Degree Of Fracture Development Research Articles

Brittleness evaluation of the Lower Silurian marine shale reservoirs: A case study of Longmaxi shale in Fenggang block, southern China

The brittleness of shale determines the fracturability of the shale reservoir and has a great influence on the exploration and development of shale gas. Therefore, prediction of brittleness and evaluation of fracturability of shale are very important in finding favorable areas for shale gas. We have used the mineral composition, rock-mechanics experiment, logging evaluation, 2D seismic data inversion, and fracture development degree to evaluate and analyze the vertical and plane brittleness characteristics and the main controlling factors of Longmaxi shale. In addition, we established the fracturability index of shale based on the brittleness index, critical strain energy release rate, and fracture toughness. The results indicate that the brittle mineral content of Longmaxi shale in the Fenggang block is between 69% and 90%, and shale samples are prone to brittle deformation by microscopic observation. Brittle deformation has a positive effect on the porosity and percolation ability of shale; the fractures in the upper and lower parts of the Longmaxi shale are relatively developed, and the degree of core fracture development is consistent with rock brittleness. The brittleness distribution of 2D seismic data inversion is in good agreement with the brittleness predicted by well logging; shale reservoirs with low fracture toughness, low critical strain energy release rate, and high brittleness index have high fracturability. Therefore, the research on shale brittleness and fracturability of Lower Silurian Longmaxi shale is expected to have important guiding significance for shale-gas exploration and development in southern China.

Analysis of Developmental Characteristics and Dominant Factors of Pore-Fracture Systems in Lower Cambrian Marine Shale Reservoirs: A Case Study of the Niutitang Formation, Fenggang Block, Southern China.

Due to breakthroughs in the Lower Silurian Longmaxi Formation in the Sichuan Basin and multiple strata around the basin, the northern part of Guizhou adjacent to the Sichuan Basin has become a key area for shale gas exploration. Compared with the Longmaxi Formation, the Niutitang Formation displays greater TOC (total organic carbon) content, depositional thickness and distribution area, but the details remain undetermined. In the study area, the Lower Cambrian Niutitang Formation typically has high TOC content, maturity and brittle mineral content. The study area has experienced multiple periods of tectonic movement, which have great influence on the fracture and pore characteristics. The fractures are mainly structural fractures and have obvious zoning. The primary types of pores are intraparticle pores, organic matter pores, and interparticle pores. Further, macropores and mesopores less than 50 nm contribute most of the pore volume, while pores less than 2 nm contribute most of the specific surface area. Many factors affect the pore-fracture system, such as tectonism, TOC content, mineral composition, and sedimentary environment. Tectonic movements produce fractures based on the changing stress field, but the degree of fracture development does not agree well with the degree of pore development. The TOC content has good positive correlations with the development of fractures and micropores, especially for nanoporosity, while clay minerals show a negative correlation with the development of fractures but a strong positive correlation with the growth of micropores. Quartz displays a positive correlation with the development of fractures but no good correlation with pore development. Finally, the lithofacies, lithologies and mineral compositions under the control of sedimentary environments are internal factors that can impact the development of pore-fracture systems.

Characteristics of the In Situ Stress Field in the Yadian Coal Mine, Central China: Implications for Roadway Differential Deformation.

To study the in situ stress mechanism for different deformations of roadways in different directions, in this paper, we used the method of stress relief with a hollow core to measure the in situ stress of roadways with different degrees of deformation in the Yadian coal mine. The results showed that the in situ stress field was generally σH > σh > σV, indicating a typical reverse faulting stress regime. The present in situ stress field was the main factor for roadway differential deformation. The σH orientations were ESE and ENE-trending, which were consistent with the regional tectonic stress field in North China. The instrument for monitoring the abscission layer deformation indicated that the NS-trending roadway (cut-hole) deformation time approached stability after approximately 1–2 months, while it was 5–10 days for its EW-trending counterpart. The study of stress gradient shows that the stress state of the Ordos Basin has changed at a depth of 600 m, which is related to multiple tectonic events from the Late Paleozoic to Cenozoic in the Ordos Basin. The comprehensive analysis results show that the differential deformation of roadways is affected by many factors, such as the buried depth of the stratum, lithology and structural characteristics, fracture development degree, mining influence, composite deformation mechanics mechanism of weak swelling rock stratum, in situ stress field, tectonic stress mechanism, fracture development, etc.

