see text] involved comparisons with the breakout width in image logs and the closure pressure observed during hydraulic fracturing treatments. Applying Mohr’s Coulomb criteria, the stress model discerned the state of the fractures, transforming the stress magnitudes into shear and effective normal stress on each fracture plane. Our observations indicated that the identified fractures existed in a noncritically stressed condition, suggesting a lack of interconnectivity among them. These findings correspond to the absence of gas production to date, providing insights into the dynamics of fractures and their impact on production behavior.

Normal fault reactivation induced by hydraulic fracturing: Poroelastic effects

Numerous surface-felt earthquakes have been spatiotemporally correlated with hydraulic-fracturing operations. Because large deformations occur close to hydraulic fractures (HFs), any associated fault reactivation and resulting seismicity must be evaluated within the length scale of the fracture stages and based on the precise fault location relative to the simulated rock volumes. To evaluate the changes in Coulomb failure stress (CFS) with injection, we conduct fully coupled poroelastic finite-element simulations using a pore-pressure cohesive zone model for the fracture and fault core in combination with a fault-fracture intersection model. The simulations quantify the dependence of CFS and the fault reactivation potential on the host rock and fault properties, spacing between the fault and the HF, and the fracturing sequence. We find that fracturing in an anisotropic in-situ stress state does not lead to fault tensile opening but rather dominant shear reactivation through a poroelastic stress disturbance over the fault core ahead of the compressed central stabilized zone. In our simulations, poroelastic stress changes significantly affect fault reactivation in all the simulated scenarios of fracturing 50–200 m away from an optimally oriented normal fault. Asymmetric HF growth due to the stress shadowing effect of the adjacent HFs leads to (1) a larger reactivated fault zone following the simultaneous and sequential fracturing of multiple clusters compared with single-cluster fracturing and (2) a larger unstable area ([Formula: see text].1) over the fault core or a higher potential of the fault slip following sequential fracturing compared with simultaneous fracturing. The fault reactivation area is further increased for a fault with lower conductivity and a higher opening-mode fracture toughness of the overlying layer. To reduce the risk of fault reactivation by hydraulic fracturing under the reservoir characteristics of the Barnett Shale, Fort Worth Basin, it is recommended to (1) conduct simultaneous fracturing instead of sequential and (2) maintain a minimum distance of approximately 200 m for HF operations from known faults.

Formational stages of natural fractures revealed by U-Pb dating and C-O-Sr-Nd isotopes of dolomites in the Ediacaran Dengying Formation, Sichuan Basin, southwest China

Deep core (>4.9 km) from Ediacaran Deng IV Member algal dolomites in the Gaoshiti-Moxi block in the Sichuan Basin, southwest China, reveals multiple generations of dolomite-lined and dolomite-filled opening-mode fractures. Three progressive stages of fracture formation are marked by crosscutting relations visible in the core, by acoustic emission experiments revealing evidence of past stress directions, and by fluid inclusions, U-Pb ages, C-O-Sr-Nd isotope patterns, and rare earth element data for dolomite cements in fractures, which document ages and differing thermal conditions and fluid compositions during fracture. In calcite-filled fractures, U-Pb ages and carbon and oxygen isotope signatures vary greatly, indicating that fractures developed with intensified tectonic activity marked by regional structures and with enhanced diagenetic alteration. In stage I, WNW-striking opening-mode fractures formed that contain dolomite deposits precipitated from basinal fluids between ca. 549 Ma and ca. 532 Ma. At this time, the Sichuan Basin experienced Xingkai taphrogenesis (rifting) from the late Neoproterozoic to early Cambrian. The central Sichuan paleo-uplift was undergoing ENE extension, and preexisting ESE- and nearly E-W−striking faults were oblique to the ENE principal stress orientation. This led to a local stress field favoring dextral shear near fault zones accommodated by the fractures. In stage II, ENE-striking fractures that are younger based on crosscutting relations contain dolomite deposits from basinal fluids with ages from ca. 423 Ma to ca. 411 Ma. Contemporaneous with Xuefeng thrusting, the central Sichuan paleo-uplift was in a NNE-striking transpressional stress field, which likely further generated ENE-striking fractures. In stage III, nearly N-S−striking fractures formed in the Gaoshiti-Moxi block. High-temperature fluids related to the Permian Emeishan large igneous province invaded these fractures from ca. 260 Ma to ca. 256 Ma. At this time, the Sichuan Basin was uplifted under the influence of the Emei taphrogenesis in the late Permian, and the central Sichuan paleo-uplift was subjected to E-W−striking extension. In fractures in these carbonate rocks, micro-computed tomography imaging reveals that macropores (>10 μm, 12.1%−21.8%) and small pores (2−10 μm, 76.6%−86.1%) dominate the dolomite mineral deposits, and that there are few (1.6%−1.8%) micropores or nanopores (<2 μm). Medium-sized throats (1−3 μm) are the main connecting channels. We infer that fractures served as conduits for fluid migration, leading to the dissolution of matrix pores adjacent to the fractures. This secondary porosity not only enhances reservoir storage capacity but also augments reservoir connectivity. Our study shows that in situ U-Pb dating and full-diameter rock acoustic emission data can effectively constrain the timing of fractures. By integrating this information with regional tectonic sequences and fracture diagenetic sequences from combined relative timing, geochemistry, and rock mechanics evidence, we clarify the factors controlling fracture formation.

