Fracture Connectivity Research Articles

A composite temporary plugging technology for hydraulic fracture diverting treatment in gas shales: Using degradable particle/powder gels (DPGs) and proppants as temporary plugging agents

Temporary plugging and diverting fracturing is one kind of technology for efficiency-enhancing the productivity of oil and gas wells, which is widely used in hydraulic fracturing treatments in shale gas reservoirs. However, the closure of unpropped fractures at the temporary plugging zone under the high closure stress post fracturing treatment may influence the efficiency of shale gas well productivity-enhancing. The unpropped temporary plugging zone plays the role of a “closed valve” that would intercept the connection of the old fractures to the flowable fracture system. Thus, a composite temporary plugging technology for hydraulic fracture diverting treatment in gas shales is proposed for solving this problem by using degradable particle/powder gels (DPGs) and proppants as temporary plugging agents. This study examined the adaptability of the DPGs, as well as the proper combinations for composite temporary plugging technology. Moreover, the temporary plugging mechanism and behavior of the composite temporary plugging zone are discussed. Experimental investigation results show that the DPGs have good adaptability for composite temporary plugging technology, and meet the requirements of diverting fracturing within the hydraulic fractures. The optimum experimental combinations are determined, the mass ratio of DPGs to proppants for temporary plugging is 16%, which can ensure the temporary plugging efficiency, as well as the timely removal of plugging. Temporary plugging mechanism and behavior of composite temporary plugging zone are closely related to the internal structure evolution of composite temporary plugging zone, the plugging processes can be divided into bridging and plugging, deformation, adhesiveness, and degradation of DPGs. This study provides the understanding and mechanism of the composite temporary plugging behavior during hydraulic fracture diverting treatment. This technology is of great significance to achieve enhanced and stable production in shale gas reservoirs.

Estimating size of finite fracture networks in layered reservoirs

Conductive fractures in petroleum reservoirs may be totally isolated or fully interconnected. There is an intermediate state between the two extremities. Partially fractured reservoirs include finite fracture networks (FFN), which are bundles of interconnected fractures embedded in a sea of isolated fractures. Devising measures for sizes of FFNs is crucial in estimating critical engineering aspects such as productivity index, production decline rate and expected ultimate recovery of wells especially in reservoirs with low matrix porosity and permeability. Here, we present results of statistical evaluation of FFN size in relation to fracture connectivity which is in essence the number of fracture intersections per fracture. The analysis is based on a large number of stochastic 2-dimensional (2D) Poisson models of sub-vertical layer bound fractures. Fracture length in the models has log normal or truncated power distribution and fracture strike has circular normal distribution. The models may have single or multiple fracture sets and various truncation modes with different probabilities.The analysis shows that number of fracture intersections per fracture can be accurately estimated by a fracture connectivity index, which is defined as product of facture scan-line density, average fracture length and sine of strike standard deviation. The statistically significant finding of this study is that the number of fractures within a FFN is an exponential function of fracture connectivity index. All three fracture properties defining the index can be measured on borehole image logs. Hence it should be possible to estimate fracture connectivity and corresponding FFN size from borehole image data. The analysis pertains to 2D fracture connectivity which is always the lower bound of number of fracture intersections in 3-dimensions. Therefore the exponential relationships must also hold for actual 3-dimensional layer-bound fractures with variable dips.

Hydraulic Fracture Propagation in Denver-Julesburg Basin Constrained by Cross-Well Distributed Strain Measurements

Summary Evaluating hydraulic fracturing completion is critical for low porosity, low permeability unconventional reservoir development. In this study, we use low-frequency distributed acoustic sensing (LF-DAS) measurements to monitor the hydraulic fracturing in the Chalk Bluff field in the Denver-Julesburg (DJ) Basin, Colorado. Interpreting fracture-hits from crosswell LF-DAS data yields insights into the fracture geometry and propagation across and within two targeted formations: Niobrara and Codell. We observe significant differences in hydraulic fracture propagation between the two formations; the half length of hydraulic fractures in the Codell formation is much longer than that in the Niobrara. In addition, hydraulic fracture propagates significantly faster in Codell than in Niobrara under the same pumping rate. The differences could be explained by higher natural fracture density and potentially lower stress anisotropy in the Niobrara formation. We also observed different fracture orientations between the two formations and inconsistent fracture orientations within Niobrara. Hydraulic fractures observed in Codell oriented at 100 degree consistently, while two group of fracture azimuths (110 and 240 degrees) can be observed in Niobrara. The difference in fracture orientations in Niobrara and Codell indicates stress regime changes between the formations. The inconsistency of fracture azimuth in Niobrara may be caused by the zipper fracturing sequence. Strong cross-formation fracture connections between the two formations can also be observed, with different up-going and down-going fracture propagation velocities. These observations help us better understand the complex fracture geometry in the DJ Basin and provide critical constraints on the optimization of the unconventional reservoir development.