Experimental study on fracture propagation of hydraulic fracturing for tight sandstone outcrop

The tight sandstone oil reservoirs characterized by the low porosity and permeability must be hydraulically fractured to obtain the commercial production. Nevertheless, the post-fracturing production of tight oil reservoirs is not always satisfactory. The influence mechanism of various factors on the fracture propagation in the tight oil reservoirs needs further investigation to provide an optimized fracturing plan, obtain an expected fracture morphology and increase the oil productivity. Thus, the horizontal well fracturing simulations were carried out in a large-scale true tri-axial test system with the samples from the Upper Triassic Yanchang Fm tight sandstone outcrops in Yanchang County, Shaanxi, China, and the results were compared with those of fracturing simulations of the shale outcrop in the 5th member of Xujiahe Fm (abbreviated as the Xu 5th Member) in the Sichuan Basin. The effects of the natural fracture (NF) development degree, horizontal in-situ stress conditions, fracturing treatment parameters, etc. on the hydraulic fracture (HF) propagation morphology were investigated. The results show that conventional hydraulic fracturing of the tight sandstone without NFs only produces a single double-wing primary fracture. The fracture propagation path in the shale or the tight sandstone with developed NFs is controlled by the high horizontal differential stress. The higher stress difference (<12MPa) facilitates forming the complex fracture network. It is recommended to fracture the reservoir with developed NFs by injecting the high-viscosity guar gum firstly and the low-viscosity slick water then to increase the SRV. The low-to-high variable rate fracturing method is recommended as the low injection rate facilitates the fracturing fluid filtration into the NF system, and the high injection rate increases the net pressure within the fracture. The dual-horizontal well simultaneous fracturing increases the HF density and enhances the HF complexity in the reservoir, and significantly increases the possibility of forming the complex fracture network. The fracturing pressure curves reflect the fracture propagation status. According to statistical analysis, the fracturing curves are divided into types corresponding to multi-bedding plane (BP) opening, single fracture generation, multi-fracture propagation under variable rate fracturing, and forming of the fracture network through communicating the HF with NFs. The results provide a reference for the study of the HF propagation mechanism and the fracturing design in the tight sandstone reservoirs.

Physical Simulation of Hydraulic Fracturing of Large-Sized Tight Sandstone Outcrops

Summary Hydraulic fracturing is an indispensable technology in developing tight oil and gas resources. However, the development of tight oil and gas is not consistently satisfactory. Further understanding of hydraulic fracturing of tight sandstone is required, which increases the production of tight oil and gas reservoirs, particularly in China. Currently, there are a few true triaxial hydraulic fracturing physical simulations of large tight sandstone outcrops. To weaken the boundary effect, this study performed simulations using large tight sandstone outcrops (500 × 500 × 500 mm and 500 × 500 × 800 mm) in the Shahezi Formation (Fm.), Jilin Province, China. The effect of natural fracture (NF) development degree, in-situ stress conditions, fracturing treatment parameters, and temporary plugging on fracture propagation were investigated. Furthermore, fracture propagation was investigated based on post-fracturing fine reconstruction, high-energy computed tomography (CT) scan, acoustic emission monitoring (AEM), and analysis of a fracturing pressure curve. Finally, suggestions on fracturing treatment were proposed. The results show that the NF is a key factor in determining the hydraulic fracture (HF) morphology in the tight sandstone reservoir. Further, the number, approaching angle, and cementation strength of the preexisting NF affect the HF propagation path; these are the key factors for forming complex fractures. In the tight sandstone reservoir with well-developed NFs, the fracture morphology is dominated by the NF under horizontal differential stress ≤ 9 MPa. A single fracture is more likely to occur under horizontal differential stress ≥ 12 MPa, which is less affected by the NF. In the fracturing at variable injection rates, a low rate facilitates fluid penetration into the NF, while a high rate facilitates deep HF propagation. A low-viscosity fracturing fluid at a high rate facilitates further propagation of the temporary plugging agent (TPA), thus achieving deep temporary plugging and fracture diversion. A high-viscosity fluid does not facilitate accumulation and plugging of particulate TPA. Higher horizontal differential stress leads to a smaller diversion radius of new HF, which is closer to the original HF, leading to poorer stimulation effect. The results provide a reference for the fracturing design of the tight sandstone.

