Design Of Hydraulic Fracture Treatments Research Articles

Investigation of coupled hydro-mechanical modelling of hydraulic fracture propagation and interaction with natural fractures

Various fracture patterns may develop through hydraulic fracture propagation and interaction with natural fractures which may substantially enhance connectivity and connected fracture surface area in low-permeability formations. Key factors controlling this behavior are analyzed using the continuum simulator TOUGHREACT-FLAC3D that couples the evolution of stress and deformation (FLAC3D) with reactive fluid flow (TOUGHREACT) in fractured rock. The three potential interaction scenarios are accommodated - for the hydraulic fracture to directly cross, stay arrested by, or reinitiate from the intersected natural fracture. The results show that the combined effects of approach-angle and differential stress affect the normal closure response acting on fractures. Also, larger approach-angles, greater stress differences, and higher fracture shear strength favor direct crossing, with tensile stresses more readily transferred to the far-side of the approached natural fracture. Higher injection rates accelerate buildup of wellbore and fracture pressures which lead to more rapid propagation of the hydraulic fracture. Higher injection rates also increase the wellbore pressure and pressure gradient when injection rate exceeds leak-off rate of fractures arrested by the natural fracture. The presence of only single natural fractures results in faster hydraulic fracture propagation and greater propagation length driven by higher developed wellbore pressures than where dual natural fractures are present. The presence of dual parallel natural fractures hinders the propagation of the hydraulic fracture along its preferred original path as a result of greater and redistributed leak-off and diminution of pressure through the natural fractures. Increased natural fracture permeability slows hydraulic fracture propagation by increasing fluid flow and resulting pressure dissipation by the natural fractures. Combined, these factors influence mechanisms of fracture propagation and interaction, and evolution of flow paths, which are essential in design of hydraulic fracturing treatments, hydro-mechanical characterization and prediction of the response of stimulated fracture networks.

Modeling Fracture Propagation in a Dual-Porosity System: Pseudo-3D-Carter-Dual-Porosity Model

Despite the significant advancements in geomodelling techniques over the past few decades, it is still quite challenging to obtain accurate assessments of hydraulic fracture propagation. This work investigates the effect of fluid leak-off in a dual-porosity system on the hydraulic fracture propagation geometry, which, in turn, affects hydrocarbon recovery from tight and unconventional reservoirs. Fracture propagation within tight reservoirs was analyzed using the Pseudo Three-Dimensional-Carter II model for single- (P3D-C) and dual-porosity systems (P3D-C-DP). Previous studies have accounted for leak-off in single-porosity models; however, studies within dual-porosity systems are still quite limited. We present a novel approach to coupling fluid leak-off in a dual-porosity system along with a fracture-height growth mechanism. Our findings provide important insights into the complexities within hydraulic fracturing treatment design using our new and pragmatic modeling approach. The simulation results illustrate that fluid leak-off in dual-porosity systems contributes to a confined fracture half-length (xf), that is 31% smaller using the P3D-C-DP model as opposed to the single-porosity model (P3D-C). As for the fracture height growth (hf), the P3D-C-DP model resulted in a 40% shorter fracture height compared to the single-porosity model.

Numerical Investigation of Interaction Mechanism between Hydraulic Fracture and Natural Karst Cave Based on Seepage-Stress-Damage Coupled Model

