In situ stresses and natural fractures in the Northern Perth Basin,Australia

Present-day stress orientations in the Northern Perth Basin have been inferred from borehole breakouts and drilling-induced tensile fractures observed on image logs from eight wells. Stress indicators from these wells give an east – west maximum horizontal stress orientation, consistent with stress-field modelling of the Indo-Australian Plate. Previous interpretations using dipmeter logs indicated anomalous north-directed maximum horizontal stress orientations. However, higher-quality image logs indicate a consistent maximum horizontal stress orientation, perpendicular to dominant north – south and northwest – southeast fault trends in the basin. Vertical stress was calculated from density logs at 21.5 MPa at 1 km depth. Minimum horizontal stress values, estimated from leak-off tests, range from 7.4 MPa at 0.4 km to 21.0 MPa at 0.8 km depth: the greatest values are in excess of the vertical stress. The maximum horizontal stress magnitude was constrained using the relationship between the minimum and maximum horizontal stresses; it ranges from 8.7 MPa at 0.4 km to 21.3 MPa at 1 km depth. These stress magnitudes and evidence of neotectonic reverse faulting indicate a transitional reverse fault to strike-slip fault-stress regime. Two natural fracture sets were interpreted from image logs: (i) a north- to northwest-striking set; and (ii) an east-striking set. The first set is parallel to adjacent north- to northwest-striking faults in the Northern Perth Basin. Several east-striking faults are evident in seismic data, and wells adjacent to east-striking faults exhibit the second east-striking set. Hence, natural fractures are subparallel to seismically resolved faults. Fractures optimally oriented to be critically stressed in the present-day stress regime were probably the cause of fluid losses during drilling. Pre-existing north- to northwest -striking faults that dip moderately have potential for reactivation within the present-day stress regime. Faults that strike north to northwest and have subvertical dips will not reactivate. The east-striking faults and fractures are not critically stressed for reactivation in the Northern Perth Basin.     

The present-day stress field of New South Wales,Australia

The Australian continent displays the most complex pattern of present-day tectonic stress observed in any major continental area. Although plate boundary forces provide a well-established control on the large-scale (>500 km) orientation of maximum horizontal stress (S_Hmax), smaller-scale variations, caused by local forces, are poorly understood in Australia. Prior to this study, the World Stress Map database contained 101 S_Hmax orientation measurements for New South Wales (NSW), Australia, with the bulk of the data coming from shallow engineering tests in the Sydney Basin. In this study we interpret present-day stress indicators analysed from 58.6 km of borehole image logs in 135 coal-seam gas and petroleum wells in different sedimentary basins of NSW, including the Gunnedah, Clarence-Moreton, Sydney, Gloucester, Darling and Bowen–Surat basins. This study provides a refined stress map of NSW, with a total of 340 (A–E quality) S_Hmax orientations consisting of 186 stress indicators from borehole breakouts, 69 stress measurements from shallow engineering methods, 48 stress indicators from drilling-induced fractures, and 37 stress indicators from earthquake focal mechanism solutions. We define seven stress provinces throughout NSW and determine the mean orientation of the S_Hmax for each stress province. The results show that the S_Hmax is variable across the state, but broadly ranges from NE–SW to ESE–WNW. The S_Hmax is approximately E–W to ESE–WNW in the Darling Basin and Southeastern Seismogenic Zone that covers the west and south of NSW, respectively. However, the present-day S_Hmax rotates across the northeastern part of NSW, from approximately NE–SW in the South Sydney and Gloucester basins to ENE–WSW in the North Sydney, Clarence-Moreton and Gunnedah basins. Comparisons between the observed S_Hmax orientations and Australian stress models in the available literature reveal that previous numerical models were unable to satisfactorily predict the state of stress in NSW. Although clear regional present-day stress trends exist in NSW, there are also large perturbations observed locally within most stress provinces that demonstrate the significant control on local intraplate sources of stress. Local S_Hmax perturbations are interpreted to be due to basement topography, basin geometry, lithological contrasts, igneous intrusions, faults and fractures. Understanding and predicting local stress perturbations has major implications for determining the most productive fractures in petroleum systems, and for modelling the propagation direction and vertical height growth of induced hydraulic fractures in simulation of unconventional reservoirs.     

