Characteristics Of Natural Fractures Research Articles

Wellbore instability in naturally fractured formations: Experimental study and 3D numerical investigation

Wellbore instability due to natural fractures is a significant issue impeding drilling operations in shale formations. However, most of the existing literature on wellbore stability analysis focuses on the coupled effects of fluid flow and deformation, and the impact of three-dimensional natural fracture characteristics on wellbore instability is not yet closely examined. This paper carried out a series of experiments to analyze the shale sample's fracture characteristics and shear strength. A fully coupled 3D hydro-mechanical model was then developed using the distinct element method (DEM) to investigate the wellbore instability. Finally, a comprehensive parametric study was performed to analyze the effects of characteristics of fractures (e.g., distribution density, fracture roughness and associated shear strength, dip angle, and seepage time) on wellbore stability under different in-situ stress states. The results show that the shear strength of shale increases with the increase in normal pressure (4 MPa, 6 MPa, and 8 MPa); the shear strength increases by 64.9% when the roughness is 0.325 mm (the largest increase among the three roughness cases). The maximum displacement around the wellbore is 1.3–1.5 times greater under the presence of weak planes than under no weak planes. Fracture roughness poses an important impact on wellbore stability because larger fracture roughness is associated with higher fracture shear strength. As the dip angle of the weak plane increases, the number of yield zones (shear failure) and maximum wellbore displacement increases and then decreases, and the peak occurs at the dip angle of 45°. The seepage time of drilling fluid is positively correlated with the number of yield zones around the wellbore, and the damage rate of drilling fluid to wellbore stability gradually decreases with the seepage time.

Predicting gas flow rate in fractured shale reservoirs using discrete fracture model and GA-BP neural network method

In the process of shale gas exploitation, the hydraulic fracturing technology is generally used to generate the stimulate reservoir volume (SRV). The network connectivity between natural fractures (NFs) and hydraulic fractures (HFs) significantly affects gas production rate in the hydraulic fracturing stage. To study the influence of natural fracture characteristics on gas flow behavior, a discrete fracture model considering matrix and fracture behaviors is developed. It is found that the increase of natural fracture permeability and distribution density leads to the increase of gas production rate, whereas large orientation angle may cause its decrease. To determine the nonlinear relationship between the natural fracture parameters and gas production rate, the method of back propagation (BP) neural network with genetic algorithm (GA) was applied to make intelligent prediction for the shale gas production. The gas flow rate values for different natural fracture parameters (e.g., permeability, density, orientation) were calculated by discrete fracture model, and used as input data for training and prediction in the GA-BP neural network. Results demonstrate the applicability of forecasting model, which is suitable for shale gas prediction during the operation of horizontal wells if more data profiles could be collected.

Numerical study failure characteristics of natural fracture under induced stress

Hydraulic fracturing is an effective method for developing oil and gas in unconventional reservoirs. The openings of natural fractures directly affect the complexity of the fracture body. The failure characteristics of natural fractures are critical factors in determining their activation by hydraulic fractures. Based on the three-dimensional displacement discontinuity method, a three-dimensional mechanical model of the interaction between hydraulic and natural fractures was established. Based on the shear and tensile failure criteria of the natural fractures, the failure characteristics of different natural fractures were clarified. Research has shown that the failure characteristics of natural fractures are influenced by factors such as three-dimensional stress, spatial distribution, and roughness. After the hydraulic fractures pass through the natural fractures, tensile and shear failures occur simultaneously; the failure of natural fractures is primarily affected by their strike and dip angles. During the process of hydraulic fracture approximation, the shear stress increases as the distance between the hydraulic fracture tip and natural fracture decreases. When the strike angle of the natural fractures near the tips of the hydraulic fractures was greater than 35°, the stress became consistent. As the dip angle of the natural fractures increased, the lowest point of the shear stress gradually moved from the upper to the lower half. This research studies the tensile and shear failure of natural fractures under different conditions, in order to facilitate engineering judgment of the types and characteristics of natural fracture failure. It is of great significance for us to understand the formation mechanism of complex fracture network morphology in volume fracturing.