Formation conditions and enrichment model of retained petroleum in lacustrine shale: A case study of the Paleogene in Huanghua depression, Bohai Bay Basin, China

Abstract Compared with marine facies shale strata, lacustrine shale strata are more complicated in geological conditions, and thus more difficult to explore and develop. To realize economic exploration and development of lacustrine shale oil, the geological regularities of accumulation and high yield of retained movable petroleum in shale should be understood first. In this work, taking the shale strata of Kong 2 Member and Sha 3 Member in the Paleogene of Huanghua depression in the Bohai Bay Basin as examples, based on the previous joint analysis results of over ten thousand core samples and the latest oil testing, production test and geochemical data of more than 30 horizontal wells, accumulation conditions and models of retained movable petroleum in lacustrine shale were studied comprehensively. The study shows that at moderate organic matter abundance (with TOC from 2% to 4%), shale strata have the best match between oil content and brittleness, and thus are rich in oil and good in fracability. Moderate ancient lake basin size and moderate sediment supply intensity are the internal factors leading to best coupling of organic matter abundance and brittle mineral content in the shale formation. Moderate thermal evolution maturity of Ro of 0.7%–1.0% (at burial depth of 3200 to 4300 m) is the interval where oil generation from thermal evolution and oil adsorption by kerogen in shale layers match best, and retained movable petroleum is high in proportion. Moderate diagenetic evolution stage (3200 to 4300 m in the middle diagenetic stage A) is conducive to the formation of a large number of dissolved pores and organic matter pores, which provide storage space for shale oil enrichment. Moderate development degree of natural fractures (without damaging the shale oil roof and floor sealing conditions) is conducive to the storage, seepage and preservation of shale oil. The research results have overthrown the general understanding that high organic matter abundance, high maturity, and high development degree of natural fractures are conducive to shale oil enrichment, and have guided the comprehensive evaluation of shale oil and gas sweet spots and well deployment in the second member of the Kongdian Formation in the Cangdong sag and the Shahejie Formation in the Qikou sag. Industrial development of the shale oil in Kong 2 Member of the Cangdong sag has made major breakthrough, and important signs of shale oil have been found in Sha 3 Member of the Qikou sag, demonstrating huge exploration potential of lacustrine shale oil.

Experimental study of the effects of gas adsorption on the mechanical properties of coal

A coupled gas-solid testing system was developed to quantitatively investigate the effects of gas adsorption on the strength, volumetric strain, and fracture development of coal. Uniaxial loading tests were conducted on coal with samples that had adsorbed helium (He), nitrogen (N2), methane (CH4), and carbon dioxide (CO2) gases. Gas adsorption during the testing process was graphed using MATLAB, and the fractal dimensions of the fractures in coal were obtained. Under the same adsorption pressure, the adsorption capacity and degradation rate of coal were found to decrease in the following order for the four gases: CO2 > CH4 > N2 > He. The adsorption of CO2 had a salient negative affect on coal strength, while the effect of non-adsorptive He was negligible. The peak strength decreased by 48.27% after CO2 adsorption at a pressure of 2.0 MPa, and the deterioration rate of coal strength increased logarithmically under adsorption equilibrium pressure. The fractal dimension and density of coal fractures increased with adsorption capacity. The degree of fracture development in coal with adsorbed CO2 at a gas pressure of 2.0 MPa was 2.28-fold that of coal without adsorbed gas, and fish scale-shaped swelling and shedding were observed. The novel findings of this study provided a scientific basis for the quantitative evaluation of the mechanical properties of coal with adsorbed gases.