Hyperspectral logging of middle Cambrian marine sediments with hydrocarbon prospectivity: a case study from the southern Georgina Basin,northern Australia

The Georgina Basin is a Neoproterozoic–Paleozoic basin that spans parts of the Northern Territory and Queensland in northern Australia. The basin is prospective for petroleum, phosphate and base metals (copper, lead and zinc). The Dulcie and Toko synclines in the southern part of the basin are prospective for petroleum, where a thick Cambro-Ordovician succession of marine carbonates hosts several source rocks and associated oil and gas shows. The key source rock units occur within the middle Cambrian Narpa Group, including both the Thorntonia Limestone (Series 2 and 3) and the Arthur Creek Formation (Series 3). The base of the Arthur Creek Formation is characterised by organic-rich ‘hot’ shales (associated with a prominent gamma spike in well logs) that have been targeted by petroleum explorers for both conventional and unconventional oil and gas. For this study, hyperspectral logging data collected by HyLogger? instruments were evaluated from 13 wells in the southern Georgina Basin, including petroleum, mineral and stratigraphic wells. Formation boundaries are commonly (but not always) characterised by distinctive changes in mineralogy, as determined by spectral and X-ray diffraction data. Key source rock units in the southern Georgina Basin were characterised and mapped in terms of their mineralogy, and other spectral properties (e.g. Short-Wave Infrared (SWIR) reflectance and spectral contrast). Interpretation of the hyperspectral data alongside wireline log data supports the differentiation of two successions within the Arthur Creek Formation that are each characterised by basal organic-rich shales, previously distinguished on the basis of biostratigraphic and well-log data. The older succession in the Dulcie Syncline is spectrally characterised as being quartz and carbonate dominated. The younger succession, distributed across the eastern part of the Dulcie Syncline and fully across the Toko Syncline, is spectrally characterised as quartz and carbonate dominated, with variable white-mica contributions. Key associations are observed between the HyLogger mineralogy and geophysical-log data. Peaks in the gamma log intensity in the middle Cambrian sediments commonly correspond to elevated measured total organic carbon contents, decreased carbonate contribution, SWIR reflectance and spectral contrast, and relatively increased proportions of white micas and quartz. This study demonstrates that HyLogging data can provide an improved understanding of the sedimentological, mineralogical and diagenetic characteristics, as well as associated spatial heterogeneity, of prospective hydrocarbon formations in sedimentary basins.     

Shallow geothermal regime in the Perth Metropolitan Area

Exploration of Perth's geothermal potential has been performed by the Western Australian Geothermal Centre of Excellence (WAGCoE). Detailed vertical temperature and gamma ray logging of 17 Western Australia Department of Water's (DoW) Artesian Monitoring (AM) wells was completed throughout the Perth Metropolitan Area (PMA). In addition, temperature logs from 53 DoW AM wells measured in the 1980s were digitised into LAS format. The logged data are available in the WAGCoE Data Catalogue.

Analysis of the gamma ray logs yielded the first estimates of radiogenic heat production in Perth Basin formations. Values by formation ranged between 0.24 and 1.065 μW m^?3. The temperature logs provide a picture of true formation temperatures within shallow sediments in the Perth Basin. A three-dimensional model of the temperature distribution was used to produce maps of temperature at depth and on the top of the Yarragadee aquifer.

The temperature data were interpreted with a one-dimensional conductive heat model. Significant differences between the model and the observations was indicative of heat moving via non-conductive mechanisms, such as advection or convection. Evidence of non-conductive or advective heat flow is demonstrated in most formations in the region, with significant effects in the aquifers. Average conductive geothermal gradients range from 13°C km^?1 to 39°C km^?1, with sandstone formations exhibiting average gradients of approximately 25°C km^?1, while insulating silt/shale formations show higher average gradients of over 30°C km^?1.

To produce preliminary heat flow estimates, temperature gradients were combined with thermal conductivities measured elsewhere. The geometric mean heat flow estimates range between 64 mW m^?2 to 91 mW m^?2, with the standard deviation of the arithmetic mean heat flow ranging between 15 and 23 mW m^?2.

The study characterises the shallow temperature regime in the Perth Metropolitan Area, which is of direct relevance towards developing commercial geothermal projects.     

