Natural Fracture Network Research Articles

Enhanced Recovery of Crude Oil From Shale Formations by Gas Injection in Zipper-fractured Horizontal Wells

The zipper-frac technique is implemented in two adjacent horizontal wells to maximize the exposure of shale rocks. The hydraulic fractures are propagated in a manner in which they are connected with natural fracture network to improve the fracture complexity. In this study, the authors exploit the advantage of stimulated fracture complexity to access more of the hydrocarbons trapped in very low permeability of shale matrix. The recovery process efficiencies by cyclic CO2 injection and CO2 flooding in zipper-fractured horizontal wells are compared. The role of diffusion recovery mechanism in recovering oil from fractured shales will be discussed.

Large-scale poroelastic fractured reservoirs modeling using the fast multipole displacement discontinuity method

Summary An effective approach to modeling the geomechanical behavior of the network and its permeability variation is to use a poroelastic displacement discontinuity method (DDM). However, the approach becomes rather computationally intensive for an extensive system of cracks, particularly when considering coupled diffusion/deformation processes. This is because of additional unknowns and the need for time-marching schemes for the numerical integration. The Fast Multipole Method (FMM) is a technique that can accelerate the solution of large fracture problems with linear complexity with the number of unknowns both in memory and CPU time. Previous works combining DDM and FMM for large-scale problems have accounted only for elastic rocks, neglecting the fluid leak-off from the fractures into the matrix and its influence on pore pressure and stress field. In this work we develop an efficient geomechanical model for large-scale natural fracture networks in poroelastic reservoirs with fracture flow in response to injection and production operations. Accuracy and computational performance of the proposed method with those of conventional poroelastic DDM are compared through several case studies involving up to several tens of thousands of boundary elements. The results show the effectiveness of the FMM approach to successfully evaluate field-scale problems for the design of exploitation strategies in unconventional geothermal and petroleum reservoirs. An example considering faults reveals the impact of reservoir compartmentalization because of sealing faults for both geomechanical and flow variables under elastic and poroelastic rocks. Copyright © 2015 John Wiley & Sons, Ltd.

Natural-hydraulic fracture interaction: Microseismic observations and geomechanical predictions

Natural fractures can reactivate during hydraulic stimulation and interact with hydraulic fractures producing a complex and highly productive natural-hydraulic fracture network. This phenomenon and the quality of the resulting conductive reservoir area are primarily functions of the natural fracture network characteristics (e.g., spacing, height, length, number of fracture sets, orientation, and frictional properties); in situ stress state (e.g., stress anisotropy and magnitude); stimulation design parameters (e.g., pumping schedule, the type/volume of fluid[s], and proppant); well architecture (number and spacing of stages, perforation length, well orientation); and the physics of the natural-hydraulic fracture interaction (e.g., crossover, arrest, reactivation). Geomechanical models can quantify the impact of key parameters that control the extent and complexity of the conductive reservoir area, with implications to stimulation design and well optimization in the field. We have developed a series of geomechanical simulations to predict natural-hydraulic fracture interaction and the resulting fracture network in complex settings. A geomechanics-based sensitivity analysis was performed that integrated key reservoir-geomechanical parameters to forward model complex fracture network generation, synthetic microseismic (MS) response, and associated conductivity paths as they evolve during stimulation operations. The simulations tested two different natural-hydraulic fracture interaction scenarios and could generate synthetic MS events. The sensitivity analysis revealed that geomechanical models that involve complex fracture networks can be calibrated against MS data and can help to predict the reservoir response to stimulation and optimize the conductive reservoir area. We analyzed a field data set (obtained from two hydraulically fractured wells in the Barnett Formation, Tarrant County, Texas) and established a coupling between the geomechanics and MS within the framework of a 3D geologic model. This coupling provides a mechanics-based approach to (1) verify MS trends and anomalies in the field, (2) optimize conductive reservoir area for reservoir simulations, and (3) improve stimulation design on the current well in near-real-time and well design/stimulation for future wells.