Oil/gas is mainly distributed in caves for fractured-vuggy carbonate reservoirs, it is therefore of significance to effectively connect caves for successful carbonate reservoir development. However, the mechanism and controlling factors that influence the connection between fractures and caves still remain unknown. To investigate how hydraulic fracture interacts with natural karst cave, a coupled seepage-stress-damage model for a vuggy carbonate reservoir is established based on statistical damage mechanics theory and finite element method. The accuracy of the proposed model is validated in comparison with experimental results. Some influencing factors, including fluid pressure in the cave, formation parameters, and construction parameters, are fully taken into account. The study results show that, when the fracture deflection degree is small, a hydraulic fracture can indirectly connect with the cave through high permeable damage units. The matrix heterogeneity that influences hydraulic fracture morphology almost does not affect the interactions between fracture and cave. The higher permeability can lead to insufficient net pressure in the fracture, which is detrimental to the connection between fracture and cave. The ability of the cave to repel fracture is proportional to the in-situ stress magnitude. The higher in-situ stress difference can cause hydraulic fracture extends along with its original path, hindering hydraulic fracture deflection. The compressive stress concentration effect around the cave weakens as the fluid pressure in the cave rises, causing the cave wall to gradually transform from a compressed to a tensioned state. The hydraulic fracture can propagate along its initial trajectory because of the high injection rate’s ability to lessen the impact of the cave. These findings achieve deep insights into interaction patterns between fracture and cave, as well as provide useful guidance for hydraulic fracturing treatment design in fractured-vuggy carbonate reservoirs.

Predicting fracture vertical growth containment using the width-induced net stress

The vertical growth of hydraulic fractures in layered formations is important from treatment-placement and well performance perspective. Most numerical fracture simulators generate fracture geometries by accounting for the in-situ stress and rock mechanical properties, along with key parameters related to fracturing fluids such as rheology and leakoff behavior, amongst various other critical parameters that can influence the outcome. Although the results from various simulators are generally reasonable, the fracture height estimates can vary significantly even for identical input data sets as shown in the literature. Because of the limitations of these simulators, some of the field observations, such as containment of fracture height growth across certain interfaces of contrasting material properties or weak interfacial bonding, are not replicated effectively, unless such an interface is pre-defined.In this study, the influence of fracture width on resultant stresses is incorporated in the calculation process while solving for vertical growth of hydraulic fractures. For this purpose, a modified equilibrium height growth model previously developed by the authors is used. The effects of viscous fluid movement in the fracture are also included in the calculation scheme.The outputs from the model were compared with the field-derived fracture heights that were inferred from micro seismic (MS) surveys conducted on various fracturing treatments that included both vertical and horizontal wells completed in layered formations. The analysis revealed a close agreement between the model-predicted and observed values of fracture height.While the authors acknowledge that predicting the containment of vertical growth of fracture across a plane is a challenging task given the complex nature of the problem, the paper discusses a method that offers a simpler approach to predicting the sites that may act as a constraint to the fracture growth during the stimulation treatments. This can aid in well-placement planning, perforation strategy, and hydraulic fracturing treatment design. The model can be readily deployed or incorporated in existing simulators.

Case Study: An Approach for Hydraulic Fracturing Minifrac G-Function Analysis in Relation to Facies Distribution in Multilayered Clastic Reservoirs

Summary An industry-accepted standard for minifrac analysis for evaluating and improving design of hydraulic fracturing treatments originated from the original Nolte analysis (Nolte 1979) of pressure decline, followed by the introduction of Castillo G-function in a Cartesian plot (Castillo 1987). The latter provides a graphical method for the identification of fracture closure pressures and stresses with subsequent derivation of other parameters such as fluid efficiency and fracture geometry. With the introduction of a more advanced consideration of the G-function interpretation for various reservoir conditions (Barree et al. 2007), subdividing the interpretation into calculations based on flow regimes and leakoff modes, this approach has become even more sophisticated. Particularly, interesting flow regimes and leakoff modes during fracture closure include the fracture height recession mode. This mode tends to result in rapid screenout and difficulty in placing high proppant concentrations. Regarding interpretation, the G-function derivative curve for this mode can have more than one plateau, an outcome that is possibly indicative of features that have not been widely considered to date or on which little to no data have been published. This paper presents a case study as an example of such height recession mode, along with a subsequent G-function interpretation and analysis and with consideration of the vertical facies distribution along the wellbore. Considerable attention is paid to the G-function derivative plateau analysis. Three distinctive wells, namely X-1, X-2, and X-3, are discussed. Using this technique can lead to an improved fracture calibration, optimized fracture design, and adoption of a successful completion strategy; additionally, the confirmation of 1D facies distribution can provide new insights into the fracture closure period.