Combined Effect of Contact Area, Aperture Variation, and Fracture Connectivity on Fluid Flow through Three-Dimensional Rock Fracture Networks

Abstract In order to investigate the combined effect of contact area, aperture variation, and fracture connectivity on the fluid flow through a fractured medium, a series of flow simulations were implemented on two types of three-dimensional discrete fracture network (3D DFN) models constituting fractures having spatially variable apertures and parallel plates, respectively. The flow tortuosity within the 3D DFN models was examined by changing the density, aperture distribution, and closure of fractures. The results show that compared with the 3D DFN models constituting parallel plates, the model with variable apertures provides more pronounced 3D preferential flow pathways. At the individual fracture scale, the preferential flow pathways mostly converge within the void spaces of large aperture, and at the network scale, they are located in the most transmissive fractures within the connected networks. The permeability of 3D DFNs depends not only on the contact area and aperture variation within individual fractures but also on the fracture connectivity and the contact at fracture intersections within the fracture network. Increasing the fracture connectivity tends to enhance the permeability, while increasing the contact at fracture intersections would significantly reduce the permeability. A correlation between the equivalent permeability of 3D DFNs constituting fractures with spatially variable apertures and parallel plates is proposed incorporating the effect of network-scale topology. A tortuosity factor for 3D DFNs is defined based on the proposed model, and it can account for two competing effects when the model is upscaled from individual fracture to fracture network: the permeability reduction induced by contact obstacles at fracture intersections and permeability enhancement induced by increasing the fracture connectivity.

Method Integrates Pressure-Transient and Fracture Area To Detect Well Interference

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of URTeC paper 208395, “Integration of Pressure-Transient and Fracture Area for Detecting Unconventional-Well Interference,” by Mazher Ibrahim, SPE, Matt Sinkey, SPE, and Thomas Johnston, SPE, Shear Frac Group, et al. The paper has not been peer reviewed. Hydraulic fractures created during completions are assumed to produce back to the original well. While multiwell-pad completions increase efficiencies, they complicate fracture connectivity between wells. The proximity of newly completed wells to a pre-existing producing well suggests a depleted zone that can “steal” fracture surface area. The complete paper presents a real-time method to estimate the stage-to-stage interference and well-to-well interference and their implications on completions efficiency. Introduction The primary challenge for the industry with regard to unconventional resource development is to optimize well spacing to improve well net present value. Shale heterogeneity and completion design influence fracture orientation and geometry. The industry still lacks accurate methods in characterizing these. Fig. 1 shows three well-spacing types that the authors write could be classified as “good,” “bad,” or “ugly”—the A+ spacing type (good), the B spacing type (bad), and the C spacing type (ugly). The A+ spacing type has no interference between wells that perfectly drain the reservoir; however, it is hard to achieve. In the B spacing type, there may be 10–15% interference between either hydraulic or natural fracture systems. B spacing can be achieved with proper integration of reservoir and completion engineering. This spacing type usually can provide more predictable well-level estimated ultimate recovery (EUR). C spacing type is characterized by closer-than-needed spacing, resulting in shared stimulated reservoir volume (SRV) between wells. Some operators use this spacing when oil and gas prices are high in order to accelerate production.