Geomechanical Characteristics of Gas Shales: A Case Study in the North Perth Basin

Gas shales are one type of unconventional reservoirs which have attracted significant attention for gas production in recent years. Gas production from very tight shales requires employment of hydraulic fracturing as a stimulation technique. To design hydraulic fracture operation the mechanical properties of the targeted and surrounding formations should be estimated. Also, the magnitude and orientation of in situ stresses in the field need to be known to estimate the fracture initiation and propagation pressures. This study focuses on gas shale characteristics in the North Perth Basin and uses data corresponding to well Arrowsmith-2 (AS-2) which is the first dedicated shale gas well drilled in Western Australia. A log-based analysis was used to build the rock mechanical model (RMM). The RMM results were used to set up a hydraulic fracturing laboratory experiment. The test was done in the presence of three principal stresses to mimic the real field stress conditions. The test results include the pressure–time curve which was used to estimate the initiation and propagation pressure at that depth. The results were used to draw some practical conclusions related to hydraulic fracturing operation in the field.     

Yanshanian–Himalayan geodynamic transformation of the northwestern Junggar Basin,southwestern Central Asian Orogenic Belt (CAOB), and its significance for petroleum accumulation

The northwestern Junggar Basin in the southwestern Central Asian Orogenic Belt is a typical petroliferous basin. The widely distributed reservoirs in Jurassic–Cretaceous strata indicate that the region records Yanshanian–Himalayan tectonic activity, which affected the accumulation and distribution of petroleum. The mechanism of this effect, however, has not been fully explored. To fill the knowledge gap, we studied the structural geology and geochemistry of the well-exposed Wuerhe bitumen deposit. Our results indicate that deformation and hydrocarbon accumulation in the northwestern Junggar Basin during the Yanshanian–Himalayan geodynamic transformation involved two main stages. During the Yanshanian orogeny, a high-angle extensional fault system formed in Jurassic–Cretaceous strata at intermediate to shallow depths owing to dextral shear deformation in the orogenic belt. This fault system connected at depth with the Permian–Triassic oil–gas system, resulting in oil ascending to form fault-controlled reservoirs (e.g., a veined bitumen deposit). During the Himalayan orogeny, this fault system was deactivated owing to sinistral shear caused by far-field stress related to uplift of the Tibetan Plateau. This and the reservoir densification caused by cementation formed favorable hydrocarbon preservation and accumulation conditions. Therefore, the secondary oil reservoirs that formed during the Yanshanian–Himalayan tectonic transformation and the primary oil reservoirs that formed during Hercynian–Indosinian orogenies form a total and complex petroleum system comprising conventional and unconventional petroleum reservoirs. This might be a common feature of oil–gas accumulation in the Central Asian Orogenic Belt and highlights the potential for petroleum exploration at intermediate–shallow depths.     

Geomechanical modelling of fault reactivation in the Cooper Basin,Australia

The Australian Cooper Basin is a structurally complex intra-cratonic basin with large unconventional hydrocarbon potential. Fracture stimulation treatments are used extensively in this basin to improve the economic feasibility; however, such treatments may induce fault activity and risk the integrity of hydrocarbon accumulations. Fault reactivation may not only encourage tertiary fluid migration but also decrease porosity through cataclasis and potentially compartmentalise the reservoir. Relatively new depth-converted three-dimensional seismic surveys covering the Dullingari and Swan Lake 3D seismic surveys were structurally interpreted and geomechanically modelled to constrain the slip tendency, dilation tendency and fracture stability of faults under the present-day stress. A field-scale pore pressure study found a maximum pressure gradient of 11.31 kPa/m within the Dullingari 3D seismic survey, and 11.14 kPa/m within the Swan Lake 3D seismic survey. The present-day stress tensor was taken from previously published work, and combined with local pore pressure gradients and depth-converted field-scale fault geometries, to conclude that SE–NW-striking strike-slip faults are optimally oriented to reactivate and dilate. High-angle faults striking approximately E–W appear most likely to dilate, and act as fluid conduits irrespective of being modelled under a strike-slip or compressional stress regime. Near-vertical SE–NW and NE–SW-striking faults were modelled to be preferentially oriented to slip and reactivate under a strike-slip stress regime. Considering that SE–NW-striking strike-slip faults have only recently been interpreted in the literature, it is possible that many reservoir simulations and development plans have overlooked or underestimated the effect that fault reactivation may have on reservoir properties. Future work investigating the likelihood that fracture stimulation treatments may be interacting, and reactivating, pre-existing faults and fractures would benefit field development programs utilising high-pressure hydraulic fracture stimulation treatments.     