The role of stress and fluid saturation on the acoustic response of fractured rock

Standard rock physics models are formulated to describe the behavior of porous sedimentary reservoirs, with clean sandstones being the archetypal system; however, many situations demand geophysical monitoring of rocks with significantly different structures, such as low porosity, fractured reservoirs. Conventional models also suggest that these “stiff” reservoirs can be challenging to monitor seismically due to small fluid substitution effects, but the presence of fractures leads to stress dependence which may be leveraged for remote monitoring purposes. Using samples from the Duperow Formation (dolostone) obtained from the Danielson test well in Kevin Dome, MT, we conducted ultrasonic and multi-scale structural (profilometry, synchrotron micro-tomography, pressure sensitive film) measurements on naturally fractured core in order to characterize the effects of fluid substitution and effective stress on the acoustic response of fractured reservoir rock with a focus in particular on the textural and seismic characteristics of natural fractures. We find that changes in effective stress can yield changes in velocity of up to 20% and changes in attenuation up to 200%. Measured fluid substitution effects are resolvable, but stress effects dominate. These measurements provide insight into the physical processes controlling acoustic response of fractured rocks in general and can also be used to inform monitoring efforts in fractured reservoirs.

Insights into the activation characteristics of natural fracture during in-fracture temporary plugging and diverting fracturing

In-fracture temporary plugging and diverting fracturing (ITPDF) has proved to be an efficient way to stimulate naturally fractured reservoirs by creating complex fracture networks. In this work, a 2D fluid–solid fully coupling finite element model is established to investigate the activation characteristics of natural fractures influenced by various factors. This model is verified against the published experimental and numerical results, and the considered factors include the approaching angle, the tensile strength of natural fracture, the horizontal stress contrast, and the injection rate. Innovatively, the plug model is proposed to plug hydro-fractures during the simulation. The mechanical properties of the natural and hydraulic fractures are designed based on the real tight reservoir in Tarim Oilfield, West of China. This work finds out the most sensitive factors to the activation of the NFs and reveals the influencing pattern of various factors. Moreover, this work presents the NF activation process and reveals the dynamic change in the fracture width. During ITPDF, the HF firstly activates the NF acute and then crosses the NF when the approaching angle is ≤ 60°, and the HF firstly crosses the NF and then activates the NF acute branch when the approaching angle is > 60. The difference in the activation pressure between the two NF branches can reach up to 35 MPa. Moreover, The NF acute branch cannot be activated at the IPT distance beyond 5 m, the IPT permeability beyond 670 mD, and the rock permeability beyond 0.8 mD. This study guides candidate well selection and diverter recipe optimization during ITPDF operations in Tarim Oilfield.

Characteristics and Formation Stages of Natural Fractures in the Fengcheng Formation of the Mahu Sag, China: Insights from Stable Carbon and Oxygen Isotope and Fluid Inclusion Analysis

The Fengcheng Formation of the Mahu Sag is an unconventional reservoir that is of paramount importance for exploration and development of hydrocarbon resource. However, current research on natural fractures in the Fengcheng Formation remains limited, posing challenges for exploration of hydrocarbon resource in the region. This study is based on core observations, thin section identification, geochemical testing and the evolution of regional tectonic movements to investigate the characteristics and periods of formation of natural fractures to address this gap. According to the characteristics of natural fractures in the drilling core samples and microsections, the natural fractures in the Fengcheng Formation can be grouped into structural fractures and atectonic fractures. Structural fractures can be further divided into three subtypes: high-angle interlayer shear fractures, along-layer shear fractures, and tensile fractures. Additionally, non-tectonic fractures in this studied area are primarily bedding fractures, hydraulic fractures, and hydrocarbon-generating overpressure fractures. Vertically, fracture development is more prominent at the bottom of Feng #2 Formation and at the top of Feng #3 Formation. Results also indicate that natural fractures primarily formed during three distinct tectonic movement periods. The initial stage of fracture evolution pertains to the Late Permian period (243–266 Ma), filled with fibrous calcite, and exhibiting a uniform temperature of 70–100 °C. The second stage of fracture evolution occurred during the Late Indosinian to Early Yanshanian period (181–208 Ma), mostly filled or semi-filled with calcite, with a uniform temperature of 110–130 °C. The third stage of fracture development happened during the late Yanshanian to early Himalaya period (50–87 Ma), predominantly filled with calcite, and presenting a uniform temperature of 130–150 °C. Among the various types of structural fractures, the density of high-angle interlayer shear fractures demonstrates a positive correlation with daily gas production, indicating their vital role in promoting hydrocarbon resource production and transportation. Furthermore, microfractures generated by hydrocarbon-generating overpressure fractures exhibit small pore sizes and strong connectivity. These microfractures can create an effective permeability system by connecting previously isolated micropores in shale reservoirs, thus establishing interconnected pore spaces in the shale formation.

