Low-angle Fractures Research Articles

Fracture stratigraphy in oil-rich shale of the Upper Xiaganchaigou Formation (upper Eocene), western Qaidam Basin

Natural fractures in wells from oil-rich shale of the Upper Xiaganchaigou Formation in Qaidam Basin, the largest Cenozoic sedimentary basin in the Tibetan Plateau, vary systematically by stratigraphic position, allowing reconstruction of fracture generation processes during regional tectonic deformation. Compacted fractures, layer-bounded fractures, and low-angle (or bed-parallel) fractures were widely identified in oil-rich shale cores obtained from vertical wells. The layer-bounded fractures can be subdivided into two sets: one prevalent in light-colored (low gamma-ray) stiff layers and arrested by dark-colored (high gamma-ray) compliant layers, the other set primarily confined to the dark-colored compliant layers. The strikes of layer-bounded fractures, revealed by horizontal well FMI logs, are dominantly N60°-80°E and N10°-30°E within the light and dark intervals respectively. These strikes are consistent with natural hydraulic fracturing of the light layers during the Oligocene and the dark layers during the Middle Miocene-Holocene, based on a regional anticlockwise rotation of the compressional strain orientation. The abutment of layer-bounded fractures against low-angle (or bed-parallel) fractures in dark layers implies that the low-angle fractures were hydraulically fractured under a vertical least compressive stress during the Early Miocene, which produced the most intense tectonic compression. Layer-bounded fractures generally remain unmineralized in the dark layers but were mineralized in the light layers, suggesting that fractures confined in light layers would not decrease the sealing capacity of the shale oil system and fractures confined in dark layers can increase the pore space of shale oil storage. The Oligocene and Early Miocene fractures represented mechanical flaws that affected the initiation of Middle Miocene-Holocene fractures, implying that all natural fractures may alter hydraulic fracture stimulations to some extent.

Formation mechanical mechanism of low-angle fractures in pre-salt carbonate reservoirs: a case study from Carboniferous KT-I formation of the NT oilfield in the eastern margin of the Precaspian Basin, Kazakhstan

Fracture is an important factor that affects the oil and gas productivity of carbonate reservoirs. Much researches have been done on the origin of high-angle fractures in carbonate reservoirs, but few efforts have been made on the genetic mechanical mechanism of low-angle fractures. Based on the seismic data, core data, conventional logging data and rock mechanics experimental data, combined with three-dimensional in situ stress field simulation methods, the features, formation geological conditions and genetic mechanical mechanism of low-angle fractures (LAFs) were analyzed by applying Coulomb–Moore criterion, Griffith criterion and non-coordination criterion. The proportion of the number of shear fractures is as high as 90.2%, while that of tensile fractures is only 9.8% in the study area. Shear fractures are mainly unfilled fractures, and tensile fractures are mainly partially filled fractures. The LAFs were formed in the second tectonic movement, in which the knee-fold structure with high in the west and low in the east developed in the study area. The buried depth of most parts of the KT-I formation is 800 m when the study area develops the knee-fold structure, with a maximum depth of 1800 m and a minimum buried depth of 70 m, and the dip angle of the steepest part of the stratum is about 20°. A large number of LAFs were formed in the study area under the joint influence of tectonics and abnormally high pressure of water, including near-horizontal LAFs in the non-weak fabrics section (type I low-angle shear fractures), the LAFs having a certain angle with bedding in the non-weak fabrics section (type II low-angle shear fractures) and near-horizontal LAFs in the weak fabrics section (type III low-angle shear fractures). The formation of type I and type II low-angle shear fractures follows the Coulomb–Moore criterion. Type I low-angle shear fractures are formed in strata with a certain dip angle, while type II low-angle shear fractures are formed in near-horizontal strata. Type III low-angle shear fractures are formed under the comprehensive influence of pre-existing weak fabrics and strong horizontal extrusion, which follows the non-coordination criterion. Low-angle tensile fractures are mainly caused by abnormally high pressure and reverse faults in the study area, following Griffith’s criterion. The research in this paper not only reveals the formation mechanical mechanism of LAFs in pre-salt carbonate reservoirs but also provides guidance for the prediction of LAFs and solving the problem of water channeling caused by LAFs in oil fields.