Experimental study of step-displacement hydraulic fracturing on naturally fractured shale outcrops

Low porosity and permeability make it extremely difficult to develop shale oil and gas reservoirs. The stimulated reservoir volume is believed to have potential to obtain industry production by multi-stage or simultaneous fracturing in horizontal wells. The formation mechanism of network hydraulic fractures in fractured shale reservoirs remains poorly understood. In this article, a true tri-axial hydraulic fracturing system associated acoustic emission monitor was deployed to simulate hydraulic fracturing on shale outcrops. Results showed that the properties of natural fractures (such as aperture, orientation), compared to the viscosity and displacement of the fracturing fluid, affect the propagation direction of hydraulic fractures more predominantly. Each natural fracture in a natural fracture network can independently affect the hydraulic fracture. Low displacement (below the diffusion ability of a reservoir) fracturing tends to connect pre-existing fractures, while high displacement (surpass the diffusion ability of a reservoir) tends to create new fractures. After the breakdown pressure, an increase in injection rate results in more acoustic emission energy and induces new fractures. These results suggest that step-displacement fracturing technology is a possible mechanism to obtain effective fracture networks. Such an understanding would help to avoid unproductive, or sometimes destructive, costly segments of the hydraulic fracturing treatment design.

The Fuling Shale Gas Field — A highly productive Silurian gas shale with high thermal maturity and complex evolution history, southeastern Sichuan Basin, China

The organic-rich Lower Silurian Longmaxi and Upper Ordovician Wufeng Shale (LSLUOWS) is one of the most important marine shale gas plays in southern China, with relatively high thermal maturity and complex structural evolution. The delineation of the Jiaoshiba shale gas play has been highly successful for the LSLUOWS in the Fuling area of southeastern Sichuan Basin. The drilling targets the basal part of the LSLUOWS, where the approximately 38–45 m of organic-rich (total organic carbon of greater than 2%) section corresponds to a maturity range around 2.2%–3.0% Ro, with high brittle mineral content (55%–65%). The produced shale gas displays a clear reversal in the stable carbon isotopes. The shale gas play zone is between the overlain mudstone in the Middle-Upper Longmaxi Formation (Fm) and the underlain Upper Ordovician tight limestone in the Jiancaogou Fm. The shale gas reservoir is overpressured, with an average pressure coefficient of 1.55 (relative to hydrostatic pressure). From December 2013 to late 2014, results of production tests determined relatively stable pressure and production curves. Fifty prolific gas wells have been completed to date in the Jiaoshiba Shale Gas Field in Fuling. Preliminary study revealed several characteristics of this structurally complex shale play that are distinctly different from those in the United States, including an anticlinal structure with mild deformation, abundant free gas, and very short gas migration through microfractures, the natural fracture network formed by the two fault systems, and the slip parallel to the layer in the basal LSLUOWS. Movement along strike-slip faults has gone through up into the Quaternary, which is considered to be a significant factor in the establishment and preservation of the overpressured region in the LSLUOWS.

Extended finite element method for analysis of multi-scale flow in fractured shale gas reservoirs

Economic exploration for shale gas is highly dependent on the complexity of the fracture network caused by hydraulic fracturing technology, so it is necessary to accurately assess the effect of the fracture network on gas flow behavior and productivity. Having multiple scales is a remarkable characteristic of gas flow in fractured shale gas reservoirs, which involves multiple flow regimes, including the gas desorption from shale matrix, Knudsen flow in nanoscale pores, Darcy flow in general porous media, Darcy flow in the fracture networks and fluid exchange between the matrix system and the fracture system. The extended finite element method (XFEM) has been integrated with the dual-permeability method (DPM) to investigate the multi-scale problem. Some previous studies have adopted the same solution scheme, but usually considered gas flow in the natural fracture network and in the hydraulic fractures as belonging to the same scale, and in addition, the coverage area of the stimulated reservoir volume (SRV) was underestimated. Based on the XFEM–DPM, this paper subsumes flow in the micro-mecro fractures and macro-hydraulic fractures under two scales because of their different effects on shale gas flow and then presents a new multi-scale extended finite element model to study the multi-scale flow problem in shale gas reservoirs. Moreover, the Lagrangian multiplier method is integrated to introduce the internal well boundary conditions into the XFEM, so the arbitrariness and the asymmetry of the complex fracture network can be taken into account easily to reflect the real flow mechanisms in fractured shale. Case studies indicate that the improved extended finite element model constructed in this paper is effective, especially for complicated asymmetrical physical condition problems.

