Natural Fractures In Reservoirs Research Articles

Natural Fracture Occurrence Model Based on FMI Imaging Logging.

Natural fractures are crucial for connecting with reservoir matrix pores and influencing the fluid velocity in the matrix during unconventional oil and gas development. The development of natural fractures has significant impact on the effectiveness of extraction and even the final recovery factor. The development stage of natural fractures in reservoirs is characterized by fracture density and fracture occurrence, which are the key characteristics. The probabilistic models of fracture occurrence and density that are now available, however, still have several drawbacks. Therefore, a fracture occurrence model that may reflect both inclination and dip angles is proposed in a three-dimensional scenario in this study based on formation micro-imager imaging logging and the elliptic Fisher model. The findings demonstrate the accuracy and clarity of the proposed 3D fracture occurrence model in reflecting the fracture density and occurrence, as well as the superiority of data simulation. The algorithm described in this study is shown to be very close to the real distribution law. The results enable visualization of the fracture density and occurrence, which is crucial for directing engineering practice and assessing the sensitivity of directional data in other domains.

Semi-Analytical Model for the Transient Analysis of the Pressure in Vertically Fractured Wells in Reservoirs Considering the Influence of Natural Fractures

Abstract In addition to artificial fractures generated by hydraulic fracturing technology, natural fractures distributed in reservoirs will also affect the fluid flow process. To study the transient behavior of the pressure in fluid flows in reservoirs containing natural fractures, a semi-analytical model for vertically fractured wells with complex natural fracture networks was established. This model was based on the linear source function theory and the fracture discretization and coupling methods. It was solved by the Stehfest numerical inversion and the matrix transformation. The results of the study on the fluid flow stages in a reservoir with natural fractures indicated that the presence of natural fractures increased natural fracture flows. These flows were dominated by natural fractures and fracture interference stages and were different from the fluid flows observed in vertically fractured wells with a single main fracture. The sensitivity analysis on the influences of the fluid flow factors in the reservoirs with three types of natural fractures could provide a more detailed reference for the identification of the reservoir parameters and the transient characteristics of the flow stage. The different characteristic curves of the fluid flow in the reservoirs with different scale natural fractures could also provide a theoretical basis for determining the distribution of natural fractures in reservoirs.

Numerical Simulation of Shale Reservoir Fluid-Driven Fracture Network Morphology Based on Global CZM

There are a large number of natural fractures in shale reservoirs, which create great challenges to hydraulic fracturing. Activating the natural fractures in reservoirs can form a complex fracture network, enhance fracturing effects, and increase shale gas production. Reservoir geological conditions (low in situ stress, natural fracture distribution, and cement strength) and operation parameters (fracturing fluid viscosity and injection rate) have an important influence on fracture network propagation. In this article, a two-dimensional hydraulic fracturing fluid-mechanic coupling numerical model for shale reservoirs with natural fractures was established. Based on the global cohesive zone model, the influence of geological conditions and operation parameters on the propagation of the hydraulic fracture network and fracturing process is investigated. The numerical simulation results show that when the horizontal in situ stress difference, approach angle, and cement strength are low, it is easier to form a complex fracture network. Research on the construction parameters indicated that when the viscosity of the fracturing fluid is low, it is easier to form a complex network of fractures, but the length of the fractures is shorter; in contrast, the fractures are straight and long. In addition, increasing the injection rate is beneficial for increasing the complexity of the fracture network while increasing the initiation pressure and width of the principal fracture reduces the risk of sand plugging. This article also proposes an optimization solution for hydraulic fracturing operations based on numerical simulation results.