Natural fractures in deep tight gas sandstone reservoirs in the thrust belt of the southern Junggar Basin, northwestern China

The development of natural fractures is a significant characteristic of the Jurassic deep tight sandstone reservoirs in the thrust belt of the southern Junggar Basin, and these reservoirs have a great potential for natural gas resources. Based on the analyses of outcrops, cores, thin sections, and other laboratory data, natural fractures in these reservoirs are mainly tectonic ones, which appear in groups and vary in scale, dip angle, and density. We have classified fractures in thin sections into intragranular, grain boundary, and transgranular ones depending on their relationship with minerals grains. Almost 58% of the whole fracture population is opening-mode fractures, and calcite is the main filling mineral for the remaining ones. Fracture apertures vary based on their types, where transgranular fractures are the widest, followed by grain boundary and intragranular ones. Lithology, rock mechanical mechanics layers, and structures control the development of natural fractures. Fractures are more frequent in siltstone and fine sandstone. Sandstones with larger mineral grains are more likely to develop grain boundary and intragranular fractures. Intralayer fractures are the dominant ones, which intersect the rock mechanics interface at high angles or perpendicularly. The linear density of these fractures decreases when the thickness of the rock-mechanics layer increases. Furthermore, fractures have a higher degree of development in the hanging wall of the faults, with the degree decreasing when the distance from the fault plane increases. Additionally, the development degree of fractures in the damage zone is better than the adjacent rocks, and the width of damage zones is a function of the amount of fault displacement.

Fracture Types and Its Control Factors in Tight Oil Reservoirs

Fractures are well developed in tight sandstone reservoirs, which are the main reservoir space and important seepage channel. Fractures control the migration, accumulation, preservation and single well productivity of tight oil and gas, and affect the drilling and completion methods, fracturing reconstruction measures and production effect of tight oil exploration and development. This paper mainly studies the genetic type, development characteristics and control factors of fractures in tight reservoirs. According to the geological origin of fractures, there are two types of structural fractures and diagenetic fractures in the study area, among which high angle structural fractures are the main one, and it is layer controlled fracture. The degree of fracture development is controlled by lithology, formation thickness, sedimentary micro and other rock heterogeneity factors.

Characteristics, influencing factors, and prediction of fractures in weathered crust karst reservoirs: A case study of the Ordovician Majiagou Formation in the Daniudi Gas Field, Ordos Basin, China

The study of fractures in karst reservoirs is a hot spot in the field of geosciences. In this article, we conducted a systematic study on the characteristics, influencing factors, and prediction methods of karst reservoir fractures of the Ordovician Majiagou Formation in the Daniudi Gas Field, China. Both weathering and tectonic fractures are mainly developed in the Ma 5 member of the Majiagou Formation. The former is categorized into surface weathering, steep wall tensile and karst collapse fractures, and the latter is made of tensile and shear fractures. The palaeo‐temperatures of the fracture filling inclusions range from 90 to 140°C, peaking at 111–120°C, which are derived from oxygen isotopes of −7.9 to −17.5‰, with average −14.1‰ from the same filling inclusions. Integrations of regional tectonic activities, inclusion tests, and stable isotope analysis recognizes four formation periods of fractures since the Caledonian. The factors controlling the development degree of the karst reservoir fractures include lithology, petrophysical properties, rock layer thickness, structural deformation strength, and karst palaeomorphology. The buckling thin plate simulation results show a good positive correlation between the maximum principal stress and tensile fracture density. The same positive correlation is also observed between the shear stress and fracture density. The ancient karst landforms have strongly affected the distribution of weathering fractures. Surficial weathering fractures occur typically in the weathered residual monadnocks, while steep wall tension ruptures in areas near geomorphic steep ridges, and karst collapse fractures in karst residual monadnocks and karst pit areas.

Analysis of Cuttings' Minerals for Multistage Hydraulic Fracturing Optimization in Volcanic Rocks.

The fracturing of naturally fractured volcanic rocks has a significant impact on the logging due to the high degree of volcanic fracture development and the complex distribution of fractures. Such impact ultimately leads to the difficulty in determining the location of fracturing perforations and the increase in engineering costs. This article proposed a method of analyzing cuttings for geologging that return to the ground when drilling. After cleaning and further processing of the cuttings, samples at every depth are formed. Then, an electron microscope and supporting processing software are used to calculate the parameters of the sample at each depth and the rock mechanical parameters in the target well section based on the mineral content. Compared with mud logging data, the mineral analysis method of rock cuttings costs less time, and the materials are easier to obtain, thereby providing richer data. This method has an important guiding role for the selection of perforation positions in large-scale hydraulic fracturing.