Curlew-C: realising production from a UK Central North Sea chalk field

Shell's Curlew-C Field was discovered by well 29/7-5 in 1983 which found light, 40°API, oil in a gentle 4-way dip-closed inversion structure, comprising fractured, heterogeneous chalks of the Upper Cretaceous-Palaeocene Tor and Ekofisk Formations. The chalk reservoir consists of both pelagic “autochthonous” coccolithic mudstone units and reworked “allochthonous” reworked beds comprising slides, slumps, debrites and turbidites. Average reservoir porosities vary from 12% to 28% with average matrix permeabilities from 0.1 to 1mD. However, the presence of a pervasive fracture network is demonstrated by image logs, with areas of greatest fracture density in the lower porosity pelagic units of the Ekofisk/Tor Formations. This has resulted in effective permeabilities ranging from 8 to 84mD. The fracture orientation is predominantly NNE–SSW, parallel to a fault that cuts through the structure. A Free Water Level (FWL) has not been penetrated and is assumed to lie well below the mapped structural spill point. The Ekofisk and Tor Formation reservoirs have been developed to date via a single, 4000ft long horizontal well, CuCP1z, oriented NE–SW, perpendicular to the direction of maximum horizontal in situ stress. The well was targeted to penetrate the relatively less fractured, reworked slumped units of higher porosity. Key to productivity was to connect the well to the natural fracture network through hydraulic fractures propagating parallel to the maximum horizontal stress. Cumulative oil produced to date is 2.6MMbbl (3.9MMboe including gas). No water has been produced.

Modified Random Walk–Particle Tracking method to model early time behavior of EOR and sequestration of CO 2 in naturally fractured oil reservoirs

Abstract We modified the Random Walk–Particle Tracking (RW–PT) technique to simulate fully miscible CO 2 injection, including matrix–fracture interaction, in naturally fractured oil reservoirs. After creating and validating the fracture network of a pilot test area for CO 2 flooding, we first performed a sensitivity analysis and investigated the effect of different parameters (such as spacing between fractures and fracture lengths, fracture and matrix permeability, fracture–matrix interaction parameters, etc.) on the performance. Secondly, we performed a history match study to reproduce the observed CO 2 production rate and achieved a good agreement between production and simulated data. We discussed the possibility of using the same technique to simulate the early stages of CO 2 sequestration in naturally fractured reservoirs while injecting it for oil recovery. Although the introduced model does not capture the whole complexity of a miscible flow in fractured porous media due to its inherent characteristics, it can be used to estimate fully miscible transport processes in naturally fractured reservoirs, including CO 2 flooding and the early stages of sequestration, as it has the capability of representing the complexity of natural fracture networks and matrix interaction. The simplifications used in the modeling and the limitations of the suggested technique are described as well.