An Approach to Define and Quantify Porosity System in Heterogeneous Carbonate Reservoirs through Textural Analysis using High-Resolution Resistivity Image in the Bassein Formation of Mumbai Offshore Basin, India

Summary In evaluating the porosity system of the Bassein formation, high-resolution resistivity image (FMI) data have been used. Major features observed from the FMI data are the presence of low-angle fractures and solution channels of varying length and thickness. Against the layers with very-low-density neutron porosity, solution channels are seen as conductive features. These mud-filled solution channels can actively participate in production. Being very small-scale features, these types of porosities are not identifiable from conventional log data. To define and quantify porosity types such as vugs, solution channel, and matrix porosity, the resistivity image data are processed and image-based porosity is calculated. A core thin-section study is carried out and is used for calibration of the image-derived porosity system. Using resistivity image data, we have computed porosity types, for example, vugs, connected matrix and resistive, and their contribution to total porosity. Identification of hydrocarbons in reservoir layers with their porosity contribution (porosity partitioning) gives better insight into hydrocarbon production in these low-porosity layers which are producing after acid job.

Rock Mechanical Properties and Wellbore Stability of Fractured Dolomite Formations.

During the drilling process in the dolomite formation of the Leikoupo formation in western Sichuan, downhole obstruction frequently occurs, which seriously hinders the efficient development of oil and gas resources on site. In view of the problems of borehole stability existing in this type of formation, the geological characteristics, underground complexity, and fracture development of the research block were systematically identified and analyzed, and the physical parameters and mechanical properties of the rock were defined through physical and chemical tests and an understanding of the mechanical properties of the rock. These studies revealed the mechanism of borehole instability and the main factors influencing fractured dolomite formation. Finally, a model of borehole collapse pressure within fractured dolomite formation was established by selecting the appropriate strength criterion as the criterion of borehole instability. The results show that the dolomite fractures of the Leikoupo formation are relatively developed, the formation is dominated by low-angle fractures, and the core integrity is not high. The development of formation fractures has an obvious effect on the mechanical strength of rock, which decreases to different degrees with the decrease in the integrity coefficient of the rock mass, and the anisotropy of the rock's mechanical strength is obvious. The empirical parameters of the generalized Hoek-Brown (H-B) strength criterion were quantified by introducing rock mass acoustic data, and the accuracy of the improved generalized H-B strength criterion was evaluated using triaxial test data. Taking the M-C criterion, the generalized H-B criterion based on acoustic wave, the D-P criterion, and the weak surface strength criterion as wellbore instability criteria, combined with the distribution of wellbore stress, a prediction model of wellbore stability considering the degree of dolomite formation fragmentation was established. The results demonstrate that the generalized H-B criterion model based on acoustic waves can be used to evaluate the wellbore stability of dolomite fracture formation with more than one group of fractures. These research results have certain guiding significance for efficient and safe drilling in fractured dolomite formations.

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.

Characterization of natural fractures in tight sandstone reservoirs in Yuanba area, northern Sichuan Basin

Natural fractures are quite important for the high and stable production of tight sandstone gas reservoirs. However, it is commonly difficult to accurately characterize their distribution in tight sandstone gas reservoirs due to the strong heterogeneity. A comprehensive characterization of natural fractures in tight sandstone gas reservoirs of the Xujiahe Formation in the Yuanba area, Sichuan Basin, was carried out by multimethod of core description, log interpretation and seismic prediction. The results show that (1) the natural fractures in the Xujiahe Formation are mainly low-angle fractures, with a few medium- and high-angle fractures. The degree of fracture development is mainly controlled by the distance from the fault, the flexural degree of the strata and the thickness of the rock mechanical layer. (2) The fracture-sensitive seismic attributes such as the preferred maximum likelihood, structure entropy, illuminant-based symmetry and high-precision curvature are taken as the input, and the unsupervised cluster analysis algorithm based on Bayesian probability model is applied to predict the distribution of large-scale fractures at different dip angles; on the basis of narrow azimuthal pre-stack CMP gather optimization, the anisotropy detection technique of Hampson-Russell's ProAZ full CMP gather is used to characterize the distribution of small- and medium-scale fractures, and the predicted fracture development intensity matches the fracture interpretation results of the imaging logs by more than 85%. Moreover, the predicted fracture orientation is basically consistent with that of the imaging loggings. (3) The fault-genesis fractures of the Xujiahe Formation are mainly distributed near the fault on the southeast flank of the Jiulongshan anticline, and are distributed in a narrow strip in NE direction. The fold-genesis fractures are mainly developed in the Xu 3rd Member, and are located in the axis of the Jiulongshan anticline and its southeast flank where the strata are strongly flexed. This study provides a solid foundation for the development of tight sandstone gas reservoirs and extends the approaches for the accurate characterization of fractures.