A novel method to evaluate performance of chemical particulates for fluid diversion during hydraulic fracturing treatment

During hydraulic fracturing treatment, each wellbore section or interval does not receive equal treatment fluid because of non-uniformity in in-situ stresses. The application of chemical particulates for fluid diversion plays an important role in achieving a uniform distribution of treatment fluid in single or multistage hydraulic fracturing treatment. The diversion works on bridging and sealing mechanisms. The large particles are responsible to initiate a bridge and small particles help to seal the voids between large particles. This sealing mechanism is responsible for creating an impermeable diverter plug that can resist higher differential pressure across the diverter plug. The pressure withstanding capacity of diverter pack is the most important parameter to be evaluated in order to compare the performance of various diverter blends.The present novel method will help to design and evaluate the effectiveness of near-wellbore diversion stage during hydraulic fracturing treatment. The method utilizes a new empirical model to estimate pressure drop during fluid flow across binary diverter blend. This model is developed by correlating two dimensionless groups, Ergun friction factor, and Modified Ergun Reynolds number. It is able to predict the pressure drop within ±10 % of the experimentally measured values. It will also help to optimize the diverter blends having different particle sizes, and proportions. The diverter blend composed of 60 % of 7 mesh particles and 40 % of 60 mesh particles is recommended for near-wellbore diversion application because it exhibited the highest pressure drop amongst the several diverter blends. When this model is incorporated in the hydraulic fracturing treatment design simulator, it will be able to update the perforation pressure drop for designing a diverter stage. This will help to estimate the increase in treating pressure necessary for the unstimulated zone. Thus, the effectiveness of fluid diversion can be analyzed.

Hydraulic Fracture Propagation and Analysis in Heterogeneous Middle Eastern Tight Gas Reservoirs: Influence of Natural Fractures and Well Placement.

Hydraulic fracturing is a stimulation process, most frequently used in tight and unconventional reservoirs for successful and economical hydrocarbon production. This study deals with the propagation behavior of induced hydraulic fractures (HFs) in naturally fractured formations within heterogeneous Middle Eastern tight gas reservoirs. Local sensitivity analysis was conducted for a Middle East candidate reservoir by varying fracture design parameters to investigate the fracture propagation behavior. After a comprehensive evaluation, a discrete fracture network-based simulator was used to introduce multiple sets of natural fractures (NFs) into the model to further analyze their interactions. Furthermore, simplistic wellbore placement analysis was also conducted. It is observed that production in tight reservoirs is governed by the presence of NFs and their distribution. This investigation analyzes HF propagation behavior and its correlated effects in the presence of NFs. Further assessment in terms of varying fracture geometry, NF sets, wellbore placement, and their effects on the conductivity are also presented. The introduced NF sets further illustrate the significance of the NF properties in this assessment. Additionally, variations in well placement demonstrate how effective the treatment can be in the presence of complex NF sets when properly located. The study is unique as it is one of its kind based on field data within the Middle East region and offers an insight into the potential concerns that may assist future fracturing operations within the region. The outcomes from this research validate the significance of NF orientation and its subsequent effects on the final HF geometry and network. Additionally, it further highlights the criticality of well placement and design strategies during hydraulic fracturing treatment design. Results describe how a minor modification with respect to the well placement can significantly affect hydraulic fracturing operations and subsequently the productivity and feasibility.