Methodology and application of shale-reservoir natural fracture modeling based on microseismic monitoring data

Fracturing is a key factor for shale oil and gas enrichment and high production. An accurate fracture model can effectively guide shale oil and gas exploration and development. The establishment of a natural fracture model must address the challenges of difficult data acquisition and poor representativeness of data points. To solve these problems, we have developed a method of shale-reservoir natural fracture modeling based on microseismic monitoring data. This method includes three steps. First, we establish an initial natural fracture model based on scale classification, vertical stratification, and genetic classification. Second, the shape and density of the hydraulic fractures are interpreted by microseismic monitoring data to calibrate the initial model of the shale reservoir natural fractures. Third, we verify the rationality of the model by assessment of the fracture porosity and permeability values. The results show that it is possible to calibrate the natural fracture density model using the fracture shape and density as determined by microseismic monitoring. And we predict that an ideal hydraulic fracture network can be formed when the body density of the natural fracturing is greater than 0.3 m2/m3. The crude production of wells is negatively correlated with the development of large-scale structural fractures and positively correlated with small-scale structural fractures. The well trajectory should run through small-scale fracture development sections as much as possible, avoiding large-scale, high-angle fracture areas. This method provides a new approach to model natural fractures in shale reservoirs that has wide applicability and can be used for modeling shale oil and gas reservoirs.

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.

A new type of high density fracturing fluid system

Deep oil and gas reservoirs enjoy great opulence in resources, and yet the ultra-deep burial, high temperature, high pressure and natural fractures in reservoirs bring great difficulties to propped fracturing. Given the challenge of propped fracturing in deep reservoirs, a new cost saving and high density fracturing fluid system was developed, of which the performance was evaluated and formulation was optimized, and with this fracturing fluid system, wells that cannot be treated before, can now be effectively stimulated. The advanced fracturing fluid system has been applied to eight layers in five wells, which all proved to be successful and effective, with remarkable reservoir stimulation efficacy. The post-production in the formation testing grew twice of the pre-fracturing production, and two wells were seen gas production exceeding one million cubic meters. The advanced fracturing fluid system greatly expands the well depth range of exploration and development, and lays a solid technical foundation for implementation of propped fracturing in deep reservoirs.

Optimal Design of Hydraulic Fracturing for Deep Volcanic Reservoir in Zhungeer Basin

Deep volcanic reservoir in Xinjiang Zhungeer basin is buried over 4000m, the elastic modulus of reservoir rocks is high, hence it is difficult to initiate hydraulic fracture during fracturing operation; fracturing fluid filtration is serious and hard to be controlled due to the massive natural fractures in reservoir. Because of the serious heterogeneity along both horizontal and vertical direction, the optimum targets of design fracturing for different well layers are not the same. 4 out of 12 fracturing wells have not achieved the target amount of proppant. Ultimately, fracturing success rate is low and the production increase after fracturing shows a big difference among different wells. In order to improve the success rate and efficiency of deep volcanic reservoir fracturing, based on the analysis of the difficulties in previous fracturing operation, combined with the geological characteristics of reservoir, we optimized the key engineering parameters of deep volcanic rock fracturing, including perforation parameters, filtration parameters, fracture parameters and operation parameters. Results of fracturing design optimization bear an important guiding significance for improving the fracturing success rate and efficiency of deep volcanic reservoir in Zhungeer basin, Xinjiang province.

FRACTURING FLUID LEAKOFF BEHAVIOR IN NATURAL FRACTURES: EFFECTS OF FLUID RHEOLOGY, NATURAL FRACTURE DEFORMABILITY, AND HYDRAULIC FRACTURE PROPAGATION

This study developed a coupled model for the fracturing fluid loss into natural fractures during a hydraulic fracturing treatment. The model considers a non-Newtonian fracturing fluid, the influence of hydraulic fracture, and the fluid exchange between hydraulic and natural fractures. A semianalytical solution is proposed to solve the coupled model, which demonstrates reliable results through validation study. Parametric studies indicate that increasing the fracturing fluid viscosity can effectively reduce its leakoff at a low viscosity level. While at a high level, further enlarging fluid viscosity may not lead to better control of leakoff. In addition, larger deformability of reservoir rock leads to a faster pressure diffusion and a greater fluid leakoff. Also, the pressure profile inside a fracture takes a concave shape when the deformation of a natural fracture is considered. Moreover, it is found that when a large number of natural fractures open at the same time, fluid leakoff can cause an immediate reduction in the hydraulic fracture width and even screen-out. Therefore, to reduce the operation risks of hydraulic fracturing, the pump rate and fluid rheology must be carefully designed based on the properties of natural fractures in reservoirs.