Improved triple porosity model for calculating porosity exponent of fractured-vuggy reservoirs based on Maxwell-Garnett mixing rule and anisotropic conductivity analysis

Porosity exponent (m) is a key parameter for calculating reservoir oil and gas saturation and evaluating reservoir effectiveness; the development of matrix pores, vug pores, and fractures makes the m response regularity of fractured-vuggy reservoirs unclear, which makes the accurate calculation of saturation difficult. By applying Maxwell-Garnett mixing rule to vuggy reservoirs and conductivity tensor analysis to fractured reservoirs, an improved Triple Porosity Model considering fracture dip angle is established. The newly improved Triple Porosity Model clarifies the response regularity of m to the matrix pores, vug pores, fracture pores, and fracture angles. Based on the improved Triple Porosity Model, the response regularity chart of m is further established. The findings show that: (1) m increases with the increase of fracture dip angle (θ) and the development of vugs; (2) m increases with the development of high-angle fractures and decreases with the development of low-angle fractures; (3) in fractured reservoirs, the fracture dip angle of 33° is the critical dip angle that determines the relationship between m and matrix porosity exponent (mb); (4) an increase in matrix porosity will weaken the influence of vugs, fractures, and fracture dip angle on m, which will eventually make m converge to mb. The field application of fractured-vuggy reservoirs shows that the water saturation calculated by the improved Triple Porosity Model is better in agreement with the core analysis results.

A Novel Trilinear Flow Model for Capturing Dynamic Behavior of Water Flooding in Core Plug with Different Fracture Inclinations in Carbonate Reservoirs

Abstract The purpose of this study is to introduce a new three-linear flow model for capturing the dynamic behavior of water flooding with different fracture occurrences in carbonate reservoirs. Low-angle and high-angle fractures with different occurrences are usually developed in carbonate reservoirs. It is difficult to simulate the water injection development process and the law of water flooding is unclear, due to the large variation of the fracture dip. Based on the characteristics of water flooding displacement streamlines in fractured cores with different occurrences, the matrix is discretized into a number of one-dimensional linear subregions, and the channeling effect between each subregion is considered in this paper. The fractures are divided into the same number of fracture cells along with the matrix subregion, and the conduction effect between the fracture cells is considered. The fractured core injection-production system is divided into three areas of linear flow: The injected fluid flows horizontally and linearly from the matrix area at the inlet end of the core to the fracture and then linearly diverts from the fracture area. Finally, the matrix area at the outlet end of the core also presents a horizontal linear flow pattern. Thus, a trilinear flow model for water flooding oil in fractured cores with different occurrences is established. The modified BL equation is used to construct the matrix water-flooding analytical solution, and the fracture system establishes a finite-volume numerical solution, forming a high-efficiency semianalytical solution method for water-flooding BL-CVF. Compared with traditional numerical simulation methods, the accuracy is over 86%, the model is easy to construct, and the calculation efficiency is high. In addition, it can flexibly portray cracks at any dip angle, calculate various indicators of water flooding, and simulate the pressure field and saturation field, with great application effect. The research results show that the greater the fracture dip angle, the higher the oil displacement efficiency. When the fracture dip angle is above 45°, the fracture occurrence has almost no effect on the oil displacement efficiency. The water breakthrough time of through fractures is earlier than that of nonthrough fractures, and the oil displacement efficiency and injection pressure are more significantly affected by the fracture permeability. With the increase of fracture permeability, the oil displacement efficiency and the injection pressure of perforated fractured cores dropped drastically. The findings of this study can help for better understanding of the water drive law and optimizing its parameters in cores with different fracture occurrences. The three-linear flow model has strong adaptability and can accurately solve low-permeability reservoirs and high-angle fractures, but there are some errors for high-permeability reservoirs with long fractures.