Fracture identification and evaluation using conventional logs in tight sandstones: A case study in the Ordos Basin, China

Fractures are of great significance to tight oil and gas development. Fracture identification using conventional well logs is a feasible way to locate the underground fractures in tight sandstones. However, there are three problems affecting its interpretation accuracy and practical application, namely weak well log responses of fractures, a lack of specific logs for fracture prediction, and relative change omission in log responses. To overcome these problems and improve fracture identification accuracy, a fracture indicating parameter (FIP) method composed of a comprehensive index method (CIM) and a comprehensive fractal method (CFM) is introduced. The CIM tries to handle the first problem by amplifying log responses of fractures. The CFM addresses the third one using fractal dimensions. The flexible weight parameters corresponding to logs in the CIM and CFM make the interpretation possible for wells lacking specific logs. The reconstructed logs in the CIM and CFM try to solve the second problem. It is noted that the FIP method can calculate the probability of fracture development at a certain depth, but cannot show the fracture development degree of a new well compared with other wells. In this study, a formation fracture intensity (FFI) method is also introduced to further evaluate fracture development combined with production data. To test the validity of the FIP and FFI methods, fracture identification experiments are implemented in a tight reservoir in the Ordos Basin. The results are consistent with the data of rock core observation and production, indicating the proposed methods are effective for fracture identification and evaluation.

Natural fractures in metamorphic basement reservoirs in the Liaohe Basin, China

The Archaean metamorphic basement reservoirs that are characterized by the development of natural fractures are the primary target for oil and gas exploration in the Liaohe Basin. Based on the analyses of outcrops, cores, thin sections, imaging logs, and laboratory measurements, tectonic fractures are the dominant type of natural fractures, and their development is mainly influenced by petrology and faulting. Tectonic fractures are more developed in metamorphic rocks with a higher content of brittle minerals, while fracture orientations are primarily parallel or almost parallel to the fault strikes. Opening-mode fractures, which account for more than 65% of the total reservoir porosity, provide the primary storage space for metamorphic basement reservoirs. Besides, opening-mode fractures serve as the major pathways for fluid flow throughout the reservoirs and ultimately determine the quality of these reservoirs. Therefore, the discrepancies in fracture development are speculated to be the primary reason leading to the vertical stratification of reservoirs. According to the degree of fracture development, various rock types in metamorphic basement reservoirs can be arranged in order as leptite, granulite, migmatitic granite, gneiss, lamprophyre, diabase, and amphibolite. In this sequence, the former rocks are more likely to become effective reservoirs, while the latter ones are usually inner interlayers. However, the lithology boundary of reservoir rocks and inner interlayers is not definite in this sequence. In a specific metamorphic basement reservoir, the rocks that can become reservoirs have a lower limit in the sequence. But for numerous metamorphic basement reservoirs in the Liaohe Basin, there is no lower limit for rocks to become hydrocarbon-bearing reservoirs.

Developmental characteristics and dominant factors of natural fractures in lower Silurian marine organic-rich shale reservoirs: A case study of the Longmaxi formation in the Fenggang block, southern China