Geometric nature of hydraulic fracture propagation in naturally-fractured reservoirs

The geometry of hydraulic fracture propagation in the absence and presence of natural fractures in reservoirs was studied. The results revealed a marked influence of natural fractures on the symmetry of fracture propagation observed for rock free of natural fractures. Natural fracture properties such as stiffness and approaching angle, and the distance from wellbore to the natural fracture were found to influence the hydraulic fracture geometry. Furthermore, the location of the wellbore with respect to the natural fractures in a reservoir having a system of natural fractures displayed a significant influence on the resulting geometry of hydraulic fracture propagation.

Mechanism of Fracture Generation in the Hole and Research on Optimization Design of Drilling Fracture Parameters

In order to increase the production of low permeability reservoir inclined or straight well, establish effective communication between the sand and improve development effect. For Daqing periphery low permeability oil field properties, such as large sandbody permeability difference, plane fast phase transition, narrow sandbody and scattered distribution. A straight and inclined well hydraulic fracture stimulation modification technology research and field application was launched. Studied the mechanism of crack generation in the hydraulic drilling hole and analyzed factors of crack situation in the hole of hydraulic drilling fracture, given parameter optimization method of hydraulic drilling fracturing, carried out hydraulic drilling fracturing on spot well selection test. The results show: At reservoir heterogeneity geo stress conditions, after the hydraulic drilling, the fracture cracks always rupture on contact surface of well and hole and then the crack extend along the direction of maximum horizontal stress. So reservoir heterogeneity is a necessary condition for generation of cracks in the hole. To make cracks in a certain position of hole after the hydraulic fracturing, reservoir heterogeneity must be a prerequisite, that there exists natural fractures in reservoir or geo stress heterogeneity. Pressure curve and fracture pressure curves intersect multiple cases. In these cases there will be many perforations along the crack. Considering the stress orientation, petrophysical, sedimentary facies, hole geometry parameters, the overall design system of hydraulic drilling fracturing parameters optimization is given. On spot selected well got a good effect. Liquid production increased to 4.8 from 1.7 tons. Oil production increased to 4.2 from 0.9 tons.

Experimental investigation of hydraulic fracture propagation in fractured blocks

Natural fractures in reservoirs can be the cause of many adverse effects during hydraulic fracturing treatment. In the present paper, hydraulic fracturing tests are used to investigate the interaction of a propagating hydraulic fracture with a natural fracture in the fractured blocks. Systematic experiments were designed and performed on the cement blocks with different pre-existing fracture strikes and dips (30°, 60° and 90°). The effect of horizontal stress difference on the propagation of hydraulic fractures was also determined through a series of experiments with different values for Δσ, which were 5 and 10 MPa, respectively. Propagation arrest of the hydraulic fracture and crossing the pre-existing fracture were two dominating fracture behaviors at horizontal stress differences of 5 and 10 MPa, respectively. It was observed that both the magnitude of differential stress and the pre-existing fracture geometry can magnify the effect of a pre-existing fracture on hydraulic fracture propagation. When the horizontal differential stress is low (5 MPa), the hydraulic fracture crosses the pre-existing fracture at a high pre-existing fracture dip (90°) and at an intermediate to high pre-existing fracture strike (60°–90°), while hydraulic fracture is arrested by the opening of the pre-existing fracture at a pre-existing fracture strike (30°). Meanwhile, when the pre-existing fracture dip is low to intermediate (30°–60°) and its strike is low to high (30°–90°), hydraulic fracture is arrested by the opening and shear slippage of the pre-existing fracture in this situation. However, at a high horizontal differential stress (10 MPa), when the pre-existing fracture dip is low to high (30°–90°), the hydraulic fracture crosses the pre-existing fracture at the strike of the pre-existing fracture of 60°–90°, and when it is decreased to 30°, the hydraulic fracture is arrested by th eopening and shear slippage of the pre-existing fracture. Therefore, the pre-existing fracture’s strike and dip play a significant role in the propagation of hydraulic fracture at a low horizontal stress difference, while the role of the pre-existing fracture dip at a high horizontal stress difference is less than the pre-existing fracture strike on the propagation of hydraulic fracture.