Estimation of regional-scale groundwater flow properties in the Bengal Basin of India and Bangladesh

Quantitative evaluation of management strategies for long-term supply of safe groundwater for drinking from the Bengal Basin aquifer (India and Bangladesh) requires estimation of the large-scale hydrogeologic properties that control flow. The Basin consists of a stratified, heterogeneous sequence of sediments with aquitards that may separate aquifers locally, but evidence does not support existence of regional confining units. Considered at a large scale, the Basin may be aptly described as a single aquifer with higher horizontal than vertical hydraulic conductivity. Though data are sparse, estimation of regional-scale aquifer properties is possible from three existing data types: hydraulic heads, ¹⁴C concentrations, and driller logs. Estimation is carried out with inverse groundwater modeling using measured heads, by model calibration using estimated water ages based on ¹⁴C, and by statistical analysis of driller logs. Similar estimates of hydraulic conductivities result from all three data types; a resulting typical value of vertical anisotropy (ratio of horizontal to vertical conductivity) is 10⁴. The vertical anisotropy estimate is supported by simulation of flow through geostatistical fields consistent with driller log data. The high estimated value of vertical anisotropy in hydraulic conductivity indicates that even disconnected aquitards, if numerous, can strongly control the equivalent hydraulic parameters of an aquifer system.     

The resistivity structure of the Penola Trough,Otway Basin from magnetotelluric data

We present inversion results for a 100 site, broadband magnetotelluric (MT) survey in the Penola Trough, Otway Basin, South Australia. The Penola Trough is host to several petroleum reservoirs and has more recently been a target for unconventional geothermal exploration. We present two interpretations of the MT data. A 1D anisotropic interpretation, where anisotropy is determined within the Otway Basin sequence and basement in the northeastern Penola Trough, fits the impedance tensor well. However, the anisotropy strike is inconsistent with the known orientation of electrically conductive fractures in the Penola Trough. On the other hand, a 3D interpretation, which incorporates lateral variations in resistivity, requires no anisotropy yet it matches the data equally well. Both the 1D and 3D inversions resolve several layers within the Otway Basin sequence, which correspond to stratigraphic units defined in wells and in the coincident Haselgrove–Balnaves 3D seismic survey. These include the Eumeralla and Dilwyn formations, which are poorly resolved in the seismic data. The basin architecture, defined in the 3D inversion, in particular the depth to basement, is consistent with previous interpretations based on seismic reflection data that show that the Otway Basin thins in the northeastern Penola Trough. This does not occur in the anisotropic model. We therefore conclude that the subsurface resistivity appears to be isotropic in the Penola Trough. This contrasts with the anisotropic resistivity structure determined in a previous study in the Koroit region, eastern Otway Basin. The difference in the MT responses between the two regions is supported by resistivity and permeability information from well logs and may reflect differences in the orientation of subsurface fractures, or differences in the present-day stress field, between the two regions.     

Mesozoic–Cenozoic stress field magnitude in Sichuan Basin,China and its adjacent areas and the implication on shale gas reservoir: Determination by acoustic emission in rocks