Modeling transient flow behavior of a multiscale triple porosity model for shale gas reservoirs

Gas flow in shales is a complex process from nanoscale to macroscale which includes diffusion of dissolved gas molecules in kerogen bulk, desorption from the pore walls, Knudsen diffusion and slip flow in nanopores, and conventional flow in natural fracture network according to recent studies. However, little work has been done in literature to simultaneously incorporate all these complex storage and flow mechanisms in well testing models for shale gas reservoirs. This paper presents a new tri-porosity model for shale gas reservoirs to describe that gas flows from formation to wellbore with consideration of all the mechanisms mentioned above. Compared with current well testing models for shale gas reservoirs, this model will be more close to the actual reservoir situation by simulating the physics behind the actual process. Partial differential equations of this tri-porosity model are derived and Laplace transform is employed to solve these equations analytically. The analytical solution of the transient pressure is obtained in real space with Stehfest numerical inversion method, and standard bi-logarithmic type curves are plotted. The characteristics of transient pressure behavior are analyzed thoroughly and different flow regimes are observed in type curves for shale gas reservoirs. Effects of relevant parameters are analyzed as well, which has important significance to understand the transient flow behavior for shale gas reservoirs.

Reservoir simulation and optimization of Huff-and-Puff operations in the Bakken Shale

A numerical reservoir model was created to optimize Huff-and-Puff operations in the Bakken Shale. Huff-and-Puff is an enhanced oil recovery method in which a well alternates between injection, soaking, and production. Injecting CO2 (or other gases) into the formation and allowing it to “soak” re-pressurizes the reservoir and improves oil mobility, boosting production from the well. A compositional reservoir simulator (CMG GEM) was used to study various design components of the Huff-and-Puff process in order to identify the parameters with the largest impact on recovery and understand the reservoir’s response to cyclical gas injection. It was found that starting Huff-and-Puff too early in the life of the well diminishes its effectiveness, and that shorter soaking periods are preferable over longer waiting times. Huff-and-Puff works best in reservoirs with highly-conductive natural fracture networks, which allow CO2 to migrate deep into the formation and mix with the reservoir fluids. Doubling the number of hydraulic fractures per stage results in considerably greater gas injection requirements without proportionally larger incremental recovery factors. Incremental recovery from CO2 Huff-and-Puff appears to be insufficient to make the process commercially feasible under current economic conditions. However, re-injecting mixtures of CO2 and produced hydrocarbon gases was shown to be technically and economically viable, and could significantly improve profit margins of Huff-and-Puff operations.

Defining structural permeability in Australian sedimentary basins

Declining conventional hydrocarbon reserves have triggered exploration towards unconventional energy, such as CSG, shale gas and enhanced geothermal systems. Unconventional play viability is often heavily dependent on the presence of secondary permeability in the form of interconnected natural fracture networks that commonly exert a prime control over permeability due to low primary permeabiliy of in situ rock units. Structural permeability in the Northern Perth, SA Otway, and Northern Carnarvon basins is characterised using an integrated geophysical and geological approach combining wellbore logs, seismic attribute analysis and detailed structural geology. Integration of these methods allows for the identification of faults and fractures across a range of scales (millimetre to kilometre), providing crucial permeability information. New stress orientation data is also interpreted, allowing for stress-based predictions of fracture reactivation. Otway Basin core shows open fractures are rarer than image logs indicate; this is due to the presence of fracture-filling siderite, an electrically conductive cement that may cause fractures to appear hydraulically conductive in image logs. Although the majority of fractures detected are favourably oriented for reactivation under in situ stresses, fracture fill primarily controls which fractures are open, demonstrating that lithological data is often essential for understanding potential structural permeability networks. The Carnarvon Basin is shown to host distinct variations in fracture orientation attributable to the in situ stress regime, regional tectonic development and local structure. A detailed understanding of the structural development, from regional-scale (hundreds of kilometres) down to local-scale (kilometres), is demonstrated to be of importance when attempting to understand structural permeability.