Numerical Simulation of Heat Transfer from Hot Dry Rock to Water Flowing through a Circulation Fracture

This paper presents an advanced computational modeling of natural fracture networks in hot dry rock (HDR) reservoirs. A mathematical model is developed for describing the heat energy extracted from a HDR in a multi-well system. The model stochastically simulates discrete properties of natural fractures, utilizing multi-set orientation and fractal mathematics. The simulated fracture networks are essential for further stimulation and fluid flow studies. The results show that the heat extraction effectiveness is affected significantly by the well spacing, well radius, reservoir thickness, and pumped flow rate in a multi-well system. The water temperature decreases with increasing pumping rate and increases with the well spacing, well radius, and reservoir thickness. This paper also examines the detrimental effects of the simulated natural fracture network on the stimulated fluid flow capacity. The effective permeability enhancement (due to hydraulic stimulation) is found almost proportional to the density of the reservoir natural fractures.

Integration of Seismic Anisotropy and Reservoir-Performance Data for Characterization of Naturally Fractured Reservoirs Using Discrete-Feature-Network Models

SummaryThis paper proposes a method for quantitative integration of seismic (elastic) anisotropy attributes with reservoir-performance data as an aid in characterizing systems of natural fractures in hydrocarbon reservoirs. This method is demonstrated through application to history matching of reservoir performance using synthetic test cases.Discrete-feature-network (DFN) modeling1 is a powerful tool for developing fieldwide stochastic realizations of fracture networks in petroleum reservoirs. Such models are typically well conditioned in the vicinity of the wellbore through incorporation of core data, borehole imagery, and pressure-transient data. Model uncertainty generally increases with distance from the borehole. Three-dimensional seismic data provide uncalibrated information throughout the interwell space. Some elementary seismic attributes such as horizon curvature and impedance anomalies have been used to guide estimates of fracture trend and intensity (fracture area per unit volume) in DFN modeling2 through geostatistical calibration with borehole and other data. However, these attributes often provide only weak statistical correlation with fracture-system characteristics.The presence of a system of natural fractures in a reservoir induces elastic anisotropy that can be observed in seismic data. Elastic attributes such as azimuthally dependent normal moveout velocity (ANMO), reflection amplitude vs. azimuth (AVAZ), and shear-wave birefringence can be inverted from 3D-seismic data. Anisotropic elastic theory provides physical relationships among these attributes and fracture-system properties such as trend and intensity. Effective-elastic-media models allow forward modeling of elastic properties for fractured media.A technique has been developed in which both reservoirperformance data and seismic anisotropic attributes are used in an objective function for gradient-based optimization of selected fracture-system parameters. The proposed integration method involves parallel workflows for effective elastic and effective permeability media modeling from an initial DFN estimate of the fracture system. The objective function is minimized through systematic updates of selected fracture-population parameters. Synthetic data cases show that 3D-seismic attributes contribute significantly to the reduction of ambiguity in estimates of fracture-system characteristics in the interwell rock mass. The method will benefit enhanced-oil-recovery (EOR) program planning and management, optimization of horizontal-well trajectory and completion design, and borehole-stability studies.