Shear-tensile fractures in hydraulic fracturing network of layered shale

Understanding hydraulic fractures generation and geometric properties are significant for optimizing hydraulic fracturing treatment design which improves the ultimate production from shale reservoirs. The propagation of the hydraulic fractures is influenced by bedding planes. Simple opening or tensile crack model is not enough to meet the hydraulic fractures generation process, and the fault slipping model which is regarding as the cause of the natural earthquake is also not compatible with the actual physical meaning of fracking induced fractures. Hydraulic fractures consist of not only the opening but also slippage. Acoustic emission monitoring combined with the true triaxial hydraulic experiment provides direct information about the propagation and the geometric parameters of fractures. Moment tensor of acoustic emission is related to the mechanical mechanics of fractures. In this paper, the moment tensor interpretation is based on the shear-tensile crack model, then the orientation and the opening width of the hydraulic fractures are calculated. Computerized tomography scanning figures of the samples give support to the interpretation process. The distributions of hydraulic fractures orientations are different in the two samples with different normal stress applied on the bedding plane. Higher normal stress on the bedding plane led to a more complex fracture orientation. And the opening widths of the fractures in the far area from the wellbore are smaller than the fractures nearby the wellbore. These two parameters quantify the fractures geometric properties and provide information for adjusting the next step of the fracturing process. The findings of this study can help for better understanding of hydraulic fractures generation in the bedding shale. Shear-tensile crack model is supported by actual physical models has good adaptability in explaining the hydraulic fracture propagation process.

An XFEM-based numerical model to calculate conductivity of propped fracture considering proppant transport, embedment and crushing

The accurate conductivity evaluation of propped hydraulic fracture is crucial for the design and optimization of hydraulic fracturing treatments to achieve economic production of hydrocarbon. In this paper, a coupled numerical model in consideration of transport, placement, deformation, embedment and crushing of proppant is proposed to calculate the conductivity within the framework of the extended finite element method (XFEM). In the model, the fluid-solid coupling equations are simultaneously solved. The proppant transport is modeled using the upwind method. The Hertz contact model is used to obtain the width of propped fracture considering the deformation and embedment of proppant. A damage model is proposed to describe the conductivity reduction of the proppant pack due to grain failure. Size effects on the strength of proppant are considered using Weibull distribution and Griffith theory. After comparison with experimental data, the proposed model is employed to conduct sensitivity studies of several parameters on fracture conductivity. Results show that the most sensitive factor is proppant size, followed by proppant concentration, pumping rate of slurry, elastic modulus of proppant, and pumping strategy of proppant. The effects of elastic modulus of formation and Poisson's ratios of proppant and formation are negligible in comparison to other factors. It is also found that with the increase of proppant size, the fracture conductivity increases initially and decreases after reaching a peak. This paper contributes to a better understanding of the effects of related factors on fracture conductivity and provides a useful numerical tool for proppant selection in hydraulic fracturing design.

A theoretical model for hydraulic fracturing through a single radial perforation emanating from a borehole

This paper considers the problem of the plane-strain fluid-driven fracture propagation of a single radial perforation emanating from a borehole. A maximum tangential strain criterion is proposed to study crack propagation during hydraulic fracturing; this criterion considers the changes in not only the mode-I stress intensity factor caused by the pore pressure but also the mode-II stress intensity factor caused by the anisotropy of the far-field stress. The critical water pressure and the critical initiation angle at the onset of crack propagation are studied using the proposed theoretical method. The effects of the stress anisotropy coefficient, the borehole radius, the perforation length, the ratio of the water pressures inside the fracture to that of the borehole, Biot’s coefficient and Poisson’s ratio on both the critical water pressure and the critical initiation angle are discussed. The parameter analysis indicates that the perforation length, the borehole radius and the stress anisotropy coefficient significantly affect the critical water pressure and the critical initiation angle. The critical water pressure decreases as the ratio of the water pressure inside the fracture to that of the borehole and Biot’s coefficient increase, whereas the critical initiation angle is not affected by these parameters. The critical water pressure increases and the critical initiation angle decreases as the Poisson’s ratio increases. During high-pressure water injection, the fracture initiation angle decreases with increases in the water injection pressure, Biot’s coefficient and the ratio of the water pressure inside the fracture to that of the borehole; however, the angle is not affected by Poisson’s ratio. The theoretical model provides a comprehensive understanding of the characteristics of hydraulic fracturing under complex loading conditions. The results also provide a basis for quantitative investigations of the engineering design of hydraulic fracturing treatments.

Study of gas production from shale reservoirs with multi-stage hydraulic fracturing horizontal well considering multiple transport mechanisms.