Water Saturation Calculation and Fracture Type Identification of a Buried Hill Fractured Reservoir

Abstract A buried hill reservoir is a special type of bedrock reservoir, in which fractures are the important reservoir space and main percolation path. However, due to the characteristics of the buried hill reservoir such as deep burial depth and high formation pressure, the fracture width of deep formation is generally in micron level, and the randomness of spatial development brings great difficulties to logging identification and reservoir parameter calculation. Based on the fracture porosity and saturation model of the dual pore model, this paper puts forward the theory of identifying fracture type of buried hill fractured reservoir by using conductivity efficiency. The results show that (1) the fracture angle has no effect on the conductivity efficiency. And we cannot distinguish a high-angle fracture from a low-angle fracture by conductivity efficiency. (2) The values of porosity and water saturation are not directly related to the conductivity efficiency. But porosity and water saturation will affect the connectivity of water in the reservoir and indirectly affect the conductivity efficiency. (3) The conductivity efficiency of the network fracture is usually less than that of the dissolution fracture.

Fracture characterization in oil-based mud boreholes using image logs: example form tight sandstones of Lower Cretaceous Bashijiqike Formation of KS5 well area, Kuqa Depression, Tarim Basin, China

The natural fractures are dominated factors for the gas yield in deeply buried tight sandstones of Lower Cretaceous Bashijiqike Formation of KS5 well area, Kuqa Depression. For the high temperature and pressure environment, boreholes were drilled in oil-based mud. To characterize fractures in ultra-deep formation, electrical imagers (High-definition Formation MicroImager (FMI-HD), Earth Imager (EI), and Oil Base MicroImager (OBMI)) and acoustic imagers (Circumferential Borehole Imaging Log (CBIL) and Ultrasonic Borehole Imager (UBI)) were run in five oil-based mud openholes in KS5 well area. In this paper, fractures in different classifications were interpreted and compared in various borehole images. Opened and partially opened fractures were, respectively, continuous and discontinuous bright sinusoidal traces in electrical images. Closed fractures should be recognized by electrical and acoustic images cooperatively. In Bashijiqike Formation, opened and partially opened medium-angle, high-angle, and network fractures were well developed, while low-angle fractures were infrequent. Bashijiqike Formation might be divided into fractures well-developed, no-developed, and less-developed intervals upwards vertically. The strikes of fractures concentrated in nearly NWW-SEE, paralleled the strikes of major faults. This paper might help in understanding the complete vertical distributional characteristics of fractures in tight sandstones of Lower Cretaceous Bashijiqike Formation of KS5 well area and in turn on the exploration potential of petroleum systems.

Influence of internal textures in fracture development in dolostones: A case study in the Mesoproterozoic Wumishan Formation in the Jizhong Depression, Bohai Bay Basin, north China