Fracture ellipticity as a measure of chemical reaction-controlled fracture growth

Fracture ellipticity as a measure of chemical reaction-controlled fracture growth

3D-printed highly stretchable curvy sandwich metamaterials with superior fracture resistance and energy absorption

This paper focuses on the potential of curvy mechanical metamaterials to show how topological design can significantly enhance fracture toughness along the in-plane and out-of-plane (through-depth) directions. The conventional re-entrant unit cell is first reformulated by introducing local curvy ligaments and then additively manufactured by three-dimensional (3D) printing to form a center/edge-notch lattice metamaterial. The new conceptual design provides multi-stiffness unit cells, helping to control stress distribution within a structure under tensile load, specifically in the vicinity of the notches where stress concentrations occur. In other words, curvy unit cells are capable of arresting and blunting the notch under tensile loads and toughening the metamaterials. The crack tip opening displacement (CTOD) method calculates the fracture toughness. Not only can the fracture of lattice metamaterials be controlled along the in-plane direction by replacing unit cells in the sensitive parts of the metamaterials, but a new assembly method is also proposed. This offers that different thin plates of metamaterials with different layouts can be sandwiched to control out-of-plane fracture propagation (through-depth propagation of opening mode fracture) for the first time in fracture mechanics. This novel sandwiching method offers a multi-step fracture and significantly improves the fracture behavior of the lattice metamaterials from brittle to ductile by taking advantage of multiple through-thickness thin plates instead of considering one thick specimen. A detailed analysis of the effects of the ligament curvature value on the fracture behavior is presented. The results reveal that the more curvature, the more extension (ductility) will be realized, but too large curvature design can provide lower energy absorption capacity.

Formation of natural fractures and their impact on shale oil accumulation in the Mahu Sag, Junggar Basin, NW China

Lacustrine shale oil reservoirs of the Fengcheng Formation in the Mahu Sag, Junggar Bain, NW China contain abundant oil resources, with the highest daily oil production of a single well reaching over 700 barrels. Based on core and thin section observation along with borehole image interpretation, this study integrated paleotectonic stress regime, fluid inclusion analysis, and calcite UPb dating to clarify fracturing periods and discuss the influence of fractures on shale oil accumulation. Results show that natural opening-mode fractures are widespread in the Fengcheng Formation, which play an important role in oil accumulation. Fractures are developed in several stages and filled by three minerals: reedmergnerite, quartz and calcite. Reedmergnerite and quartz fillings show similar fluid inclusions and petrographic features, with numerous hydrocarbon inclusions compared to aqueous ones, yet, such inclusions were less observed in calcite fillings. Fractures in the study area were formed in two separate stages. In the first period, due to the NW-SE compression of the Hercynian movement, the WNW-ESE and NNW-SSE striking fractures were formed in the Late Permian, with Th values of 95–115 °C. The first stage of fractures coincided with hydrocarbon generation, providing migration pathways for the oil. In the second period, due to the nearly SN compression of the Indosinian movement, the NNW-SSE and NNE-SSW striking fractures were formed in the late Triassic, with Th values of 120–140 °C. The second stage of fractures was formed subsequent to major hydrocarbon generation and expulsion period, hence their contribution to hydrocarbon migration and accumulation was found relatively minor. Moreover, fractures with the nearly E-W, ENE-WSW and WNW-ESE strikes intersect with the present-day maximum horizontal principal stress at a small angle, with large apertures and good connectivity, which should have a positive impact on shale oil accumulation.