To What Extent Could Shale Gas “Fracking” Contaminate Ground Water

The possibility to economically produce gas from unconventional natural resources (shale gas) reservoirs has been made possible recently through horizontal well and hydraulic fracturing application. Hydraulic fracture or ‘fracking ‘is a technique that use in combination with horizontal drilling to stimulate or improve extracting natural gas from shale formation. However, this operation requires large volume of fluid to be pumped into the well at high pressure and flow rate in order to split the rock. This fluid is mainly water and mixed with sand and some chemical materials such as proppant. (Serve to prop open the fracture). Injection large volume of fluid into subsurface is not without risk. The recent report have highlighted the following issues: (earthquake induced by slip on nearby fault, emission of CO2 into atmosphere) However, this project focus on the effect of fracking operation on ground water and aquifer due to chemical additives and methane which is the main composition of shale gas. According to this report the gases and chemical additives may escape and flow into overlying ground water ‘aquifer’ in three possible pathways. Loss of wellbore integrity disposal of flow back water natural fracture network. This paper also looks at two case studies, North-East Pennsylvania, New York and Wyoming in the USA, which have the same geological shale formation. The study focuses on finding the potential impact of fracking technique that is used to extract natural shale gas on ground drinking water systems.

A quasi steady state method for solving transient Darcy flow in complex 3D fractured networks accounting for matrix to fracture flow

Modeling natural Discrete Fracture Networks (DFN) receives more and more attention in applied geosciences, from oil and gas industry, to geothermal recovery and aquifer management. The fractures may be either natural, or artificial in case of well stimulation. Accounting for the flow inside the fracture network, and accounting for the transfers between the matrix and the fractures, with the same level of accuracy is an important issue for calibrating the well architecture and for setting up optimal resources recovery strategies. Recently, we proposed an original method allowing to model transient pressure diffusion in the fracture network only [1]. The matrix was assumed to be impervious. A systematic approximation scheme was built, allowing to model the initial DFN by a set of N unknowns located at each identified intersection between fractures. The higher N, the higher the accuracy of the model. The main assumption was using a quasi steady state hypothesis, that states that the characteristic diffusion time over one single fracture is negligible compared with the characteristic time of the macroscopic problem, e.g. change of boundary conditions. In that context, the lowest order approximation N=1 has the form of solving a transient problem in a resistor/capacitor network, a so-called pipe network. Its topology is the same as the network of geometrical intersections between fractures.In this paper, we generalize this approach in order to account for fluxes from matrix to fractures. The quasi steady state hypothesis at the fracture level is still kept. Then, we show that in the case of well separated time scales between matrix and fractures, the preceding model needs only to be slightly modified in order to incorporate these fluxes. The additional knowledge of the so-called matrix to fracture transfer function allows to modify the mass matrix that becomes a time convolution operator. This is reminiscent of existing space averaged transient dual porosity models.

Numerical Simulation of Complex Fracture Network Development by Hydraulic Fracturing in Naturally Fractured Ultratight Formations

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and hot-dry-rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in biwing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial discrete fracture network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulations suggest that stress state, in situ fracture networks, and fluid type are the main parameters influencing hydraulic fracture network development. Major factors leading to more complex fracture networks are an extensive pre-existing natural fracture network, small fracture spacings, low differences between the principle stresses, well contained formations, high tensile strength, high Young’s modulus, low viscosity fracturing fluid, and large fluid volumes. The differences between 5 km deep granitic HDR and 2.5 km deep shale gas stimulations are the following: (1) the reservoir temperature in granites is higher, (2) the pressures and stresses in granites are higher, (3) surface treatment pressures in granites are higher, (4) the fluid leak-off in granites is less, and (5) the mechanical parameters tensile strength and Young’s modulus of granites are usually higher than those of shales.