The Sichuan Basin is one of the vital basins in China, boasting abundant hydrocarbon reservoirs. To clarify the intensity of the tectonic stress field of different tectonic episodes since the Mesozoic and to identify the regional dynamic background of different tectonic movements in the Sichuan Basin and its adjacent areas, the characteristics of the acoustic emission in rocks in different strata of these areas were researched in this paper. Meanwhile, the tectonic stress magnitude in these areas since the Mesozoic was restored. The laws state that the tectonic stress varied with depth was revealed, followed by the discussion of the influence of structural stress intensity on structural patterns in different tectonic episodes. These were conducted based on the paleostress measurement by acoustic emission method and the inversion principle of the stress fields in ancient periods and the present, as well as previous research achievements. The results of this paper demonstrate that the third episode of Yanshanian Movement (Yanshanian III) had the maximum activity intensity and tremendously influenced the structural pattern in the study area. The maximum horizontal principal stress of Yanshanian III varied with depth as follows: 0.0168 x + 37.001 (MPa), R² = 0.8891. The regional structural fractures were mainly formed in Yanshanian III in Xujiahe Formation, west Sichuan Basin, of which the maximum paleoprincipal stress ranging from 85.1 MPa to 120.1 MPa. In addition, the law stating the present maximum horizontal principal stress varies with depth was determined to be 0.0159 x+10.221 (MPa), R²=0.7868 in Wuling Mountain area. Meanwhile, it was determined to be 0.0221 x+9.4733 (MPa), R²=0.9121 in the western part of Xuefeng Mountain area and 0.0174 x+10.247 (MPa), R²=0.8064 in the whole study area. These research results will not only provide data for the simulation of stress field, the evaluation of deformation degree, and the prediction of structural fractures, but also offer absolute geological scientific bases for the elevation of favorable shale gas preservation.     

Sediment supply from the Betic-Rif orogen to basins through Neogene

We present a quantification of total and partial (divided by time slices) sedimentary volumes in the Neogene basins of the Betic-Rif orogen. These basins include the Alboran Sea, the intramontane basins, the Guadalquivir and Rharb foreland basins and the Atlantic Margin of the Gibraltar Arc. The total volume of Neogene sediments deposited in these basins is ~ 209,000 km³ and is equally distributed between the internal (Alboran Basin and intramontane basins) and the external basins (foreland basins and Atlantic Margin). The largest volumes are recorded by the Alboran Basin (89,600 km³) and the Atlantic Margin (81,600 km³). The Guadalquivir and Rharb basins amount 14,000 km³ and 14,550 km³, respectively whereas the intramontane basins record 9235 km³. Calculated mean sediment accumulation rates for the early-middle Miocene show an outstanding asymmetry between the Alboran basin (0.24 mm/yr) and the foreland basins (0.06-0.07 mm/yr) and the Atlantic Margin (0.03 mm/yr). During the late Miocene, sedimentation rates range between 0.17 and 0.18 mm/yr recorded in the Alboran Basin and 0.04 mm/yr in the intramontane basins. In the Pliocene-Quaternary, the highest sedimentation rates are recorded in the Atlantic Margin reaching 0.22 mm/yr. Sedimentary contribution shows similar values for the inner and outer basins with a generalized increase from late Miocene to present (from 3500 to 6500 km³/My). Interestingly, the Alboran Basin records the maximum sedimentary contribution during the late Miocene (5500 km³/My), whereas the Atlantic Margin does during the Pliocene-Quaternary (6600 km³/My). The spatial and time variability of the sediment supply from the Betic-Rif orogen to basins is closely related to the morphotectonic evolution of the region. The high sedimentation rates obtained in the Alboran Basin during the early-middle Miocene are related to active extensional tectonics, which produced narrow and deep basins in its western domain. The highest sedimentary contribution in this basin, as well as in the foreland and intramontane basins, is recorded during the late Miocene due to the uplift of wide areas of the Betics and Rif chains. The analysis of the sedimentary supply also evidences strong relationships with the post-Tortonian crustal thickening and coeval topographic amplification that occurred in the central Betics and Rif with the concomitant evolution of the drainage network showing the fluvial capture of some internal basins by rivers draining to the Atlantic Ocean (the ancestral Guadalquivir).     

敦——密断裂带吉林段断陷盆地石油地质条件及勘探方向

本文从敦--密断裂演化的角度分析吉林东部柳河、辉桦和敦化盆地的形成、演化及其石油地质条件。根据其对盆地发育的影响,断裂活动可分为3 个主要时期。初始断陷期: 敦密断裂的不均衡拉张使得柳河盆地下白垩统发育较好的湖相烃源岩,而辉桦、敦化盆地则以河流相--火山喷发为主。挤压隆起期: 区域白垩系全面抬升遭受剥蚀。晚期裂陷期: 断裂自南西向北东裂陷,辉桦盆地形成时间可能稍早于敦化盆地,盆地内古近系厚度较大,烃源岩条件也相对较好。综合对比分析认为,辉桦及敦化盆地具较好的石油地质条件,各盆地内大规模的常规油气富集可能性较小,但油砂和油页岩等非常规油气资源具有较大的潜力,下一步区域上应将非常规油气资源作为重点勘探方向。     