Natural fractures are an important storage space and main seepage channel of shale gas reservoirs, controlling the permeability of shale gas reservoirs and the migration, enrichment, preservation conditions and single-well productivity of shale gas. The successful production of shale gas has shown that the development of natural fractures in shale is beneficial, and a high degree of natural fracture development can allow a large-scale fracture network to form in the process of hydraulic fracturing, which can effectively improve the shale reservoir conditions. The development of fractures in shale reservoirs not only effectively improves the permeability of shale reservoirs but also increases the gas content, improving the productivity of shale reservoirs. Therefore, the degree of shale fracture development is the key to the production of shale gas reservoirs. Through the outcrop, shale core, thin section and scanning electron microscopy observations of the Longmaxi shale in the Fenggang block of Guizhou Province and the experimental data analysis of the corresponding samples, the fracture characteristics are statistically analyzed, and the fracture development characteristics and dominant factors are discussed in depth. The study area is located in the complex tectonic area of southern China, which experienced a strong tectonic deformation and a high degree of fracture development. The multiscale characterization of Longmaxi shale fractures indicates the following: the fractures observable in the field are mainly regional structural fractures, fold-related fractures, fault-related fractures and bedding fractures; additionally, the statistical analysis of core fractures shows that the structural fractures, including high-angle shear fractures, tension-shear fractures, and low-angle slip fractures are dominant and that most of them are filled with calcite; the micro-fractures are mainly intragranular fractures and intergranular fractures, and the fracture aperture is 0.01–2 μm. The degree of fracture development is controlled by structural factors, lithology, mineral composition and content, TOC, rock mechanical properties, paleoenvironment and diagenesis, and the structural factors are the most influential. The gentle transition zone of a fold limb is a favorable position for shale gas structure preservation. Fractures significantly impact the formation of seepage channels and storage space and the connection of isolated micro-pores, so the degree of fracture development has a positive relationship with the total and analytical gas contents.

Study on the Influence of Coal Face Advancing Distance on Fault-Activated Water Inrush

Water inrush in deep coal mines is closely related to geological structures such as faults. In order to study the influence rule of different coal face advancing distance (CFAD) on floor fault activation and floor rock mass failure characteristics, a mechanical model of fault activation was established with the 1315 working face of Anju coal mine as the research background, and the distribution of shear stress on fault plane and the influence rules of fault-activation under different CFAD are obtained. Then, FLAC3D numerical simulation software was used to further simulate and study the activation rules of floor faults and the characteristics of fracture development in floor rock mass. The results show the following: (1) When the coal face advances to a position of 80 m from the fault, the shear stress on the fault plane is sufficient to cause the fault-activation; When the coal face advances to a position of 20 m from the fault, the shear stress reaches a maximum and the fault-activation will reach a peak; (2) In the fault zone, fractures are derived from the bottom up under mining operation, but the development degree of fractures in the deep part is weaker than that in the shallow part. (3) Due to the existence of faults, a “oblate” damage and failure zone extending to the front and bottom of the coal wall gradually forms in the working face floor. The extension of this damage zone is first connected with the activated fault crack, and has formed advanced water inrush.

A new cross‐borehole hydraulic caving technique in the coal seam with a soft layer for preventing coal and gas outbursts during coal roadway excavation

AbstractPredrainage of gas by cross‐boreholes is an important method to prevent coal and gas outbursts in the process of a coal roadway excavation. Limitations of technologies and poor effects of preventing coal and gas outbursts occur in the coal seam with a soft layer. In this study, a new hydraulic caving technology for cross‐boreholes has been proposed to solve this problem. A CT equipment was used to observe the development of coal fissures around cross‐boreholes in the coal seam with a soft layer. The plastic zone range and permeability distribution of ordinary hydraulic slotting technologies and the new hydraulic caving technology also were compared by numerical simulation. The field test of hydraulic caving was taken in the Xuehu Mine (China). The results show that the fracture development degree of soft coal is greater than that of hard coal at the same distance from cross‐boreholes. The fracture development degree in the plastic zone is greater than that in the elastic zone. The hydraulic caving technique can achieve the same effect as the ordinary hydraulic slotting with less workload. The mass of coal discharged from a cross‐borehole was 1.15 t/m and the average methane concentration of single drainage borehole increased by 1.09‐4.1 times, and the average methane extraction amount of single drainage borehole increased by 6.06 times. Elimination of coal and gas outburst had been completed after 110 days of extraction in the area of hydraulic caving, and Q and S values are lower than the critical value during roadway excavation. It is conclusion that hydraulic caving technique can effectively improve the permeability and rapidly eliminate coal and gas outburst in the coal seam with a soft layer.