Seismic traveltime analysis for azimuthally anisotropic media: Theory and experiment

Natural fractures in reservoirs, and in the caprock overlying the reservoir, play an important role in determining fluid flow during production. The density and orientation of sets of fractures is therefore of great interest. Rocks possessing an anisotropic fabric and a preferred orientation of fractures display both polar and azimuthal anisotropy. Sedimentary rocks containing several sets of vertical fractures may be approximated as having monoclinic symmetry with symmetry plane parallel to the layers if, in the absence of fractures, the rock is transversely isotropic with symmetry axis perpendicular to the bedding plane. A nonhyperbolic traveltime equation, which can be used in the presence of azimuthally anisotropic layered media, can be obtained from an expansion of the inverse‐squared ray velocity in spherical harmonics. For a single set of aligned fractures, application of this equation to traveltime data acquired at a sufficient number of azimuths allows the strike of the fractures to be estimated. Analysis of the traveltimes measured in a physical model simulation of a reverse vertical seismic profile in an azimuthally anisotropic medium shows the medium to be orthorhombic with principal axes in agreement with those given by an independent shear‐wave experiment. In contrast to previous work, no knowledge of the orientation of the symmetry planes is required. The method is therefore applicable to P‐wave data collected at multiple azimuths using multiple offset vertical seismic profiling (VSP) techniques.

Azimuthal variation in AVO response for fractured gas sands

Natural fractures in reservoirs play an important role in determining fluid flow during production, and hence the density and orientation of fractures is of great interest. In the presence of aligned vertical fractures, the reflection amplitude at finite offset varies with azimuth. The effect of natural fractures on the azimuthal AVO response from a gas‐sandstone reservoir encased within shale is investigated. A simple expression for the difference in P‐wave reflection coefficient from the top of the reservoir parallel and perpendicular to the strike of the fractures is obtained in terms of the normal and tangential compliances, ZN and ZT, of the fractures. This expression is valid for small anisotropy and material contrasts and is compared with the results of numerical modelling. For a given value of ZT, the azimuthal variation in reflection coefficient at moderate offsets is found to increase with decreasing ZN/ZT. For gas‐filled open fractures ZN/ZT ≈ 1, but a lower ratio of ZN/ZT may result from the presence of cement or clay within the fractures, or from the presence of a fluid with non‐zero bulk modulus. For ZN/ZT = 1 and moderate offsets, the variation with offset of the reflection coefficient from the top of the fractured unit is dominated by the contrast in Poisson's ratio between the gas sand and the overlying shale, the effect of fractures only becoming noticeable as the critical angle for the unfractured sandstone is approached. However, for reflections from the base of the fractured unit, the variation in reflection amplitude with azimuth is much greater at conventional seismic offsets than for the reflection from the top. Azimuthal variations in the strength of the reflection from the top of the reservoir depend only on the variation in reflection coefficient, whereas the raypath is also a function of azimuth for reflections from the base of the fractured unit, leading to stronger, more visible, variations of AVO with azimuth. It follows that an azimuthal variation in AVO due to fractures in the overburden may be misinterpreted as due to the presence of aligned fractures in the reservoir.