Distribution pattern of natural fractures in lacustrine shales: a case study of the Fengcheng formation in the Mahu Sag of the Junggar Basin, China

The Lower Permian Fengcheng Formation in the Mahu Sag develops a set of organic-rich alkaline lacustrine shale strata, which is a key area for shale oil exploration and development. As an important storage space and seepage channel for shale reservoirs, natural fractures have an impact on shale oil enrichment, production and development effect. In this study, the types and characteristics of natural fractures were first analyzed using core, thin section and imaging logging data. On this basis, combined with the distribution of fractures in single wells, the vertical distribution law of fractures is discussed. Finally, the planar distribution of fractures is evaluated using different seismic attributes such as coherence, curvature, likelihood, and AVAz. The results showed that three types of fractures are existed, including transformational shear fractures, intraformational open fractures and bed-parallel shear fractures, with intraformational open fractures being the most developed. The development degree of fractures in different layers has obvious differences, mainly controlled by lithology and brittle mineral content. The basalt and tuff are developed in the Feng 1 Member, with low carbonate mineral content, resulting in a relatively low degree of fracture development. The dolomite and argillaceous dolomite are developed in the Feng 2 Member and the Feng 3 Member, with high carbonate mineral content and brittleness, resulting in a high degree of fracture development. Additionally, the closer to the fault, the higher the degree of fracture development. On the plane, the fracture zone develops near the main and secondary faults, with the trend mainly oriented in the E-W direction and approximately parallel to the direction of the faults. The width of the fracture zone is largest in the central and southern part of the study area. These fractures are fault-related and are caused by regional stress fields resulting from the activity of the main-secondary faults.

Microscopic Analysis of Natural Fracture Properties in Organic-Rich Continental Shale Oil Reservoirs: A Case Study from the Lower Jurassic in the Sichuan Basin, China

Natural fractures are of paramount importance in storing carbon in shale oil reservoirs, where ultra-low porosity and permeability necessitate their essentiality for enhanced oil recovery. Therefore, comprehensively clarifying the characteristics of natural fractures in shale oil reservoirs is imperative. This paper focuses on investigating the microscopic features of natural fractures in organic-rich continental shale oil reservoirs that are commonly found in the Lower Jurassic strata of the Sichuan Basin, employing them as a representative example. Multiple methods were utilized, including mechanical testing, Kaiser testing, multi-scale CT scanning (at 2 mm, 25 mm, and 100 mm scales), and a numerical simulation of fluid seepage in fracture models. The results revealed that the in situ stress of the target seam displays the characteristic of σH > σv > σh, with σv and σh being particularly similar. The relatively high lateral stress coefficient (ranging from 1.020 to 1.037) indicates that the horizontal stresses are higher than the average level. Although the 2 mm CT scan provides a more detailed view of fractures and connected pores, it primarily exhibited more pore information due to the high resolution, which may not fully unveil additional information about the fractures. Thus, the 25 mm shale core is a better option for studying natural fractures. The tortuosity of the different fractures indicated that the morphology of larger fractures is more likely to remain stable, while small-scale fractures tend to exhibit diverse shapes. The simulations demonstrated that the stress sensitivity of fracture permeability is approximately comparable across different fracture scales. Therefore, our research can enhance the understanding of the properties of natural fractures, facilitate predicting favorable areas for shale oil exploration, and aid in evaluating the carbon storage potential of shale oil reservoirs.