A Critical View of the Current State of Reservoir Modeling of Shale Assets

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165713, ’A Critical View of Current State of Reservoir Modeling of Shale Assets,’ by Shahab D. Mohaghegh, SPE, Intelligent Solutions and West Virginia University, prepared for the 2013 SPE Eastern Regional Meeting, Pittsburgh, Pennsylvania, USA, 20-22 August. The paper has not been peer reviewed. The coupling of hydraulic fractures and natural-fracture networks and their interaction with the shale matrix remains a major challenge in reservoir simulation and modeling of shale formations. This article reviews methods used to understand the complexities associated with production from shale to shed light on the belief that there is much to be learned about this complex resource and that the best days of understanding and modeling how oil and gas are produced from shale are still ahead. Introduction Preshale Technology. The phrase “preshale” technology aims to emphasize the combination of technologies that are used to address the reservoir and production modeling of shale assets. In essence, almost all of the technologies used today for modeling and analysis of hydrocarbon production from shale were developed to address issues that originally had nothing to do with shale. As the shale boom began, these technologies were revisited and modified in order to find application in shale. Conventional Discrete Fracture Network. The most common technique for modeling a discrete natural fracture (DNF) network is to generate it stochastically. The common practice in carbonate and some clastic rocks is to use borehole-image logs to characterize the DNF at the wellbore level. These estimates of DNF characteristics are then used for the stochastic generation of the DNF throughout the reservoir. The idea of the DNF is not new. It has been around for decades. Carbonate rocks and some clastic rocks are known to have networks of natural fractures. Developing algorithms and techniques to generate DNFs stochastically and then couple them with reservoir-simulation models was common practice before the so-called “shale revolution.” A New Hypothesis on Natural Fractures in Shale What are the general shapes and structures of natural fractures in shale? Are they close to those of the stochastically generated set of natural fractures with random shapes that has been used for carbonate (and sometimes clastic) formations? Or are they more like a well-structured and well-behaved network of fractures that have a laminar, plate-like form, examples of which can be seen in outcrops (such as those shown in Fig. 1)? Shale is defined as a fine-grained sedimentary rock that forms from the compaction of silt and clay-sized mineral particles commonly called mud. This composition places shale in a category of sedimentary rocks known as mudstones. Shale is distinguished from other mudstones because it is fissile and laminated.

In Situ Gelation Study of Organically Crosslinked Polymer Gel System for Profile Modification Jobs

The crosslinked polymer gel systems are used in profile modification jobs to recover additional oil from matured oil fields where natural or induced fractures and fracture network, vertical permeability variations and channeling are the main hurdles during water flooding operations. In this work, crosslinked polymer gel solutions were prepared using partially hydrolyzed polyacrylamide polymer, hexamine and hydroquinone crosslinkers in the brine solution. These gel solutions were injected in the sand packs and kept in the oven at various ranges of temperature to meet the in situ reservoir conditions of the Indian oil fields. After complete gelation, the reduction in permeability of the sand packs was determined using brine flooding. The experimental investigation furnishes that the permeability reduction and residual resistance factor of the sand pack increases with increase in the polymer and crosslinker concentrations as well as temperature. It shows the potential of this crosslinked polymer gel system for high temperature and high- pressure wells.

Role of overpressurized fluid and fluid-driven fractures in forming fracture networks

A 2-D numerical study was carried out, using a fully coupled rock deformation and fluid flow hydraulic fracturing model on fracture network formation in a low-permeability naturally fractured rock, in which new fractures are allowed to nucleate and grow driven by overpressurized fluid. Fracture seeds either are defined as small flaws or are nucleated based on a stress and fracture energy criterion. Fracture intersection, fluid flow and frictional slip along fractures are also explicitly simulated in the model. In particular, we consider a few artificial fracture network geometries with sets of finite discrete or isolated fractures in order to study the roles of fluid viscosity, injection conditions, fracture intersections and offsetting at pre-existing or natural fractures in determining the paths which hydraulic fractures follow through the network. The newly fluid-created fracture segments, which are oriented locally normal to the least compressive stress, are the most conductive parts along the hydraulic fracture path. The resulting network will allow for long-term fluid flow to occur more easily provided that these segments retain their conductivity. However, the existence of intersections and offsets in the main fracture path act to impede fracture growth and fluid flow. A fracture nucleation event associated with higher fluid pressure may allow a fracture path to bypass these barriers, thus leading to a more planar fracture geometry. If fracture nucleation does not occur, fluid may enter other cross cutting natural fractures or enter along a barrier fracture to the tip of the barrier fracture, both processes that require a larger expenditure of energy reflected in an increasing fluid pressure. The results clearly demonstrate the importance of these stress and flow barriers in forming a preferential fracture and flow path. Fluid invasion into and fracture growth of natural fractures can still continue to occur at the high pressure region near the hydraulic fracture entry, even after a complete hydraulic fracture pathway has developed, showing strong similarity to the invasion percolation process. In contrast to fixed-aperture, connected fracture network models, the fracture growth-generated patterns also depend on the in situ stresses, which affect mechanical interaction between the main hydraulic fracture and natural fractures. The numerical results provide improved understanding of fluid-driven fracture growth into and through a network of pre-existing natural fractures.