Mineralogy controls fracture containment in mechanically layered carbonates

AbstractUnderstanding the distribution and geometry of faults and fractures is critical for predicting both subsurface permeability architecture and the integrity of geological fluid barriers, particularly in rocks with low primary porosity and permeability. While fracture patterns in relatively competent, weathering-resistant (therefore often well-exposed) rocks are generally well studied in outcrop, the role of mechanically weak layers in defining fracture patterns is frequently overlooked or under-represented. Here we show that rock composition, specifically clay and silicate minerals versus carbonate content, exerts a strong control on fault and fracture propagation and bed-containment within a mechanically layered, Cretaceous carbonate sequence at Canyon Lake Gorge, Texas. We find that relatively incompetent, clay-rich layers limit fault and fracture propagation, and cause bed-containment of fractures in more competent beds. In our results, no clear relationships exist between mechanical layer thickness and fracture abundance. These results are important for understanding the relative importance of composition versus bed thickness on fracture abundance in the subsurface, and for predicting fracture-controlled fluid flow pathways, seals and fracture connectivity across beds with variable compositions, thicknesses and competences.

Effects of Thermal Stress in Hot Dry Rock Fracturing

Summary China has rich geothermal hot dry rock (HDR) resources, but the development and usage of its thermal energy are still at an early stage. At present, few studies have investigated the variation law for fracturing pressure on the borehole wall and fracture wall under the influence of thermal stress. This study investigates the fracturing pressure around the borehole wall based on rock mechanics and thermal stress analysis. Two models were developed: one for borehole wall fracturing pressure with consideration for thermal stress and the other for temperature difference conditions related to the automatic opening of fractures. By analyzing the temperature variation in the fracture wall, the mechanism for the opening of branch fractures at the fracture wall was investigated based on rock mechanics, the theory of fracture extension in hydraulic fracturing, and the theory of thermal stresses. We developed a computational model for tensile or shear damage related to branch fractures in the fracture wall with consideration for thermal stress, as well as a model for temperature difference conditions for the automatic opening of branch fractures. The simulation results show that the fracturing pressure decreased significantly when thermal stress was considered. Under normal geostress and temperature conditions, large temperature difference conditions are needed for the HDR borehole wall to break naturally because of thermal stress alone. During fracture extension, branch fractures on the fracture wall are more likely to form because of thermal stress. Irrespective of the type of damage (tensile or shear), branch fractures on the fracture wall closer to the borehole required lower net fracturing pressure. The decline in the net fracturing pressure was greater in response to shear damage than to tensile damage. In a high-temperature thermal reservoir, when branch fractures in the fracture wall were subjected to the temperature difference conditions for automatic opening, shear damage was more likely to occur than tensile damage. From the results, the following conclusions were obtained: The developed mechanical model of fracture opening reflects the mechanism of fracturing at the borehole wall and the fracture wall during HDR fracturing, thereby revealing the mechanism of the formation of fracture networks under thermal stress. For HDR fracturing, thermal stress promotes the formation of branch fractures in the fracture wall and increases the occurrence of complex fractures in the near-well region. Under thermal stress, the main fractures are less likely to extend in the optimal direction but instead tend to develop into complex fractures, which is not conducive to fracture connectivity between wells.

Thermal response of the fractured hot dry rocks with thermal-hydro-mechanical coupling effects

In order to efficiently exploit geothermal energy, the reasonable configuration of fracture network should ensure the minimum water loss, high flow rate, high production temperature, and good connectivity between injection wells and production wells. To achieve the above objectives, the operating parameters of the EGS project should be balanced with the reservoir characteristics. In this paper, the THM coupling model is established in the finite element solver, which analyzes the influence of formation stress, injection pressure, roughness of fracture surface, fracture intersection angle, and fracture connectivity on fluid seepage pressure and outlet temperature. The accuracy of the model was verified by comparison to analytical solutions. The results show that although the increased vertical stress, fracture surface roughness and intersection angle will increase the flow resistance, the temperature of fracture fluid will rise faster. On the contrary, the increase of injection pressure will expand the fracture aperture and lead to the temperature of the fracture fluid rises slowly. In addition, not all fractures contribute to the productivity of the hot dry rocks (HDRs) type of reservoirs, while only the interconnected fractures are effective. The flow rate of production will increase when fracture density increases under the condition of connecting the injection well and production well, but the production temperature will decrease. The relative importance of the individual parameter alone is not enough to directly measure the optimal engineering parameters, so considering the impact of multiple parameters comprehensively is crucial for EGS project development and directly affects its commercial viability.