Development of unconventional shale gas reservoirs (SGRs) has been boosted by the advancements in two key technologies: horizontal drilling and multi-stage hydraulic fracturing. A large number of multi-stage fractured horizontal wells (MsFHW) have been drilled to enhance reservoir production performance. Gas flow in SGRs is a multi-mechanism process, including: desorption, diffusion, and non-Darcy flow. The productivity of the SGRs with MsFHW is influenced by both reservoir conditions and hydraulic fracture properties. However, rare simulation work has been conducted for multi-stage hydraulic fractured SGRs. Most of them use well testing methods, which have too many unrealistic simplifications and assumptions. Also, no systematical work has been conducted considering all reasonable transport mechanisms. And there are very few works on sensitivity studies of uncertain parameters using real parameter ranges. Hence, a detailed and systematic study of reservoir simulation with MsFHW is still necessary. In this paper, a dual porosity model was constructed to estimate the effect of parameters on shale gas production with MsFHW. The simulation model was verified with the available field data from the Barnett Shale. The following mechanisms have been considered in this model: viscous flow, slip flow, Knudsen diffusion, and gas desorption. Langmuir isotherm was used to simulate the gas desorption process. Sensitivity analysis on SGRs’ production performance with MsFHW has been conducted. Parameters influencing shale gas production were classified into two categories: reservoir parameters including matrix permeability, matrix porosity; and hydraulic fracture parameters including hydraulic fracture spacing, and fracture half-length. Typical ranges of matrix parameters have been reviewed. Sensitivity analysis have been conducted to analyze the effect of the above factors on the production performance of SGRs. Through comparison, it can be found that hydraulic fracture parameters are more sensitive compared with reservoir parameters. And reservoirs parameters mainly affect the later production period. However, the hydraulic fracture parameters have a significant effect on gas production from the early period. The results of this study can be used to improve the efficiency of history matching process. Also, it can contribute to the design and optimization of hydraulic fracture treatment design in unconventional SGRs.

Effect of non-uniform pore pressure fields on hydraulic fracture propagation

In elastic materials, it is evident that the path of a propagating fracture is deflected from its normal course in presence of imperfections of the material or loading conditions. This paper aims at investigating hydraulic fracture deviation induced by non-uniformity of pore pressure fields with the use of a fully coupled poroelastic model based on the finite element method. The model includes a poroelastic domain in which pressurized hydraulic fractures are explicitly embedded, thus allowing to realistically model the fluid flow inside the fracture and to intrinsically consider the fracturing fluid load on the fracture walls as well as fluid leak-off into the formation. The latter process (fluid leak-off into the formation) controls both the length and the orientation of the fracture by changing the local pore pressure which in turn leads to a change in magnitude and direction of local principal stresses around the fracture tip. An innovative method, Mean Rotation Angle (MRA) is utilised for post-processing of evolving stress data at the vicinity of the fracture tip. The MRA predicts the potential growth path of pressurized fractures. In this paper pore pressure induced fracture reorientation is studied for a single fracture as well as closely spaced fractures. Results of this study indicate that presence of a pore pressure anomaly changes the growth path of a hydraulic fracture, towards or away from the anomaly. A higher than average pore pressure zone attracts the fracture while a lower pressure anomaly zone repulses the growing fracture. The fracture growth direction depends on the differential pressure and the distance between the anomaly and the fracture tip. Also in case of two simultaneously growing transverse fractures pressurized by injected fluid, it has been observed that the fluid leak-off controls the potential deviation angle of the fractures through changing the local pore pressure distribution pattern. It is shown that there are three distinct trends for the change of potential deviation angle due to fluid leak-off and that these three trends are linked to three corresponding stages of hydraulic communication between the two fractures. Furthermore, this study shows that change in matrix permeability, stress anisotropy, fracture half-length, spacing and the rate of leak-off influence the timing of each of the stages to the extent to which the corresponding stage of hydraulic communication of the two fractures are affected. This new understanding gives a better insight into the mechanism by which closely spaced hydraulic fractures interact and help optimize the design of multi-stage hydraulic fracture treatments.