Characterization methods for natural fractures distribution in shale and tight reservoirs

Aperture distribution and spatial arrangement are fundamental characteristics of natural fractures. Since it is impossible to directly measure the aperture of all existing fractures, a power law (fractal model) has been commonly used to describe fracture apertures, which has also been extended to estimate fracture spacing and macrofractures density. Although a power law (fractal model) has commonly been used to describe fracture apertures, data points in small and large fracture size ranges tend to deviate from this distribution. In this study, a Variable Shape Distribution (VSD) method was derived from a fractal theory to model fracture size distribution. The VSD method was compared with seven other commonly used models. Eleven fracture datasets collected from five countries on four continents were regressed using these methods. The scale-free methods of the VSD and power law models showed more advantages than the scale-dependent methods. The VSD method was found to best fit all variable aperture size distribution patterns, with an average coefficient of determination of 0.99. The average fractal dimension for all samples calculated by the VSD method (1.36) was slightly higher than that of the power law (1.06). This study is unique in showing that the VSD method can solve a boundary characterization problem that has been widely neglected in previous studies. With the assumption of an even fracture distribution, the VSD method was further applied to estimate average fracture spacing, predict a threshold fracture length that controls the linkage of fractures, and predict fractures outside of the measurement range. This study not only proposes an advanced fractal method to model aperture size distributions in shale and tight rocks but also helps to better understand the importance of fractal dimensions and boundary characterizations.

Risk assessment of earthquakes induced during HDR development: A case study in the Gonghe Basin, Qinghai Province, China

Earthquakes induced during hot dry rock (HDR) geothermal development have attracted extensive attention and constrained the further exploitation of HDR resources. Seismic risk evaluation of HDR projects is essential. The first HDR demonstration project in China is located in the Gonghe Basin in Qinghai. The EGS (enhanced geothermal systems) site is located near Gonghe County and is very seismically sensitive. The seismic risk induced by hydraulic fracturing and long-term cycling during the HDR development process was evaluated using a multi-field coupling method based on analysis of the geothermal geological conditions, ground stress, and natural fracture characteristics. During hydraulic fracturing, the predicted magnitude of earthquake events is generally below 2.0, with a range of 0.7–1.3. During a 30-year development period, the predicted maximum earthquake magnitude is less than 1.28. The HDR development will not have an impact on the local geological safety. Considering the uncertainty of the geology, a further discussion of measures to reduce the risk of earthquakes is presented. An entire induced seismic risk evaluation process method is developed, which can provide a reference for related research.

Study on coalbed methane flow characteristics based on fractal bifurcation fracture network model

The geometric structure and distribution of the fracture network significantly impact the coalbed methane flow characteristics. The indoor optical microscope test is utilized to analyze the distribution and structural characteristics of natural fractures in coal. The results indicate that the fracture network in coal consists primarily of irregular bifurcated fractures, but the influence of the bifurcation fracture network’s structural characteristics on permeability remains unclear. Therefore, the fracture network geometric structure characteristic parameters are considered in accordance with the fractal theory, and the analytical formula of the bifurcation fracture network permeability is established. Meanwhile, the bifurcation fracture network geometric model with varied structural parameters is reconstructed using the pixel probability decomposition algorithm. Finally, the influence of the key parameters of the reconstructed bifurcation fracture network on the coal seam permeability is analyzed through numerical simulation. The results indicate that the permeability of the bifurcated fracture network increases with the increase of fracture porosity φf, aperture ratio χ, and proportionality coefficient η, and decreases with the increase of tortuosity fractal dimension DT, bifurcation angle θ, fractal dimension Df, and bifurcation level n. Among them, fracture porosity and proportionality coefficient have the greatest influence on permeability, followed by tortuosity fractal dimension, aperture ratio.