Open fracture clustering: Integrating subsurface and outcrop analogues, Asmari Formation, SW Iran

Fracture networks play a significant role in controlling fluid flow in carbonate reservoirs. Here we have utilized a modern and rigorous technique known as normalized correlation count (NCC) to investigate the 1D spatial arrangement and size distribution of conductive opening-mode fractures in the Asmari Formation, a naturally fractured carbonate reservoir in the Zagros Fold and Thrust Belt. To overcome subsurface sampling limitations, here we integrate data from a subsurface fault-related fold called the Gachsaran anticline, and from adjacent outcrops. The Oligo-Miocene Asmari Formation is composed of three units with different lithology, thickness, and stratal geometry. Subsurface and outcrop data from the Asmari Formation have different patterns of spatial arrangements. While the fractures from outcrop anticlines show indistinguishable from random arrangements, the subsurface scanlines from the Gachsaran anticline have various clustering patterns, from self-organized regularly-spaced fracture clustering in the backlimb to externally-imposed clustering in the forelimb. The NW-SE striking fracture set in outcrops and subsurface show clustering. Aperture-size data for all fracture sets are best-fit by log-normal distributions, but sampling biases against the smallest apertures may obscure a power-law aperture-size distribution. Forcing the power-law fit to aperture-size distribution indicates steeper slopes in the backlimb and gentler slopes in the forelimb, which reflect lower and higher strain, respectively. This is consistent with higher tendency of clustering in the forelimb of the anticline which correlates with higher productivity index. Our results demonstrate the ability of NCC to identify hierarchical fracture clusters as well as to distinguish between self-organized and extrinsic organization. The results of quantitative analysis of fracture clustering and patterns in the Asmari Formation provides valuable insights that can aid in the refinement of Discrete Fracture Network (DFN) models and help make informed decisions regarding fractured reservoir development and production.

Deep and ultra-deep basin brittle deformation with focus on China

This volume describes progress in understanding brittle structures in deep and ultra-deep (>4 km to > 7 km) sedimentary basins. Under deep conditions in sandstone, carbonate rocks, shale, and other rocks, fluid charge and resource recovery are sensitive to faults and opening-mode fractures. In China, work is in progress on deep, deformed, and tectonically active basins including drilling of wells expected to exceed 10 km in depth. Papers describing fractures in horizontal wells indicate locally highly clustered spatial arrangements. Orientation patterns record protracted superposed deformation. Despite deep settings, open fractures are abundant, and wide (>1 mm) fractures with varying amounts of sealing calcite are common. Differences in cement abundances are due to the diagenetic history of fractures, not their origins (e.g., tectonic loading or elevated pore fluid pressure). In carbonate rocks, solution enhanced strike-slip faults and fractures with cavernous porosity are present, and in sandstone enigmatic enhanced host-rock porosity halos a few mm wide locally surround sealed fractures. Owing to differences in thermal exposure due to recent (>6 Ma to present) rapid deep burial (in some cases >2000 m) and locally low geothermal gradients, some fractures at great depths are less diagenetically altered than those at shallower depths in the North American Cordillera. Contrasts in diagenesis may affect fracture size, spatial arrangement, and connectivity.