Influences of nodular chert rhythmites on natural fracture networks in carbonates: an outcrop and two-dimensional discrete element modelling study

Abstract Natural fractures control primary fluid flow in low-matrix-permeability carbonate hydrocarbon reservoirs, making it important to understand the factors that affect natural fracture distributions and networks. Away from the influence of folds and faults, stratigraphic controls are accepted to be the major control on fracture networks. The influence of carbonate nodular chert rhythmite successions on natural fracture networks is investigated here using a Discrete Element Modelling (DEM) technique that draws on outcrop observations of naturally fractured carbonates in the Eocene Thebes Formation, exposed in the west central Sinai of Egypt, that also form reservoir rocks in the subsurface. Stratally-bound chert nodules below bedding surfaces create lateral heterogeneities that vary over short distances. The resulting distribution of physical properties (differing stiffnesses) caused by chert rhythmites is shown to generate extra complexity in natural fracture networks in addition to that caused by bed thickness and lithological physical properties. Chert rhythmite successions need to be considered as a distinct type of carbonate fractured reservoir. Stratigraphic rules for predicting the distribution, lengths and spacing of natural fractures, and quantitative fracture indices ( P 11 , P 21 , P 22 and fractal dimension) are generated from the DEM outcomes. In a less-stiff carbonate medium, the presence of chert nodules reduces fracture intensity at chert horizons, and fractures per unit area are higher in chert-free vertical corridors. In a stiff carbonate medium, chert has little influence on fracture development. In a peritidal cyclic succession with constant layer thicknesses, the presence of chert in less-stiff carbonate horizons results in a reduction in fracture intensity. When chert is introduced in a subtidal cyclic sequence with constant layer thicknesses, it has little effect on fracture distribution. The study has widespread significance for characterizing naturally fractured reservoirs containing carbonate nodular chert rhythmites.

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.

Enhancement of CBM well fracturing through stimulation of cleat permeability by ultra-fine particle injection

Coal permeability declines due to fracture closure during the dewatering stage. A new technique for stimulation of natural coal cleats through ultra-fine and ultra-light high-strength particle injection into a coal fracture system is proposed. Coupling this technique with hydraulic fracturing treatment resulted in particles entering cleats under leak-off conditions. The following optimal water-based coreflood experimental conditions were determined by applying Derjaguin-Landau-Verwey-Overbeek (DLVO) theory to the interaction between glass particles and the coal matrix: stability of a particle-based suspension (no agglomeration); repulsion between particles and the coal matrix; and, immobilisation of coal natural fines. At these conditions, these particles were placed inside cleats and were not attached to the cleat entrance, leading to less external cake formation; no formation damage due to fines migration was observed. The experimental study was carried out on some bituminous coal samples. Micro-sized glass particles were injected into a coal core at minimum effective stress until core permeability decreased to a value predetermined by a mathematical model. An increase of the effective stress to its maximum value by injection of particle-free water resulted in an approximate three-times increase in coal permeability, when compared to the original value. The proposed technique can be used for stimulation of a natural fracture network in conventional and unconventional reservoirs, as well as for the enhancement of conductivity of micro-fractures around the hydraulically induced fractures. These particles can be used as a non-damaging leak-off additive during hydraulic fracturing stimulation treatments leading to long-term fracture conductivity.