Fractures provide pore spaces for the preservation and migration of hydrocarbons and control the quality of dolomitic reservoirs. Textures caused by sedimentary and tectonic processes control the mechanical properties of dolostones and the development and distribution of fractures in them. An understanding of the influence of textures present in dolostones in the development of fractures is crucial. Therefore, massive micritic, brecciated, columnar stromatolitic, and siliceous dolostones and laminites present in the early Mesoproterozoic Wumishan Formation (between ca. 1.5 Ga and ca. 1.45 Ga) in the Jizhong Depression with varying internal textures were analyzed based on observations of outcrops, core, and microstructures to determine their influence on reservoir quality. The development characteristics of fractures in the dolostones were investigated, and their petrophysical properties were measured. Uniaxial and triaxial compression tests were utilized to explore the impacts of textures on the distribution patterns of fracture in the dolostones. The fracture density, porosity, and permeability are 5.4/m, 1.55%, and 17.10 mD in the homogeneous and massive micritic dolostone, with fracture oriented parallel or at an acute angle to the maximum principal stress direction. The fracture density, porosity, and permeability, respectively, are characterized by averages of 8.9/m, 6.39%, and 106.68 mD, and are significantly better in the brecciated dolostones, and the fractures develop along the preexisting weakly cemented planes between the brecciated textures. The fracture density of the siliceous dolostone is 9.8/m, and its porosity and permeability are 2.74% and 29.68 mD. The extension of high-angle fractures is usually restrained by the low-angle bedding fractures, and intensive microcracks are developed in the siliceous textures. The occurrence of algal laminae in dolostones increases the proportion of low-angle fractures; these fractures can extend along the maximum principal stress direction and rupture along the weak algal laminae. The fracture density and petrophysical properties of columnar stromatolitic dolostones (7.4/m, 4.39%, and 87.75 mD) are better than those of laminites (4.3/m, 1.21%, and 14.57 mD). Therefore, the formative environment of textures in dolostones controls the quality of the reservoirs in the Wumishan Formation. The reservoirs in brecciated dolostones that are located in structural highs and fracture zones and columnar stromatolitic dolostones deposited in high-energy intertidal to upper subtidal zones have the highest reservoir quality. The quality of the reservoirs in siliceous banded dolostones deposited in mid-energy intertidal zones is average, and that of massive micritic dolostones and laminites deposited in low-energy lower-subtidal zones is poor.

Reservoir quality of tight oil plays in lacustrine rift basins: Insights from early Cretaceous fine-grained hydrothermal dolomites of the Erlian Basin, NE China

There has been increasing recognition of fine-grained dolomitic sediments in continental rift basins, but research has tended to focus on their petrography, geochemistry and genesis, rather than the pore characteristics that determine tight oil and gas reservoir quality. This paper presents a classification of pore types for dolomitic sediments influenced by hydrothermal processes from the early Cretaceous Erlian Basin, and examines relations between pore types to infer underlying genetic processes and controls as a precursor to predicting their distribution. We recognize three pore types: (1) primary porosity, which includes inter-crystalline pores between hydrothermal minerals within granules and nano-scale pores within fine matrix; (2) secondary dissolutional porosity, including inter-crystalline dissolved pores in granules, mouldic pores in laminae and bandings and selectively dissolved pores in argillaceous matrix, as well as large vugs in breccias; and (3) fracture porosity, including low-angle dissolved fractures, bedding-parallel microfractures and high-angle tectonic fractures. Both hydrothermal and hydrocarbon-related fluids caused significant dissolution, generating secondary pores that form the largest volume of reservoir storage. Channeling of aggressive fluids via low-angle fractures localized dissolution in the matrix and significantly enhanced permeability. Vertical fractures have a lesser impact on porosity but contribute to improved pore network connectivity. These relationships reflect dolomite accumulation within a tectonically-active extensional setting, with associated fault and fracture networks providing conduits for hydrothermal fluids. These fluids are responsible for formation of the dolomitic reservoir rocks and their diagenesis and may result in a characteristic suite of pore types. The high heat flux ensured rapid maturation of source rocks and may have played an important role in generating additional dissolutional porosity. Given the tight nature of reservoirs in such lacustrine systems, a systematic understanding of the nature and evolution of the pore network is key to identifying productive “sweet spots” in the vicinity of faults for de-risking future hydrocarbon exploration and also in developing such settings for geothermal energy.

Characterization of the weathered basement rocks in the Dongping field from the Qaidam Basin, Western China: significance as gas reservoirs