Characteristics and controlling factors of natural fractures in deep lacustrine shale oil reservoirs of the Permian Fengcheng Formation in the Mahu Sag, Junggar Basin, China

Maximum burial depth of the Permian Fengcheng Formation, which contains significant oil resources in the Mahu Sag, exceeds 4500 m constituting a deep reservoir. Fractures are widespread in the deep lacustrine shale, providing important storage space and fluid conduits. Based on cores, borehole image logs, and petrographic analysis, we identified and analyzed the types and characteristics of fractures and conducted X-ray diffraction (XRD) and Cathodoluminescence (CL) tests to investigate the factors influencing fracture development. We found faults and three types of opening-mode fractures: bed-bounded fractures, unbounded fractures and bed-parallel fractures. Mechanical stratigraphy (depositional rock types modified by diagenesis) and proximity to faults, are main controls of opening-mode fracture occurrence and attributes. Specifically, Dolomitic mudstone with a high carbonate content shows the highest fracture density of 5.24 m-1. Bed-bounded fractures are mainly developed within brittle layers, with fracture density lower in thicker beds. On the other hand, unbounded (tall) fractures primarily occur near reverse faults (0–1500 m), with orientations parallel to extension directions implied by the kinematics of nearby faults. Additionally, the effectiveness of early-formed fractures as fluid conduits is likely modified (reduced) by cementation and enhanced by dissolution. Fractures have a positive influence on oil production, corresponding to high fracture density and aperture in the vertical direction.

Using in-situ strain measurements to evaluate the accuracy of stress estimation procedures from fracture injection/shut-in tests

Fracture injection/shut-in tests are commonly used to measure the state of stress in the subsurface. Injection creates a hydraulic fracture (or in some cases, opens a preexisting fracture), and then the pressure after shut-in is monitored to identify fracture closure. Different interpretation procedures have been proposed for estimating closure, and the procedures sometimes yield significantly different results. In this study, direct, in-situ strain measurements are used to observe fracture reopening and closure. The tests were performed as part of the EGS Collab project, a mesoscale project performed at 1.25 and 1.5 km depth at the Sanford Underground Research Facility. The tests were instrumented with the SIMFIP tool, a double-packer probe with a high-resolution three-dimensional borehole displacement sensor. The measurements provide a direct observation of the fracture closure signature, enabling a high-fidelity estimate of the fracture closure stress (ie, the normal stress on the fracture). In two of the four tests, injection created an opening mode fracture, and so the closure stress can be interpreted as the minimum principal stress. In the other two tests, injection probably opened preexisting natural fractures, and so the closure stress can be interpreted as the normal stress on the fractures. The strain measurements are compared against different proposed methods for estimating closure stress from pressure transients. The shut-in transients are analyzed with two techniques that are widely used in the field of petroleum engineering – the ‘tangent’ method and the ‘compliance’ method. In three of the four tests, the tangent method significantly underestimates the closure stress. The compliance method is reasonably accurate in all four tests. Closure stress is also interpreted using two other commonly-used methods – ‘first deviation from linearity’ and the method of (Hayashi and Haimson, 1991). In comparison with the SIMFIP data, these methods tend to overestimate the closure stress, evidently because they identify closure from early-time transient effects, such as near-wellbore tortuosity. In two of the tests, microseismic imaging provides an independent estimate of the size of the fracture created by injection. When combined with a simple mass balance calculation, the SIMFIP stress measurements yield predictions of fracture size that are reasonably consistent with the estimates from microseismic. The calculations imply an apparent fracture toughness 2-3x higher than typical laboratory-derived values.