Shale Gas Formation and Occurrence in China: An Overview of the Current Status and Future Potential

Shale gas is one of the most promising unconventional resources both in China and abroad. It is known as a form of self-contained source-reservoir system with large and continuous dimensions. Through years of considerable exploration efforts, China has identified three large shale gas fields in the Fuling, Changning and Weiyuan areas of the Sichuan Basin, and has announced more than 540 billion m~3 of proven shale gas reserves in marine shale systems. The geological theories for shale gas development have progressed rapidly in China as well. For example, the new depositional patterns have been introduced for deciphering the paleogeography and sedimentary systems of the Wufeng shale and Longmaxi shale in the Sichuan Basin. The shale gas storage mechanism has been widely accepted as differing from conventional natural gas in that it is adsorbed on organic matter or a mineral surface or occurs as free gas trapped in pores and fractures of the shale. Significant advances in the techniques of microstructural characterization have provided new insights on how gas molecules are stored in micro- and nano-scale porous shales. Furthermore, newly-developed concepts and practices in the petroleum industry, such as hydraulic fracturing, microseismic monitoring and multiwell horizontal drilling, have made the production of this unevenly distributed but promising unconventional natural gas a reality. China has 10–36 trillion m~3 of promising shale gas among the world's whole predicted technically recoverable reserves of 206.6 trillion m~3. China is on the way to achieving its goal of an annual yield of 30–50 billion m~3 by launching more trials within shale gas projects.     

Semianalytical modeling on 3D stress redistribution during hydraulic fracturing stimulation and its effects on natural fracture reactivation

The hydraulic fracturing technique has been widely applied in many fields, such as the enhanced geothermal systems (EGS), the improvement of injection rates for geologic sequestration of CO₂, and for the stimulations of oil and gas reservoirs. The key points for the success of hydraulic fracturing operations in unconventional resources are to accurately estimate the redistribution of pore pressure and stresses around the induced fracture and predict the reactivations of preexisting natural fractures. The pore pressure and stress regime around hydraulic fracture are affected by poroelastic and thermoelastic phenomena as well as by fracture opening compression. In this work, a comprehensive semi-analytical model is used to estimate the stress and pore pressure distribution around an injection-induced fracture from a single well in an infinite reservoir. The model allows the leak-off distribution in the formation to be three-dimensional with the pressure transient moving ellipsoidically outward into the reservoir from the fracture surface. The pore pressure and the stress changes in three dimensions at any point around the fracture caused by poroelasticity, thermoelasticity, and fracture compression are investigated. With Mohr-Coulomb failure criterion, we calculate the natural fracture reactivations in the reservoir. Then, two case studies of constant water injection into a hydraulic fracture are presented. This work is of interest in the interpretation of microseismicity in hydraulic fracturing and in the estimation of the fracture spacing for hydraulic fracturing operations. In addition, the results from this study can be very helpful for the selection of stimulated wells and further design of the refracturing operations.     

利用室内和现场水压致裂试验联合确定地应力与岩石抗拉强度

钻杆式水压致裂原地应力测试系统的柔性会影响最大水平主应力的计算精度。利用空心岩柱液压致裂试验获得的岩石抗拉强度来取代重张压力计算最大水平主应力是降低钻杆式测试系统柔性的负面影响的重要途径。在福建某隧道深度为65 m的钻孔内开展了8段的高质量水压致裂原地应力测试,随后利用钻孔所揭露的完整岩芯开展了17个岩样的空心岩柱液压致裂试验。利用空心岩柱液压致裂所得的抗拉强度平均值为8.40 MPa,与经典水压致裂法确定的岩体抗拉强度8.22 MPa接近。对于20 m的范围内8个测段的原地应力量值,最小水平主应力平均值为8.41 MPa,基于重张压力P_r的最大水平主应力平均值为16.70 MPa;基于空心岩柱抗拉强度的最大水平主应力量值平均值为16.88 MPa,两种方法获得的最大水平主应力平均值基本一致。最大最小水平主应力与垂直主应力之间的关系表现为σ_H > σ_V > σ_h,这种应力状态有利于区域走滑断层活动。通过对比分析可知,对于钻杆式水压致裂原地应力测试系统,当测试深度小且测试系统柔性小时,基于重张压力和基于空心岩柱抗拉强度得到的最大水平主应力量值差别不大,这说明基于空心岩柱的岩石抗拉强度完全可以用于水压致裂最大水平主应力的计算,同时基于微小系统柔性的水压致裂测试系统获得的现场岩体强度也是可靠的。      