Numerical solution of Biot equations in quasistatic state for seismic attenuation estimation in anisotropic media

An algorithm for numerical upscaling elastic properties of fractured-porous media in low-frequency range is presented. To do so, the algorithm to solve Biot equations in quasi-static state is developed. Paper describes the following aspects: stating the problem of the poroelastic media upscaling to obtain frequency-dependent stiffness tensor, corresponding to the visco-elastic media; the finite-difference approximation of the considered boundary-value problem; peculiarities of the numerical solution of the SLAE with numerical experiments and performance analysis. Numerical experiments are performed to observe the influence of fracture connectivity and fracture-filling material properties on frequency-dependent seismic attenuation in fractured porous fluid-saturated media.

Mapping the possible origin of anomalous saline water occurrence in Agbabu, Eastern Dahomey Basin, Nigeria: insights from geophysical and hydrochemical methods

Many researchers have suspected saltwater occurrence in Agbabu in the eastern Dahomey Basin. However, there is a need to get an insight to the possible origin of saltwater in the area. The aim of this study is to determine the source of saltwater in the inland aquifers of Agbabu, southwestern Nigeria for proper management of scarcely available freshwater resource in the area. 23 vertical electrical sounding, 2D electrical resistivity tomography (ERT), aeromagnetic and hydrochemical data (11 subsurface water samples) analyses were utilized in this study. The results from the magnetic analysis revealed the inland extension of the Chain Fracture Zone (CFZ). This NE-SW trending fracture zone cuts across the entire eastern Dahomey Basin, including Agbabu and its environs. Four (4) geoelectric layers were delineated across Agbabu namely, the topsoil (4 - 2806 Ωm), clayey sand (3 - 1280 Ωm), clayey (3 - 161 Ωm) and bituminous sand (1 - 10390 Ωm) layers. Anomalously low resistivity (1 - 20 Ωm) zones suspected within the bituminous sand correspond to the saltwater intrusion zones. The bituminous sand unit harbouring freshwater exhibits characteristic resistivity values of 33 – 160 Ωm. The interface between the freshwater and saltwater intruded zones in the area was suspected at 10 m depth with resistivity values ranging between 21 Ωm and 33 Ωm. The results from the hydrochemical water analysis also confirmed the presence of saltwater intrusion in the area. The salinity extent chart which was generated from the VES results indicated the mobility of the saltwater into the groundwater system. The fracture connectivity between the complex aquifers of Agbabu and the Atlantic Ocean (CFZ), that was mapped from the aeromagnetic and electrical resistivity results, is suspected to be primarily controlling the localization of saltwater in the study area.

Stress–strain and acoustic emission characteristics of cement-based materials used to simulate soft rock with fractures

Instability failure in rock mass engineering is closely related to expansion of joint fissures. In this study, uniaxial compression tests and acoustic emission (AE) measurements were carried out simultaneously on specimens of soft rock-like material with different fracture angles and connectivity values to better understand their influence on the deformation and failure of the material. The stress–strain curve and AE signal of fractured soft rock-like material are similar to those of intact soft rock-like; specifically, they exhibit a compaction, elastic deformation, stable fracture development, and unstable fracture development. The main differences between fractured and intact material occur during post-peak failure stage. Under the combined influence of fracture angle and connectivity, the uniaxial compressive strength of fractured soft rock-like material (f_{cu}^{^{prime}}) is lower than that of the intact soft rock-like material (fcu), and can be described by the relationship f_{cu}^{^{prime}} = f_{cu} cdot alpha, where alpha is the strength reduction coefficient, fitted as alpha = 0.8228 + 0.00411x - 0.00789y. In this equation, x is the fracture angle (^circ) and y is the fracture connectivity (%). Under uniaxial compression, the main types of secondary cracks were wing cracks and secondary coplanar cracks. The specimen with a fracture angle of 30° mainly underwent tensile failure under loading, whereas those with fracture angles of 45° and 60°mainly experienced shear failure under high-connectivity conditions (45%).