Fracture-pattern growth in the deep, chemically reactive subsurface

Arrays of natural opening-mode fractures show systematic patterns in size and spatial arrangement. The controls on these factors are enigmatic, but in many cases the depth of formation appears to be critical. Physical, potentially depth-dependent factors that could account for these variations include confining stress, fluid pressure, and strain rate; these factors are common inputs to existing fracture models. However, temperature-dependent chemical processes likely exert an equally important control on patterns, and such processes have not yet been rigorously incorporated into models of fracture formation. Here we present a spring-lattice model that simulates fracturing in extending sedimentary rock beds, while explicitly accounting for cementation during opening of fractures, and for rock failure via both elastic and time-dependent failure criteria. Results illustrate three distinct fracturing behaviors having documented natural analogs, which we here term fracture facies. “Exclusionary macrofracturing” occurs at shallow levels and produces large, widely spaced, uncemented fractures; “multi-scale fracturing” occurs at moderate depth and produces partially cemented fractures having a wide range of sizes and spacings; and “penetrative microfracturing” occurs at great depth and produces myriad narrow, sealed fractures that are closely and regularly spaced. The effect of depth is primarily to accelerate both dissolution and precipitation reactions via increased temperature and porewater salinity; the specific depth range of each fracture facies will vary by host-rock lithology, grain size, strain rate, and thermal history.

Numerical investigation of interactions between hydraulic and pre-existing opening-mode fractures in crystalline rocks based on a hydro-grain-based model

Hot dry rock (HDR) is deep geothermal reservoir rock predominantly containing granite, whose physical and mechanical properties are governed by heterogeneous crystal structures. However, the fluid conductivity of intact granite with ultra-low permeability cannot be reformed using existing techniques. Complex fracture networks must be created by connecting hydraulic fractures with natural fractures developed in reservoirs. In this study, we introduce the wall barrier method into the novel hydro-grain-based model (hydro-GBM) to build a prefractured granite model at the mineral grain scale. This model enables investigation of the effects of the stress environment, mineral spatial distribution, and fluid injection rate on hydraulic fracturing characteristics. Microcracks around the inner tips of pre-existing fractures reproduce the initiation, propagation, and coalescence behaviors similar to experimental results. Mineral spatial distributions induce random changes in the propagation paths of hydraulic fractures. Increasing the fluid injection rate delays the deflection of hydraulic fractures and extends the propagation distance along the major axes of pre-existing fractures. The average activity level and proportion of large seismic events are reduced by injecting low-rate fluid. In summary, our results reveal the interactions between hydraulic and pre-existing fractures and provide a valuable reference for constructing an efficient enhanced geothermal system (EGS) for deep reservoirs.

Reservoir quality evaluation and prediction in ultra-deep tight sandstones in the Kuqa depression, China

Core, thin sections, cathodoluminescence (CL), scanning electron microscopy (SEM), conventional well logs and image logs are used to unravel depositional microfacies, diagenetic facies and fractures in the deeply buried (6000–8100 m) Cretaceous Bashijiqike (K1bs) and Baxigai (K1bx) Formations in Kuqa depression of the Tarim Basin. Results show that depositional microfacies in core and well log data include distributary channel, river mouth bar and distributary bay deposits of fan-braided delta fronts as well as lacustrine deposits. We establish well log predictable models of depositional microfacies using conventional and image logs. The Cretaceous sandstones experienced low to medium mechanical compaction and low intensity dissolution. Dominant diagenetic minerals are carbonate cements, clay minerals and minor amounts of quartz cements. The pore spaces are primarily intergranular pores and rare dissolution pores. We identify three diagenetic facies according to compaction state and diagenetic minerals, including carbonate cemented facies, tightly compacted facies, and facies having limited compaction and lacking cement (slightly cemented and compacted facies). We use well log characteristics to interpret diagenetic facies in areas without core data. Fractures are also elements of reservoir quality, including vertical opening-mode fractures, high to medium dip angle fractures, low angle fractures that probably include small faults and horizontal fractures. Fractures include open, partially open, and closed (sealed) fractures. We used image logs to identify fracture attributes, and calculate fracture density, porosity, aperture, and length. Depositional microfacies and diagenetic facies determine the primary intergranular pores and diagenesis subsequently modified secondary pore spaces. Natural fractures acted as both reservoir porosity (probably less than 1%) and as hydrocarbon flow channels accounting for elevated permeability. We evaluate and predict reservoir quality by superposing depositional microfacies, diagenetic facies and fracture occurrence.