Reservoir quality is a critical risk factor in basement reservoirs. Researches into basement reservoirs by petrographic analysis combined with X-ray diffraction, log identification, electron microscopy, field emission scanning electron microscopy, porosity and pulse-decay permeability and core analysis have provided insights into the characterization of the commonality, diversity and difference of the weathered basement rocks as gas reservoirs in the Dongping field. Geological structures, lithology and near-surface processes control the reservoir physical property together. From Wellblock Dp 3 to Wellblock Dp 17, the high uplift gradually transforms into the low slope area towards the center of basin, with the lithology changing as well, which results in different degrees of fracture development in the bedrock in different wellblocks. The basement lithologies are granite, granitic gneiss, and limestone with slate in Wellblock Dp3, Dp1 and Dp17, respectively. Though they all provide effective reservoir space for gas accumulation, the productivity of nature gas shows significant differences. Fractures are the main store space in the three wellblocks. The development of fractures gives rise to secondary porosity around them because of physical weathering and chemical dissolution, but they generate many inhomogeneous fractures and secondary solution pores, whether on the planar distribution or in vertical. In Wellblock Dp3, high angle fractures were generated under the action of structural stress mechanism, with a large number of secondary pores. The porosity is between 0.1 and 23.2%. In Wellblock Dp 1, low angle fractures were the main storage space, with plenty of solution pores mainly in melanocratic minerals. The porosity is between 0.1 and 18.8%. In Wellblock Dp 17, where short and dense fractures developed, the porosity is between 0.1 and 10.3%. The data indicate that the granite in the uplift in Wellblock Dp3 has better reservoir properties due to the stronger physical weathering and chemical dissolution. As the porosity gradually decreases towards the slope and low-lying area, the more favorable exploration area should be the uplift and slope area in the depression area. However, the effective caprock developed locally in Wellblock Dp3, which affected the gas accumulation. Meanwhile, the reservoirs’ petrophysical properties showed distintive variation with different depths in different wellblocks. High productivity layers are under the 200 m, 100 m and 200 m depths from the top of the basement rocks in Wellblock Dp 3, Wellblock Dp 1 and Wellblock Dp 17, respectively. This suggestion in this study will be of significance for guiding oil and gas exploration in front of the Altun Mountains.

Hydrogeochemical zoning of uranium isotopes (<sup>234</sup>U/ <sup>238</sup>U) in the Southern Siberian paleocontinent: the role of the South Baikal reservoir in the groundwater formation

The southern deformed edge of the Siberian paleocontinent is studied for zoning the disturbance of 234 U/ 238 U cyclic equilibrium in groundwaters discharged to the accreted Khamardaban terrane. A relationship is established between vertical variations of 234 U/ 238 U ( ОА 4/8) activity ratios and the hydrogeochemical zoning of groundwaters. Lateral ОА 4/8 zoning of groundwaters in the basement rocks and sedimentary cover of the Siberian platform is described. It is emphasized that an important role is played by the water propagating from the South Baikal reservoir (SBR) ( ОА 4/8 = 1.95–1.99; U content = 0.44–0.46 μ g/L) under the shore of Lake Baikal. It is suggested that the lateral advancement of the SBR water is facilitated by the development of low-angle (weakened by rifting) fractures of the Angara thrust fault, as well as subvertical fractures in the shear zone of the Main Sayan Fault. Monitoring data on the study area show that the ratios of the groundwaters components vary in time due to Cherdyntsev – Chalov deformational effect, chemical interaction of the waters and evaporites, and mixing of the groundwaters with contrasting hydrogeochemical signatures.

Fracture characterization and detection in the deep Cambrian dolostones in the Tarim Basin, China: Insights from borehole image and sonic logs

Characterization and detection of natural fractures using well logs in ancient deeply buried dolostones with low matrix porosity are very difficult. Core description, thin section analysis, conventional well logs, borehole image and sonic logs are used to document distribution of fractures in deep Cambrian dolostones in the Tarim Basin, China. The SHmax (maximum horizontal stress) direction is determined from drilling induced fractures, borehole breakouts and shear wave birefringence. Natural fractures with various attributes (open to partly open to closed) and orientation (including dip angles) are recognized. Natural fractures are classified into closed fractures, partly closed fractures, vuggy fractures and open fractures, and they can be further classified into high angle fractures, low-medium dip angle fractures, and low angle or horizontal fractures. Natural fractures are mainly associated with the more brittle rocks (dolograinstone, fine-medium-coarse crystalline dolostones), while fractures in dolomicrites and evaporitic gypsums-bearing dolostones are rare.Open to closed fractures are recognized as dark to bright sine waves on image logs, and the presences of open fractures cause minor deviations on the DEN logs, but significant deviations in resistivity values, while AC will be significantly increased in front of fractures. The energy of sonic full-waveforms will be strongly attenuated in front of open fractures. Fractures with strike parallel to the SHmax tend to have large aperture and good connectivity, and are suggested to enhance hydrocarbon productivity. Dolostones adjacent to the deep faults are heavily fractured, and fractures act as the hydrothermal fluid flow pathways, facilitating dissolution process. The abundance of vuggy fractures, and enlargement of the pre-existing microfractures support that fractures had enhanced dissolution. The dissolution along fracture surfaces helps increase fracture porosity. The results of this study about subsurface fracture patterns and their distributions are important for the hydrocarbon exploration and production in the Cambrian dolostones in the Tarim Basin.