Influence of fracture connectivity and shape on water seepage of low-rank coal based on CT 3D reconstruction

The shape and connectivity characteristics of coal fractures are important factors that affect the permeability of coal and the migration of water in the coal during water injection. In this study, a microscopic and mesoscopic fracture model of coal is constructed by using CT 3D reconstruction technology. Based on this model, the fracture connectivity parameters are selected and analyzed, and the gray correlation method for comprehensive evaluation is adopted to determine the relationship between permeability and fracture connectivity. Then, the shape factor η is introduced, the water injection seepage flow is simulated through the Navier-Stokes equation, and the seepage in the fractures with different shape factors is analyzed. The results show that the permeability of coal have a strong correlation with the fracture connectivity parameters, and the correlation order is average coordination number > porosity > maximum Feret diameter. Furthermore, the fracture shape factor is positively correlated with the maximum Feret diameter. In addition, the steady flow velocity increases with the increase of the shape factor. The fractures with η > 2 significantly increases the permeability of coal, but fractures with large shape factors are still the most important channels for seepage.

Multiscale Fracturing in Medium- to Low-Rank Coals and Its Implications on Coalbed Methane Production in the Baode Area, Eastern Ordos Basin, China

Coal fractures are crucial in affecting the production of methane from coal. Multiscale fracturing and its implications on coalbed methane production have still not been fully understood. Herein, we present a case study, combining underground coal mine surveying and specimen, thin section, and scanning electron microscope observations for illustrating the ~m-, ~cm-, ~mm-, and ~μm-scale fractures present in the Baode area, eastern Ordos Basin, China. Then, the fracture connectivity is evaluated by helium permeability and mercury porosimetry measurement. The coals are mainly of semibright, semidull, and dull macrolithotypes. And main maceral composition is vitrinite, accounting for 73%~95%, with around 26% inertinite. The coals are ultralow-ash and low-ash content, belonging to high-volatile bituminous coal. The ~m scale fractures can penetrate the whole coal seams, dominant by S-N and following E-W direction, which were generated during the Yanshanian and Himalayan movements. The ~cm fractures are generally parallel to the lamina, influenced by the bright and dull coal band extension caused by the depositional differences. The ~mm fractures are mainly shown as endogenous fractures perpendicular to the lamina restricted within bright macrolithotypes. There are also ~mm fractures that are perpendicular to the lamina while penetrating dull components and fractures parallel to the lamina. The ~μm fractures are widely distributed and connect each other. Some of the fractures are filled with carbonate and clay minerals and are beneficial for methane migration, caused by hydraulic fracturing. The average mercury withdrawal efficiency of the coals was 75%. The helium permeability of the coals was between 10 × 10 − 3 and 50 × 10 − 3 μm2, indicating good fracture connectivity. The study findings, which indicated the presence of fractures of different scales in the coals studied, can be used for fully understanding the coalbed methane performance of medium- and low-rank coals.

Fracture Effectiveness Evaluation of Ultra-Deep Tight Sandstone Reservoirs: A Case Study of the Keshen Gas Field, Tarim Basin, West China

Fracture effectiveness evaluation has an important impact on the efficient exploration and development of ultra-deep fractured reservoirs. Based on the liquid production profile results collected during the development of the Keshen gas field and based on the traditional static evaluation of fracture density, opening and filling degree, the fracture effectiveness evaluation of ultra-deep reservoirs is carried out from the perspectives of fracture activity, fracture opening and fracture connectivity. The results show that the static characteristics, such as fracture density and fracture properties, are only some factors that determine the effectiveness of fractures. From the perspective of contributions to reservoir permeability, dynamic parameters such as fracture activity, fracture opening and fracture connectivity are the key factors in determining the effectiveness of fractures. Practice has proven that fractures with a high shear ratio, low stress environment and high connection with the fracture system around the well are the main seepage channels for oil and gas supply in the development process. The research results provide a scientific basis for well location deployment, optimization of reconstruction intervals and optimization of development schemes.