Marcellus Shale Lithofacies Prediction by Multiclass Neural Network Classification in the Appalachian Basin

Marcellus Shale is a rapidly emerging shale-gas play in the Appalachian basin. An important component for successful shale-gas reservoir characterization is to determine lithofacies that are amenable to hydraulic fracture stimulation and contain significant organic-matter and gas concentration. Instead of using petrographic information and sedimentary structures, Marcellus Shale lithofacies are defined based on mineral composition and organic-matter richness using core and advanced pulsed neutron spectroscopy (PNS) logs, and developed artificial neural network (ANN) models to predict shale lithofacies with conventional logs across the Appalachian basin. As a multiclass classification problem, we employed decomposition technology of one-versus-the-rest in a single ANN and pairwise comparison method in a modular approach. The single ANN classifier is more suitable when the available sample number in the training dataset is small, while the modular ANN classifier performs better for larger datasets. The effectiveness of six widely used learning algorithms in training ANN (four gradient-based methods and two intelligent algorithms) is compared with results indicating that scaled conjugate gradient algorithms performs best for both single ANN and modular ANN classifiers. In place of using principal component analysis and stepwise discriminant analysis to determine inputs, eight variables based on typical approaches to petrophysical analysis of the conventional logs in unconventional reservoirs are derived. In order to reduce misclassification between widely different lithofacies (for example organic siliceous shale and gray mudstone), the error efficiency matrix (ERRE) is introduced to ANN during training and classification stage. The predicted shale lithofacies provides an opportunity to build a three-dimensional shale lithofacies model in sedimentary basins using an abundance of conventional wireline logs. Combined with reservoir pressure, maturity and natural fracture system, the three-dimensional shale lithofacies model is helpful for designing strategies for horizontal drilling and hydraulic fracture stimulation.     

Geology and tectonic evolution of the Palaeoproterozoic Bryah, Padbury and Yerrida Basins (formerly Glengarry Basin), Western Australia: implications for the history of the south-central Capricorn Orogen

The Palaeoproterozoic Bryah, Padbury and Yerrida Basins are situated along the northwestern margin of the Archaean Yilgarn Craton, central Western Australia. These basins form part of the Capricorn Orogen, which developed between 2.0 and 1.8 Ga as a result of the collision between the Archaean Pilbara and Yilgarn cratons. The Bryah, Padbury and Yerrida Basins, which at the present day cover a total area of ca 20 000 km², were formerly considered as one geological entity, the Glengarry Basin. These three basins are characterized by distinct stratigraphy, igneous activity, structural and metamorphic history, and mineral deposit types. Igneous activity only affected the Bryah and Yerrida Basins, with voluminous eruptions of tholeiitic magma. In the Bryah Basin tholeiitic volcanic rocks are Mg-rich and have mixed MORB to oceanic island chemical signatures, but with a boninitic (subduction-related) component. In the Yerrida Basin tholeiites are Fe-rich and have chemical signatures that suggest a mixed tectonic environment ranging from oceanic to continental. It is considered possible that this tholeiitic magmatism is related to a mantle plume. Two models for the tectonic evolution of the Bryah, Padbury and Yerrida Basins are proposed: (1) the Bryah and Yerrida Basins were formed in a back-arc setting, whilst the Padbury Basin developed as a retro-arc foreland basin over the Bryah Basin; and/or (2) strike-slip transtension, during and following the Pilbara-Yilgarn collision, created the Bryah and Yerrida strike-slip pull-apart Basins. A change in regional stress regime resulted in the inversion of the basins and the development of a foreland basin in the northwest (Padbury Basin).     