Ultra-Deep Dolomite Reservoir Quality Classification and its Effect on Acid-Fracturing Based on Natural Fracture Activity Analysis: A Case Study of the Cambrian Subsalt Reservoir in Northern Uplift of Tarim Basin

Taking the >8,000 m buried Cambrian subsalt dolomite reservoir in the northern uplift of the Tarim Basin as an example, this study used imaging logging, cores, outcrops, and other data to identify natural fractures and obtain parameters of natural fractures, including strike, azimuth, width, length, and apparent porosity, and clarified the characteristics of natural fractures in the well section. Based on the logging data, wellbore rock mechanics, in situ stress, and elastic parameters were established. The analysis of the mechanical characteristics of natural fractures was carried out to find out the shear stress, normal stress, and their ratio of each natural fracture in the reservoir section. Combined with the stress value of each fracture, the quantitative characterization parameter Fractures Geomechanical Activity Index of the mechanical characteristics of natural fractures is established. Combined with the petrophysical parameters of natural fractures, the evaluation model of the quality index of the reservoir containing the natural fractures is established. According to the classification of reservoir quality, combined with the petrophysical properties of the reservoir section, the optimization of the acid-fracturing scheme and injection pressure can be carried out in order to increase the production after acid-fracturing. In this study, the quality of the reservoir with natural fractures is divided into three categories: the QRCF of a Class I reservoir is 0.6∼1, of Class II reservoir is 0.3∼0.6, and of Class III reservoir is less than 0.3. The application of Well L1 and other wells shows that there are great differences in the development of natural fractures at different depths of the Cambrian subsalt dolomite reservoir so as to QRCF. The Class I reservoir is easy for acid-fracturing to achieve high performance. The Class II reservoir needs large-scale acid-fracturing, and the Class III reservoir cannot be acid-fractured under the current methods. The research results provide a reference for the classification of the fracture mechanical activity of an ultra-deep Cambrian subsalt dolomite reservoir and the optimization of acid-fracturing treatment parameters of similar reservoirs.

Experimental study on the shear‐slip characteristics of natural fractures in shale reservoirs

AbstractThe injection of high‐pressure fluid and the propagation of hydraulic fractures (HF) can impact the stress state of natural fractures (NF) in shale reservoirs, which will lead to shear slip in NF that are in a critical stress state. However, the NF mechanics response mechanism during hydraulic fracture (HF) approximation has not been well investigated, especially under triaxial stress and injection conditions. This work focuses on the NF shear‐slip characteristics during HF through experimental investigation. Each shale sample contains a single rough NF in the tests, and high‐pressure fluid is injected through a pre‐drilled hole at the top of the sample. Meanwhile, the deformation (axial deformation and radial deformation), axial stress, and injection pressure of the sample during the experiment were recorded in real‐time. The experimental results show that the NF will initiate in tension or shear mode during the HF approaching process, and the fracture will produce shear slip in both initiation modes. In addition, the deviator stress, confining pressure, hydraulic fracture approach angle, and fracture surface roughness all affect the degree of shear slip in natural fractures (NF). The results further reveal the mechanical response mechanism of NF during hydraulic fracturing and provide a reference for optimizing hydraulic fracturing process measures.

Effect of Natural Fracture Characteristics on Proppant Transport and Placement in an Irregular, Nonplanar Fracture

Summary Hydraulic fracturing is recognized as the primary stimulating technique to enhance recovery in unconventional reservoirs. Connecting natural fractures and filling proppant are crucial elements to achieve the effective development of the reservoirs. Many studies have investigated the interaction characteristics between hydraulic fracture and natural fracture and proppant transport in complex fracture systems. However, few studies show how natural fracture affects proppant migration and placement. In this work, we experimentally explore proppant transport in an irregular, nonplanar fracture containing hydraulic fractures and a natural fracture. The objective is to identify the influence of natural fractures on proppant transport and placement. In this paper, proppant transport in a nonplanar fracture with bends is studied experimentally by a laboratory size slot, and the bending section represents a natural fracture. A high-resolution particle image velocimetry (PIV) system is used to detect the instantaneous velocity field in the complex pathway to understand particle transport behaviors. Proppant placement is quantitatively evaluated by the proppant coverage area as the proppant bed reaches the equilibrium state. Also, the effects of natural fracture width and height, intersection angle with hydraulic fracture, and relative location with the inlet on proppant placement are investigated. The results identify that the natural fracture would significantly increase the complexity of proppant transport and lead to a discontinuous and irregular proppant bed in the complex fracture. The vorticity flow appears around the bend and resuspends deposited proppants through the bending section. The small natural fracture width and height increase flow erosion and are not conducive to proppant settlement, resulting in no proppant. The more the bending angle, the lower the coverage area and bed height. When the natural fracture is close to the inlet, a depleted region without proppants would be formed around the wellbore. The multiple linear regression method developed two reliable models expressed by four normalized parameters to predict the bed coverage areas. The experimental results and laws provide ways to quantitatively analyze natural fracture characteristics' effect on proppant transport and placement in unconventional reservoirs and fissured formations.