Formation of multi-stage and clustered fractures at 3.6–4.9 km in the Shizigou structure, SW Qaidam basin

In the Eocene Upper Xiaganchaigou Formation from depths of about 3.6–4.9 km in the Shizigou (SZG) Structure in the SW Qaidam basin, core and image logs reveal three fracture assemblages (A-C) comprising opening-mode fractures and faults. Assemblages are defined by structural style (groups of fracture types), and orientation patterns and thus kinematics and separated by relative timing by the unlithified rock style of deformation of assemblage A and fracture crosscutting relations between assemblages B and C. Correlation of fracture kinematics with the structural history of the basin suggests a multi-stage fracture population in the Shizigou Structure arising as a response to Eocene transtension, Miocene transpression, and Quaternary shortening under the influence of the Cenozoic evolution of two boundary faults, the Altyn Tagh Fault (ATF) and the Qimen Tagh-Eastern Kunlun Fault (QTEKF). To clarify the relation, we document formation process of multi-stage fractures in cores and their preferred orientations in log images in five wells. Using image logs from horizontal wells (Shi A and B) at ca. 3.7–3.9 km depth and statistical methods for quantifying spatial arrangement patterns, we identified statistically significant conductive fracture clusters; opening-mode fractures of the assemblage B are significantly hierarchically clustered. Combining fracture mode and their preferred orientations with reconstructed stress history, we propose that the deformation history of the fracture population is kinematically related to the Cenozoic activity of the ATF and the QTEKF. The initial stage of fracture formation is associated with Eocene strike-slip faulting along the ATF, followed by the Early Miocene initial transpressional faulting along the QTEKF and finally intensified shortening since the Quaternary, respectively.

Estimation of magma overpressure from partially exposed dykes - A new approach

We present a new method to estimate full length and maximum thickness of dykes from their partial exposures having at least one tip. The method is particularly applicable to dykes which originate as dominantly opening mode fractures. The idealized canonical model for Mode I fracture shows it to open up in the shape of an ellipse. We solve the equation of this ellipse using every possible combination of two points lying on the dyke margin measured from the observed tip to acquire the results. The method has been validated with observations made on felsic dykes found within intrusive porphyritic granitoids of Chotanagpur Granite Gneiss Complex (CGGC), Purulia, India which are completely exposed (showing tips at both ends) or have an exposed centre with at least one tip. The method has also been tested against published data collected from incomplete dyke outcrops found in the caldera walls of Miyake-jima volcano, Japan. Acquired results are found to be in good agreement with the ones estimated through a previously published method. The present method has been successfully employed to calculate the aspect ratios (maximum thickness/total length) of partially exposed mafic dykes emplaced within younger granite of Chitradurga Schist Belt, Western Dharwar Craton, India. We comment on the magma overpressure ranges and depth of origin of these dykes and on the fracture toughness of the host granite.

Scale-dependent fracture networks

Using examples of regional opening-mode fractures in sandstones from the Cambrian Flathead Formation, Wyoming, we show that quartz deposits preferentially fill fractures up to ca. 0.05 mm wide and fractures transition from being mostly sealed to mostly open over a narrow size range of opening displacements from 0.05 to 0.1 mm. In our example, although isolated (I-node) dominated networks have some trace connectivity, the effective connectivity for fluid flow is likely greatly reduced by quartz cementation. Trace connectivity at microscopic and outcrop scale is similar, but most porosity is found in outcrop-scale fractures. Near faults, trace connectivity increases as initially wide porous fractures preferentially shear and wing cracks form, increasing fracture intersections (Y-nodes). However, pore space is lost due to the development of microbreccia. Macro-scale trace connectivity increases, but porous connectivity diminishes and thus potential for fluid flow is markedly lower. Connectivity descriptions should include accurate measures of widths and lengths and use nodes that reflect scale and diagenesis. We propose new rule-based node descriptions to measure diagenesis sensitive connections within the context of current field practices. Under diagenetic conditions between ca. 50°C–250°C differential infill makes network porosity, and thus permeability and strength, scale dependent.