In situ stress field of eastern Australia

New in situ data based on hydraulic fracturing and overcoring have been compiled for eastern Australia, increasing from 23 to 110 the number of in situ stress analyses available for the area between and including the Bowen and Sydney Basins. The Bowen Basin displays a consistent north‐northeast maximum horizontal stress (σ_H) orientation over some 500 km. Stress orientations in the Sydney Basin are more variable than in the Bowen Basin, with areas of the Sydney Basin exhibiting north‐northeast, northeast, east‐west and bimodal σ_H orientations. Most new data indicate that the overburden stress (σ_V) is the minimum principal stress in both the Bowen and Sydney Basins. The Sydney Basin is relatively seismically active, whereas the Bowen Basin is relatively aseismic. Despite the fact that in situ stress measurements sample the stress field at shallower depth than the seismogenic zone, there is a correlation between the stress measurements and seismicity in the two areas. Mohr‐Coulomb analysis of the propensity for failure in the Sydney Basin suggests 41% of the new in situ stress data are indicative of failure, as opposed to 13% in the Bowen Basin. The multiple pre‐existing structural grains in the Sydney Basin further emphasise the difference between propensity for failure in the two areas. Previous modelling of intraplate stresses due to plate boundary forces has been less successful at predicting stress orientations in eastern than in western and central Australia. Nonetheless, stress orientation in the Bowen Basin is consistent with that predicted by modelling of stresses due to plate boundary forces. Variable stress orientations in the Sydney Basin suggest that more local sources of stress, such as those associated with the continental margin and with local structure, significantly influence stress orientation. The effect of local sources of stress may be relatively pronounced because stresses due to plate boundary forces result in low horizontal stress anisotropy in the Sydney Basin.     

Kilometre‐scale sand injectites in the intracratonic Murzuq Basin (South‐west Libya): an igneous trigger?

Mount Telout, situated at the edge of the Murzuq Basin, is a 325 m high conical hill within a circular collapse structure that records 0·5 km³ of sand intrusion into Silurian shales. Based on a comparison with other similar circular collapse structures around the Murzuq Basin, it is argued that sand injection in the form of pipes occurred during the Devonian. The overpressures triggering the process are inferred to result from a combination of: (i) tectonic uplift at a basin scale that initially focused regional ground water flows; and (ii) igneous intrusion within the sand‐rich Cambrian–Ordovician strata. The palaeorelief buried under the regionally extensive Silurian shales may have locally focused overpressures and localized sand injection at the 1 to 10 km scale. The Mount Telout injected sandbody and related features offer exceptional, seismic‐scale outcrop analogues for sand injections that are often identified in seismic reflection data. Large‐scale sand injections might be essential in petroleum exploration of the North African Lower Palaeozoic basins as they form seal‐bypass systems.     

Joint clay–heavy–light mineral analysis: a tool to investigate the hydrographic–hydraulic regime of Late Cenozoic deltaic inland fans under changing climatic conditions (Cuvelai-Etosha Basin, Namibia)

An interdisciplinary study (major and minor elements, C and O isotopes, heavy and light minerals, phyllosilicates, wireline logs) in northern Namibia unraveled the hydrographic and hydraulic evolution of alluvial–fluvial sediments of the Kunene and Cubango megafans (Etosha-Cuvelai Basin). Three principal aquatic regimes were operative within the megafan complex: (1) the hydrographic regime, (2) the proximal hydraulic regime, (3) the distal hydraulic regime. The allogenic mineral assemblages mirror the hydrographic variation or drainage system and the lithological evolution of the fan sediments (alluvial–fluvial fan, lacustrine environment with evaporites, fan delta progradation). Authigenic heavy minerals are markers of the physical–chemical condition (Eh and pH values) of the hydraulic regime within the proximal fan at the basin margin. Authigenic heavy, light and clay minerals equally contribute to the determination of the fluid chemistry and temperature, as well as the source of chemical constituents of the former pore fluids percolating through the distal fan. Carbonatization was the most pronounced event in the distal hydraulic system and controlled by the presence of biogenic as well as atmospheric carbon. The isotope-based determination of the temperatures, albeit strongly fluctuating, do not exceed 40 °C. The overall pH values determined for the hydraulic regime within the distal fan range from slightly acidic to alkaline. The presence of zeolites attests to some short-lasting but strong deviations from the pH range, mainly towards more alkaline conditions. Heavy, light and clay mineral analyses proved to be a useful tool to determine the (paleo)hydrology of alluvial–fluvial fan systems in tropical arid to semiarid climates.