Study on the Theory of High Pressure Water Jet Coal Breaking and Its Main Controlling Factors

In order to solve the problems of gas extraction and pressure relief and permeability enhancement under low permeability and high surrounding rock stress conditions in deep coal seams, the ultra-high pressure hydraulic cutting technology is proposed. The mechanical mechanism of coal breaking by high pressure water jet is analyzed. The process of coal breaking by jet is divided into stress wave effect and secondary crack propagation effect. The effects of physical and mechanical properties of coal and rock and jet parameters on jet cutting depth are analyzed theoretically. The results show that the shear strength, tensile strength, fracture and pore development degree of coal and rock correspond to different types of coal and rock failure. With the increase of jet pressure and flow rate (nozzle diameter), the jet cutting depth increases gradually. The influence of jet rotating speed on cutting depth is analyzed. It is concluded that reducing rotating speed should be adopted to improve cutting depth in field practice. The research results can effectively improve the stress state of coal body, play the role of pressure relief and permeability enhancement, and improve coal seam permeability and gas release capacity, which can well meet the control needs of coal mine gas complex dynamic disasters.

3D Physical Simulation of Water Flooding Characteristics of Buried Hill Reservoir with Different Fracture Systems

In order to understand the water-flooding characteristics of different fracture systems in metamorphic rock buried hill reservoirs and the mechanism of improving water-flooding development effect, a three-dimensional physical model of fractured reservoirs is established according to the similarity criterion based on the prototype of metamorphic buried hill reservoirs in JZ Oilfield in Bohai Bay Basin. Combined with the fractured reservoir characteristics of JZ Oilfield, the water displacement characteristics of the top-bottom staggered injection-production well pattern in different fracture network mode and different fracture development degree of buried hill reservoir are studied. The experimental results show that: 1) the more serious the fracture system irregularity is, the shorter the water-free oil production period is and the lower the water-free oil recovery is. After water breakthrough of production wells, the water cut rises faster, and the effect of water flooding development is worse; 2) under the condition of non-uniform fracture development, the development effect of the bottom fracture undeveloped is better than that of the middle fracture undeveloped. Water injection wells are deployed in areas with relatively few fractures, while oil wells are deployed in fractured areas with higher oil recovery and better development effect.

Quantitative Prediction of Fracture Distribution of the Longmaxi Formation in the Dingshan Area, China using FEM Numerical Simulation

Fracture prediction is a technical issue in the field of petroleum exploration and production worldwide. Although there are many approaches to predict the distribution of cracks underground, these approaches have some limitations. To resolve these issues, we ascertained the relation between numerical simulations of tectonic stress and the predicted distribution of fractures from the perspective of geologic genesis, based on the characteristics of the shale reservoir in the Longmaxi Formation in Dingshan; the features of fracture development in this reservoir were considered. 3D finite element method (FEM) was applied in combination with rock mechanical parameters derived from the acoustic emissions. The paleotectonic stress field of the crack formation period was simulated for the Longmaxi Formation in the Dingshan area. The splitting factor in the study area was calculated based on the rock breaking criterion. The coefficient of fracture development was selected as the quantitative prediction classification criteria for the cracks. The results show that a higher coefficient of fracture development indicates a greater degree of fracture development. On the basis of the fracture development coefficient classification, a favorable area was identified for the development of fracture prediction in the study area. The prediction results indicate that the south of the Dingshan area and the DY3 well of the central region are favorable zones for fracture development.

Developmental characteristics, influencing factors and prediction of fractures for a tight gas sandstone in a gentle structural area of the Ordos Basin, China

The study of fracture development characteristics of tight gas sandstone reservoirs in the gentle structural areas of the Ordos Basin has been a research hot spot in recent years. However, there remains a lack of systematic research in this field. In this paper, we conducted a systematic study of the developmental characteristics, influencing factors and prediction of fractures for the tight gas sandstone in the Lower Permian He 8 Member in the Sulige gas field. The results show that the development degree of the fractures in the He 8 Member is mainly concentrated between 1 and 2 m−1. Meanwhile, the degree of fracture development is positively correlated with the cumulative sand body thickness, porosity and permeability and that it has no obvious correlation with gas saturation. Moreover, the degree of fracture development is positively correlated with the energy storage coefficient (Esc), indicating that the enrichment of natural gas in the tight gas sandstone reservoir of the He 8 Member is obviously affected by the fractures. The fracture index U is constructed by the finite element method and has a positive power exponential correlation with the fracture linear density. Finally, the fracture index was divided into three grades according to its coupling relationship with the gas well productivity.