Effect of Multiple Hydraulic Fractures on Gas-Well Performance

Summary This paper describes the use of a single-phase 2D numerical model to study the performance of a well intersected by two perpendicular vertical fractures assumed to have either infinite or finite conductivities. Analysis of the simulated drawdown tests at a constant flow rate showed that the transient flow behavior of a well intersected by finite-conductivity (CfD<500) perpendicular fractures does not exhibit the bilinear and formation linear flow periods. However, when fracture conductivities were infinite (CfD =500), the formation linear flow period was observed. This period was used to determine the fracture half length and gave a fracture half-length equal to the sum of the two fracture half-lengths (xf + yf). The beginning of the pseudoradial flow period for any conductivity was found to decrease as yf/xf increased and to increase as the fracture conductivities increased for a given yf/xf. A single hydraulic fracture gave higher productivity than two fractures of the same total length when fracture conductivity was infinite. However, when fracture conductivity was low, the two fractures gave higher productivity than the single fracture. Introduction Hydraulic fracturing is an effective way to increase the productivity of wells producing from low-permeability formations. Considerable research has been conducted to determine the effect of hydraulic fractures on well performance and pressure-transient behavior. The results have been used to improve the design of hydraulic fractures. The increasing use of hydraulic fracturing to improve the productivity of oil and gas wells in low-permeability reservoirs has resulted in many research efforts aimed at increasing fracturing capabilities and evaluating fracture characteristics in the postfracturing period. The massive hydraulic fracturing (MHF) treatment is now a proven technique for developing commercial wells in low-permeability or tight gas formations. The purpose of MHF is to expose a large surface area of the low-permeability formation (in-situ permeability =0.1 md) to flow into the wellbore. Over the past few decades, hydraulic fracturing and explosive shooting of wells have been used to improve the productivity of tight reservoirs. An alternative to these techniques, one that uses certain features of both but appears better for creating multiple fractures, is tailored-pulse loading. Warpinski et al. in 1979 and Schmidt et al. in 1980 demonstrated that propellants can create multiple fractures in the field without damaging the wellbore region. Their results indicated that the long loading time of the pulse allows greater fracture extension and thus gives more opportunity for connecting a wellbore to the reservoir's natural fracture system.

Application of Aerial Photographic Interpretation to the Study of Reservoir Natural Fracture Systems

Aerial photography, through skillful interpretation, can be a potential source of information on natural fracture orientation in a reservoir. The feasibility of the approach is discussed here on the basis of an investigation conducted in the Midland basin of West Texas. Introduction Well developed natural fracture systems, forming intersecting sets of parallel planes, are extremely common within the rocks of the earth's crust. Extensive and systematic fracturing, generated by large stress fields of natural origin, is widespread in all geomorphological divisions of the earth, including those that are tectonically stable where most of the world's known oil producing basins are located. Over the years, considerable scientific inquiry has been directed toward natural fracture systems found in surface formations. Yet little emphasis has been placed on the fact that natural fractures, far from placed on the fact that natural fractures, far from being restricted to the surface of the earth, are equally prevalent in subsurface rocks at all depths. Thus until prevalent in subsurface rocks at all depths. Thus until recently, the petroleum industry has been less than enthusiastic about acknowledging natural fracture systems as routine structural components of producing formations. Indeed, engineering experience in producing formations. Indeed, engineering experience in the field reveals increasingly that the incidence of natural fracturing in reservoirs is much more common than is generally thought, extending well beyond the classic examples cited in the literature. As is universally recognized, the presence of fractures can enhance productivity in dissolved gas drive reservoirs. If it were not for naturally formed fractures, or for the practice of hydraulically inducing "parting" in formations to increase their productivity, many low-permeability reservoirs would perhaps never be commercial. On the other hand, in a reservoir where a frontal displacement mechanism is in effect, fractures can be highly undesirable. In various papers dealing with this subject, analytical studies papers dealing with this subject, analytical studies supported by field evidence have shown that in a reservoir with a rising water table the presence of fractures will result in lower recovery. Perhaps the most significant aspect of natural fracture systems is that they invariably create troublesome channeling problems in reservoirs undergoing recovery by fluid injection. Many investigations have shown that when fractures are present, volumetric sweep efficiency in a reservoir is adversely affected by, among other controlling factors, the degree of fracturing and the orientation of the fracture sets with respect to the alignment of injection-production well pairs. Consequently, in planning fluid injection programs or in dealing with reservoirs that produce by programs or in dealing with reservoirs that produce by frontal displacement, it is important to establish the spatial attitude of the reservoir fracture planes so that their adverse effects can be avoided or at least minimized. Unfortunately, the investigation of fracture conditions in the subsurface remains a technological frontier. No current engineering or logging method, when used alone, is entirely effective in determining conclusively either the presence or the systematic attitude of fractures in a reservoir. JPT P. 37