Macrolithotype controls on natural fracture characteristics of ultra-thick lignite in Erlian Basin, China: Implication for favorable coalbed methane reservoirs

Understanding the distribution of the fracture system in the reservoir scale could significantly benefit coalbed methane (CBM) development. Coal fractures are controlled by multiple factors, among which the influence of macrolithotypes has been widely studied. However, few studies have explained their relationship from the perspective of mechanics. Furthermore, the macrolithotypes are controlled by coal facies and thus a relationship between coal facies and fracture system characteristics is likely to be built, which could largely facilitate the prediction of fracture system development in a CBM reservoir, especially for those having ultra-thick coal seams. In the current research, mechanical properties, in combination with in-situ and laboratory observations, are carried out for different coal macrolithotypes from ultra-thick lignite reservoirs to reveal their influence on coal fracture development in Erlian Basin, China. In this basin, xylitic coal and detritic coal are mainly developed, and the former has better developing natural fractures which appears to be caused by its weaker mechanical strength as identified by the mechanical tests including the compressive, shear, and tensile strength. Moreover, coal facies based on petrography and palynology tests were analyzed to clarify the spatial distribution of macrolithotypes in the reservoir. The results show that in an ideal coal-forming cycle, the coal seams occur starting from the detritic coal, to xylitic coal, and fusitic coal at last upwards in order. In a realistic sag, however, multilayer individual xylitic coal intervals are likely to exist, especially for ultra-thick lignite. In this situation, coal facies analysis could explain xylitic coal distribution, thereby predicting the fracture system development.

Nanoparticle-stabilized CO2 foam to improve conventional CO2 EOR process and recovery at Batı Raman oil field, Turkey

(B.Raman), which is the largest oil field of Turkey's already existing CO2 injection system, does not produce at the desired efficiency due to the natural fracture characteristics. Therefore, this research is performed to control the CO2 mobility in the reservoir by creating nanoparticle stabilized CO2 foam using the property of nanoparticles to be adsorbed at the gas-water interface permanently and to achieve additional oil recovery at the B. Raman oil field. In the initial stage of the research, dispersion stabilization and foamability of different nano-silicas are considered. The effects of nanoparticle concentration, salinity, temperature, and pH on foamability and dispersion stabilization were examined. Research results suggested that half hydrophobicity, salt addition, and increased concentration positively affect foamability, whereas the salinity value above 1% generated flocculation. Also, although the foam with half hydrophobic nano-silica named H30 has better foamability, this foam could not be stabilized. The effects of pressure, phase ratio, and flow rate on foam formation were also studied. The better foam was observed at the observation cell when the CO2 to Nano dispersion phase ratio was 1. It was also found that the pressure should be above 1100 psi where the CO2 was in the supercritical phase to create the foam with the current core flooding system. Then, the oil recovery test was conducted with suitable nanoparticles, particularly the PEG and CC301. Before using nano-silica particles, CO2 injection and then WAG was applied to the core sample to express the B. Raman field case. The results indicate that foam application is successful if appropriate conditions exist.