Mineral Filling Pattern in Complex Fracture System of Carbonate Reservoirs: Implications from Geochemical Modeling of Water-Rock Interaction

Much research has been conducted on physical and numerical modeling that focus on stress state and structural controls on subsurface geofluid flow, yet very few attempts have been made to discover and quantify the mineral precipitation/dissolution kinetics in complex fracture system such as Tarim Basin of China. We conducted a geochemical simulation study using the outcrop fracture networks in Ordovician carbonate rocks in Tabei Outcrop Area of Tarim Basin. Structural analysis, filling analysis within the fracture networks and surrounding rocks were used to constrain the generation and geochemical evolution of the geofluids. Using an advanced reactive transport simulation platform TOUGHREACT, a pertinent thermodynamic system was applied to establish the geological model of the fracture-surrounding rock, where the corresponding calcium carbonate (CaCO3) solution was configured to replace the deep saturated hydrothermal fluids. Different types of mineral parameters were considered with material balance and phase equilibrium calculation to perform numerical simulation of multi-field, e.g., pressure field, temperature field, seepage field and chemical field under formation conditions. The simulation results were consistent with field observations. The major findings of this simulation study include: (1) Along with fluid injection, local dissolution occurred within the fractures and matrix, but with the gradual saturation of calcium ions and the increasing pH value, considerable calcite precipitation occurred. (2) The dissolution/precipitation in different fractures was mainly affected by their structure and physical properties, resulting in changes in fluid flow rate, temperature, pressure and ion concentration over time. (3) In the same group, the degree of mineral filling of small-aperture fractures, low-angle fractures and shallow fractures was significantly higher than other types of fractures. (4) The better the connectivity between reticular fractures and the higher the linear density of fractures, the lower the mineral filling degree. (5) Dissolution phenomenon strengthened within large-aperture conjugated fractures gradually along the flow direction. The proposed methodologies in this study can be applied to model effective fracture filling of other deep reservoirs.

Experiments on nitrogen assisted gravity drainage in fractured-vuggy reservoirs

Abstract Visual models of fractured-vuggy reservoirs were designed and manufactured to conduct experiments of nitrogen assisted gravity drainage (NAGD). The impacts of flooding pattern, gas injection rate, well type, and displacement direction (vertical or horizontal) on development performances and remaining oil distribution were studied. The results show that during NAGD, the sweep scope is decided by the connections between producer and reservoir, and the local sweep efficiency is decided by fracture-vuggy configuration. The homogenous fractured reservoir has higher oil recovery, and the bigger the aperture of fracture is, the higher the recovery. The main regions of remaining oil due to poor connectivity and gas-oil gravity difference include blind fractures and vugs below the connected fractures, the bottom of vugs, and the narrow and low-angle fractures. The accumulation of remaining oil in the bottom of reservoir is easily formed and controlled by the connections between producers and reservoir. The higher the gas injection rate and the stronger the fracture heterogeneity, the earlier the gas channeling and the lower the oil recovery of the producer will be. Horizontal wells have the best development effect, so horizontal well can be applied in fractured-vuggy reservoirs without bottom water. Producers should be preferentially drilled at low structural position. Gas channeling firstly occurs in the producer at high structural position, and it should be shut in timely to improve the utilization of injected gas.