Quantitative Evaluation of Well Performance Affected by Fracture Density and Fracture Connectivity in Fractured Tight Reservoirs

Understanding the relationship between petroleum recovery and characteristics of hydraulic fracture network is a key component of economic development of tight reservoirs. Owing to the limitations inherent in current reservoir simulators, optimization of fracture network has been simply focused on the parameters of fracture conductivity, fracture number, aperture, and so on. Deeper insight into the effect of decisive parameters, such as fracture density and fracture connectivity on the well production in tight reservoirs, is now required to maximize the petroleum recovery. In this work, a newly developed discrete fracture simulator is applied to comprehensively study the effect of fracture density and fracture connectivity in tight reservoirs. Conceptual models with different fracture densities and different fracture connectivity are firstly designed and simulated to explore how these two parameters affect the reservoir behavior and establish the equations for effect measurement. Then, we simulate models with different well placement strategies and a fixed set of natural fractures to determine the optimal strategy. Finally, simulations are performed on a field-scale reservoir with three long fractured horizontal wells. Results demonstrate that increases in either fracture density or fracture connectivity can significantly improve well production. However, an optimal value exists considering the economic profit. Compared to the fracture density, fracture connectivity plays a more important role in affecting the well production. In a tight reservoir with abundant natural fractures, making the horizontal well parallel to the direction of natural fractures is determined to be the optimal well placement strategy. The heterogeneous distribution of remaining oil in real tight oil reservoirs is mainly caused by the heterogeneous distribution of fracture density and fracture connectivity.

The quantitative characterization of hydraulic fracture connectivity from a postmortem investigation

AbstractTwo bio-siliceous Onnagawa (ONG I and ONG II) shale samples have been hydraulically fractured under two constant differential stresses (60 and 85 MPa, respectively) to investigate the fracture network's connectivity evolution by a postmortem analysis. The pressure inside the drilled borehole in a cylindrical core sample is increased above the confining pressure (10 MPa) until failure by hydraulic fracture. The two samples failed at two different borehole pressures (ONG I: 42 MPa, ONG II: 16 MPa). Fractured samples were scanned in an industrial X-ray CT machine and the tomographic images of the fracture network were extracted for a postmortem investigation. From the fracture volume segments, obtained by thresholding the frequency distribution of the fracture network's voxel values, a quantitative estimation of fracture connectivity was carried out. The connectivity was quantified based on the relative entropy of size distribution of fractures (${H_r}$), a method adapted from information theory. Fracture connectivity estimation shows that ${H_r}$ is at a maximum value when the fractures show a significant distribution with very limited connectivity. The value of ${H_r}$ is at a minimum and close to 0 when a well-linked fracture network is formed. In both samples, this minimum was attained at the threshold of 43k indicating the highest connectivity and the best representation of the fracture network. The extracted fracture network of ONG I showed a multi-winged hydraulic fracture network while a planar conventional two-winged hydraulic fracture network had been generated in ONG II with a lower fracture volume.

Experimental Study on Connection Characteristics of Rough Fractures Induced by Multi-Stage Hydraulic Fracturing in Tight Reservoirs

The well spacing for the development of tight reservoirs by multi-stage fracturing is continuously narrowed. Consequently, interwell interference during fracturing is more and more serious, accompanied by a host of issues in fracturing design and oil and gas production. However, the mechanism of interwell interference during fracturing is not explicit. The corresponding laws of the connectivity of rough fractures during fracturing, which plays a critical role in interwell interference, are not fully understood. In this study, on the basis of characterizing the roughness of fractures, a laboratory evaluation method for fracture connectivity was established. The connectivity characteristics of rough fractures and factors affecting the fracture connectivity are studied. The time and scale effects of fracture connectivity were discussed and their application in interwell interference was analyzed. The results show that the connectivity performance of rough fractures can be characterized by the time for pressure decay. The upstream pressure gradually decreases over time, and the decline rate is related to the fracture aperture, the fracture surface roughness, the contact area of the closed fractures, and liquid properties. Specifically, the decrease in fracture aperture and the increase in fluid viscosity leads to a significant reduction in fracture connectivity. While larger fracture surface roughness and contact area can make fracture connectivity better. The connectivity of the fracture system is one of the significant mechanisms causing interwell interference during fracturing. The connectivity of rough fractures formed during fracturing has remarkable scale and time effects. This study can effectively guide the fracturing design and the evaluation of the impact of fracture connectivity on production.