Fluid Mechanics of Hydraulic Fracturing: a Review

Although hydraulic fracturing is a mature technology that has been used commercially since the late 1940s, the development of unconventional hydrocarbon fields with the combination of directional drilling and multistage hydraulic fracturing in the last two decades gave rise to a substantial progress in both operations and associated modeling. Numerical simulators, based on those models, are key to the design and evaluation of hydraulic fracturing treatments. Though hydraulic fracturing is a truly coupled phenomenon, the solid mechanics part of the problem has typically received more attention than the fluid mechanics part. Yet, that fluid mechanics field is a very rich multidisciplinary domain, presenting a number of challenges posed by the contemporary technology advancement, most of which being still unresolved. This paper aims to review the state of the art in multiphase fluid mechanics modeling of hydraulic fracturing, highlighting gaps in the body of knowledge and clarifying the questions that are still open.This review sheds light on critical phenomena peculiar to hydraulic fracturing treatments, which are grouped into three categories (according to subsequent stages of the stimulation treatment): (i) proppant transport down the wellbore, (ii) proppant placement into the fracture, (iii) flowback from fractures into a well after the end of stimulation treatment (which is particularly important for preserving the integrity and conductivity of the fracture network). To support the modeling in these areas, constitutive relationships calibrated by experiments are of paramount importance. The list of phenomena, still not fully covered by modeling, includes: slugs dispersion in the well during alternate-slug fracturing, impact of fibers and visco-elasto-plasticity of the fracturing fluid on proppant placement in fractures, effects of complex rock fabric and real fracture morphology (roughness, steps, ledges, turns, and junctions), transition from dense suspension to close packing, dynamic bridging and mobilization, particle sedimentation to form a packed bed and re-suspension, dune transport in fracture network, overflush, and flowback into the near-horizontal well from fractures, to name a few. All these effects need to be properly accounted for in the hydraulic fracturing simulators in order for the contemporary technology of multistage fracturing to be designed, executed, evaluated, and optimized properly and safely to yield optimum production, especially in unconventional reservoirs.

An XFEM-based method with reduction technique for modeling hydraulic fracture propagation in formations containing frictional natural fractures

Field-scale modeling of hydraulic fracture development in formations containing pre-existing fractures is a time-consuming task for XFEM-based numerical models. Because the costly solving of large-scale linear equation systems has to be performed for many times during two types of iteration processes of solving the fluid-solid coupling equations and determining the contact status between frictional fracture surfaces. In view of this challenge, a reduction technique is proposed in a tightly coupled model in which the equilibrium and flow continuity equations are solved simultaneously by the Newton-Raphson method. By retaining the enriched degrees of freedom (DOFs) and removing the standard DOFs which have no contribution to fracture opening, the dimensions of linear equation systems to be solved for both the fluid-solid coupling iteration and the nonlinear contact iteration can be significantly reduced. In the coupled model, the continuity of pressure and the mass balance at intersections of hydro-fractures are automatically achieved by sharing a common fluid node. The contact behavior of frictional fractures is modeled using the penalty method within the framework of plasticity theory of friction. Moreover, the extended Renshaw and Pollard criterion is utilized to predict whether a hydro-fracture will propagate across the frictional fracture. Simulation results indicate that the reduction technique can significantly accelerate the simulation without worsening the convergence or losing the computational accuracy for both types of iterations, and the acceleration effect becomes more remarkable as the problem scale increases. The great advantages of XFEM as well as the computational efficiency make the proposed method an attractive tool for engineering design of hydraulic fracturing treatments.

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.