Evolution and characterization of fracture patterns: Insights from multi-scale analysis of the Buxa dolomite in the Siang Valley, Arunachal Lesser Himalayan fold-thrust belt

Fractures at different scales are an integral component of shallow crustal deformation associated with the progressive evolution of a fold-thrust belt (FTB). We characterize the evolution of fractures from the Buxa dolomite of the Main Boundary thrust (MBT) sheet in the frontal segment of the Arunachal Lesser Himalayan FTB. Regionally, the MBT sheet forms a fault-bend antiform. Based on unfolding of strata, early formed low- and moderate-angle fractures are interpreted to be pre-folding layer-parallel shortening structures, while the dominant late-stage high-angle fractures are inferred to have formed synchronous to folding, tracking the progressive deformation of the orogenic wedge. The high-angle fracture set is the dominant one at both outcrop and microscopic scales, forming ∼44% and ∼45% of the total number of fractures, respectively. Microfracture analysis indicates that ∼41% of the high-angle fractures, ∼22% of the moderate-angle fractures and ∼10% of the low-angle fractures form veins, respectively. Cumulative plots of fracture spacing values collected from outcrops and under the microscope reveal that this parameter is best described by power-law distributions that indicate scale-independence of fracture spacing. However, the coefficients of variation (Cv) of spacing of these high-angle fractures reflect scale-dependent clustering.

Characterization and formation mechanisms of fractures and their significance to hydrocarbon accumulation: A case study of Lower Ordovician mid-assemblage Formations in central Ordos Basin, China

The lower Ordovician mid-assemblage Formations in the central Ordos Basin of China host prolific gas resources, and most hydrocarbon reserves are stored in naturally-fractured reservoirs. Thus, fracture pathway systems may have a significant impact on reservoir performance. This article focuses on the core- and laboratory-based characterization of fractures. Through the developmental degrees, extended scale, output state and filling characteristics of various types of fractures, the results show that there are three distinct fracture types: 1) nearly vertical fractures, 2) oblique fractures, and 3) horizontal fractures. Based on a systematic study of the characterization of reservoir space, the main geologic setting of natural gas accumulation and the regional tectonic background, type 1 is mainly driven by the tectonic formation mechanism, and type 3 and parts of low-angle fractures in type 2 are induced by the diagenetic formation mechanism. While recovered paleopressure for methane-rich aqueous inclusions trapped in fracture-filling cement indicates that the fracture opening and growth are consistent with gas maturation and charge and such high-angle fractures in type 2 are caused by the compound formation mechanism. The fractures to hydrocarbon accumulation may play a more significant role in improving the quality of reservoir porosity. Furthermore, connected fractures, dissolved pores and cavities together constitute the three-dimensional pore-cave-fracture network pathway systems, with faults serving as the dominant charge pathways of highly pressurized gas in the study area. Our results demonstrate that protracted growth of a pervasive fracture system is not only the consequence of various formation mechanisms but also intrinsic to quasi-continuous accumulation reservoirs.

Reservoir architecture and fracture characterization of low-permeability sandstone reservoir: a case study of Biandong oilfield, Jinhu depression, northern Jiangsu Basin, China

Fracture is one of the most important factors through the whole process of low-permeability reservoir development. Biandong oilfield is a typical low-permeability fractured sandstone reservoir, and has stepped into high water cut stage; thus, the waterflooding effect is poor. Therefore, many contradictions such as high moisture content, decreasing production speed, and low recovery efficiency are becoming increasingly prominent, which have seriously hindered the sustainable development, and need to be solved urgently. However, few such studies on reservoir characterization in low-permeability fractured sandstone reservoir have been conducted in China. In this study, through comprehensive analysis on reservoir characterization and sedimentary environment, significant results are achieved. Three types of fracture occurrence are identified; they are high-angle fracture, low-angle fracture, and horizontal fracture, respectively. Two types of reservoir pore (primary porosity and secondary porosity) are recognized based on thin-section observation and analysis. The diagenetic stage of Biandong oilfield are divided into three stages, early A, early B, and late A, respectively. Finally, a regional discrete fracture network model is established with Fisher’s algorithm based on three-dimensional geological model. All the research results presented above can make a significant instructing function for making reservoir development plan and improving recovery efficiency.