Correction to Characteristics of Natural Fractures in an Ultradeep Marine Carbonate Gas Reservoir and Their Impact on the Reservoir: A Case Study of the Maokou Formation of the JLS Structure in Sichuan Basin, China

Correction to Characteristics of Natural Fractures in an Ultradeep Marine Carbonate Gas Reservoir and Their Impact on the Reservoir: A Case Study of the Maokou Formation of the JLS Structure in Sichuan Basin, China

Characterizing the characteristics of natural fractures in shale based on the modified petrophysical model

In order to provide technical support for the shale gas exploration and development in the Lower Silurian Longmaxi Formation of the Sichuan Basin, this paper takes the Longmaxi Formation in the Changning and Fuling Shale Gas Fields as the research object to quantitatively characterize the development characteristics of natural fractures in the Longmaxi Formation shale by means of helium pycnometry, X-ray diffraction (XRD), true density testing and other methods, with the aid of the modified petrophysical model. Then, the development types and genetic mechanisms of natural fractures and their influences on shale gas development are discussed. The following research results are obtained. First, the modified petrophysical model can accurately describe the pore system in the Changning shale with a fitting rate of 0.74. Second, the development of natural fractures in shale is different in various regions. The natural fractures in the Changning Shale Gas Field, controlled by basement thrust faults, decollement layers and internal folds, are locally developed and filled with calcareous, and the average fracture porosity is 0.15%. In the Fuling Shale Gas Field, however, natural fractures, mainly controlled by reverse faults and slippage effect, are commonly more developed and unfilled or semi-filled with siliceous, and the average fracture porosity is 1.30%. Third, under the formation conditions, the opening of natural fractures is different. The natural fractures in the Changning Shale Gas Field are basically closed with weaker flowing ability, while those in the Fuling Shale Gas Field are relatively open with stronger flowing ability. Fourth, the occurrence mode of shale gas is influenced by natural fractures, and it is internally dominated by free gas. The initial gas production of shale gas wells is higher. In conclusion, (1) the regression coefficient is introduced to calculate the actual total organic matter content, which promotes the modified petrophysical model to describe matrix pores and fracture pores more accurately; (2) the development of natural fractures in the shale producing pay of the Sichuan Basin is relatively beneficial to shale gas enrichment and exploitation, but the flowing ability of the natural fractures will be weakened under the original formation conditions.

Characteristics of Natural Fractures in an Ultradeep Marine Carbonate Gas Reservoir and Their Impact on the Reservoir: A Case Study of the Maokou Formation of the JLS Structure in the Sichuan Basin, China

Characteristics of Natural Fractures in an Ultradeep Marine Carbonate Gas Reservoir and Their Impact on the Reservoir: A Case Study of the Maokou Formation of the JLS Structure in the Sichuan Basin, China

Prediction of natural fracture in shale oil reservoir based on R/S analysis and conventional logs

Investigation into natural fractures is extremely important for the exploration and development of low-permeability reservoirs. Previous studies have proven that abundant oil resources are present in the Upper Triassic Yanchang Formation Chang 7 oil-bearing layer of the Ordos Basin, which are accumulated in typical low-permeability shale reservoirs. Natural fractures are important storage spaces and flow pathways for shale oil. In this study, characteristics of natural fractures in the Chang 7 oil-bearing layer are first analyzed. The results indicate that most fractures are shear fractures in the Heshui region, which are characterized by high-angle, unfilled, and ENE-WSW-trending strike. Subsequently, natural fracture distributions in the Yanchang Formation Chang 7 oil-bearing layer of the study area are predicted based on the R/S analysis approach. Logs of AC, CAL, ILD, LL8, and DEN are selected and used for fracture prediction in this study, and the R(n)/S(n) curves of each log are calculated. The quadratic derivatives are calculated to identify the concave points in the R(n)/S(n) curve, indicating the location where natural fracture develops. Considering the difference in sensitivity of each log to natural fracture, gray prediction analysis is used to construct a new parameter, fracture prediction indicator K, to quantitatively predict fracture development. In addition, fracture development among different wells is compared. The results show that parameter K responds well to fracture development. Some minor errors may probably be caused by the heterogeneity of the reservoir, limitation of core range and fracture size, dip angle, filling minerals, etc.