Well Interference and Fracture Geometry Investigation Using Production and Low-Frequency Distributed Acoustic Sensing Data in an Unconventional Reservoir

Summary Well interference directly impacts well spacing optimization and well economics, thus it has received significant attention. Observed in many unconventional reservoirs, well interference is mainly attributed to connection of hydraulic fractures. Few studies have compared the hydraulic fracture connection during stimulation with that during the production period. This study connects these two aspects by leveraging the low-frequency distributed acoustic sensing (LF-DAS) signals acquired during the stimulation and the daily production data of 23 horizontal wells in the Denver-Julesburg (DJ) Basin. Strong cross-formation communication between Niobrara and Codell has been identified from both LF-DAS and production data. Interwell fracture connection could divert up to 80% of a shut-in well’s production to the offset well in the adjacent formation, revealing that well interference can be evaluated through random shut-ins of wells during production. Further, fracture connection in LF-DAS data is observed between Codell wells but rarely between Niobrara wells. Given the average Codell well spacing of 1,270 ft and Niobrara well spacing of 650 ft, we observe that the half-length of the stimulated hydraulic fractures in Codell wells is significantly longer than that of Niobrara wells. This study also confirms that stronger well interference during production correlates with strong fracture connection identified from LF-DAS.

Numerical study of the mud loss in naturally fractured oil layers with two-phase flow model

Drilling in the naturally fractured formations always encounters severe mud loss, which endangers the drilling safety. In oil & gas layers, a larger quantity of mud loss has great adverse effects on later oil and gas production. Therefore, it makes the knowledge of mud loss very important, and after that, it is instructive to control the mud loss in the oil layer. In this paper, we first consider the mud loss process using a two-phase flow model. A discrete fracture network model is employed to describe the fluid transfer between fractures and matrix pores. And different relative permeability curves and capillary pressure functions are used in matrix pores and natural fractures. The finite element method and “upwind” scheme are employed to deduce the numerical discretized formulas. The correctness of our model is verified with the published literature. Then a sensitivity analysis is performed to study the laws of mud loss in naturally fractured oil-wet formation. Compared with single-phase flow models, the mud loss rate of two-phase flow model is lower. The two-phase flow model is used to identify the most influential factors on mud loss and predict the distribution of water saturation in oil formation during the drilling process. We find that: since the pressure increase zone is much larger than the water saturation increase zone, the size of the water invasion zone is unknown in the single-phase flow model. The most important influential factors of mud loss in the oil layer are fracture connection, drilling fluid density and matrix permeability. Once the natural fractures are connected to the wellbore, the mud loss rate is much higher than that when the natural fractures are not connected to the wellbore. The capillary pressure has little effect on the mud loss. The larger the capillary pressure, and the lower the mud loss rate. The model in this paper is instructive to learn the law of mud loss and contamination range of drilling fluids in oil layers.

Effects of Fracture Connectivity on Rayleigh Wave Dispersion

AbstractPassive seismic characterization is an environmentally friendly method to estimate the seismic properties of the subsurface. Among its applications, we find the monitoring of geothermal reservoirs. One key characteristic to ensure a productive management of these reservoirs is the degree of fracture connectivity and its evolution, as it affects the flow of fluids within the formation. In this work, we explore the effects of fracture connectivity on Rayleigh wave velocity dispersion accounting for wave‐induced fluid pressure diffusion (FPD) effects. To this end, we consider a stratified reservoir model with a fractured water‐bearing formation. For the stochastic fracture network prevailing in this formation, we consider varying levels of fracture density and connectivity. A numerical upscaling procedure that accounts for FPD effects is employed to determine the corresponding body wave velocities. We use a Monte‐Carlo‐type approach to obtain these velocities and incorporate them in the considered fractured reservoir model to assess the sensitivity of Rayleigh wave velocity dispersion to fracture connectivity. Our results show that Rayleigh wave phase and group velocities exhibit a significant sensitivity to the degree of fracture connectivity, which is mainly due to a reduction of the stiffening effect of the fluid residing in connected fractures in response to wave‐induced FPD. These effects cannot be accounted for by classical elastic approaches. This suggests that Rayleigh wave velocity changes, which are commonly associated with changes in fracture density, may also be related to changes in interconnectivity of pre‐existing or newly generated fractures.