Hydraulic fracturing design for coalbed methane in Barito Basin, Indonesia

The coalbed methane (CBM) reservoir in Barito Basin, Indonesia may be stimulated by hydraulic fracturing to efficiently recover methane gas from low permeability reservoirs. The permeability of coalbed may be quite diverse, ranging up to a few thousand mD. If the reservoir permeability is too low (less than a tenth md), hydraulic fracturing could be considered to improve gas productivity as a stimulation treatment method. In this study, hydraulic fracturing treatment design is conducted to determine total slurry volume and proper pump rate upon different fracture lengths. To set an optimal treatment schedule, fracture geometry and fracture efficiency were compared depending on the increase of fracture length and pump rate by fracturing stages. The proper pump rate was determined to be 40 bpm and resulting from high fracture efficiency. Furthermore, usage of proppant was determined using definite proper pump rate and slurry volume determined by highest pump rate in this study. All calculated fracture lengths of treatment with proppant were shorter than the fracture length of treatment without proppant. Also, fracture widths and heights were larger than treatment without proppant. However, the fracture efficiency in treatment with proppant was higher than in treatment without proppant. Therefore, proppant would contribute to improving the fracture efficiency of hydraulic fracture treatment in the CBM reservoir in Barito Basin. Consequently, the 3D-propped fracture model was designed for the CBM. Developed hydraulic fracturing model would be useful for the hydraulic treatment of CBM especially in Barito Basin for fracture design and treatment analysis prior to the actual treatment.

Optimization of Shale Gas Production Using Design of Experiment and Response Surface Methodology

High cost and uncertainty are among the most pre-eminent factors to be considered in shale gas production. Many parameters significantly affect production from such reservoirs. In this work, a new approach is proposed to obtain the optimal gas production scenario by optimizing the uncertain factors. Design of Experiment is used to analyze the order of influence of these factors, and then employ Response Surface Methodology to optimize the significant factors with economic analysis to obtain the most economical production scenario. Results show that this approach is effective and efficient for hydraulic fracturing treatment design and production scheme optimization.

The importance of the formation and fracture pressures for the selection of the depths for casing setting in Slovakia

The successful development of shale gas requires a fundamental understanding of shales and that can be challenging because these rocks vary significantly. For recoverable shale gas resources assessment a broad range of geological, geochemical, geophysical and geomechanical data is required. Information about the variable lithologies, mineralogies, and kerogen content is vital to locate favorable intervals for gas production. Knowledge of the in-situ stresses and porosity of these intervals is essential for developing hydraulic fracturing strategies to recover the gas in place. Geomechanical properties of shales are important in terms of determination of the likelihood of fractures initiating and propagating in shale materials. Geomechanical properties of rock include: Poisson's Ratio, Total Minimum Horizontal Stress, Bulk, Young and Shear Modulus. These properties play significant role in developing shale assets. Having access to geomechanical data can assist engineers and geoscientists during geomechanical modeling, hydraulic fracture treatment design and in some cases during reservoir modeling in shale gas fields. This paper is intended to give characterization of geomechanical properties of shale rock. It then refers to a case study of Baltic Basin of shale gas in Poland, for discussing it geological condition and rock properties.

Studies of Hydraulic Fracture-Propagation Behavior in Presence of Natural Fractures: Fully Coupled Fractured-Reservoir Modeling in Poroelastic Environments

In this paper, the propagation behavior of an induced hydraulic fracture in the presence of a natural fracture is described. A complex meshing and finite-element technique are employed to couple a poroelastic formation, a hydraulic fracture, and an arbitrarily oriented natural fracture. Possibilities of fracture deviation, arrest, and crossing for various angles of approach are investigated under different scenarios of in situ stress contrast, rock strength, and natural fracture geometry (length). Results of this study show that orientation of natural fracture and its length have a profound effect on induced hydraulic fracture propagation. It has been observed that, in most cases, the induced hydraulic fracture crosses short natural fractures (<10 m). As the induced hydraulic fracture approaches the natural fracture, fluid leak off increases, and consequently, the width of the induced fracture at the wellbore (fracture mouth) decreases. Once the induced hydraulic fracture breaks out of the natural fracture, the fluid leak off decreases, thus increasing the width of the induced fracture. It has been also observed that propagation of induced fracture is blocked or diverted by the presence of a long natural fracture (>10 m). With an increase in the injection rate, however, the induced fracture is likely to cross a long natural fracture (>10 m). The new understandings derived from the fully coupled poroelastic model have many beneficial applications, including design and optimization of hydraulic fracture treatments in naturally fractured reservoirs (tight gas and shale gas reservoirs) and permeability enhancement by fluid-induced shear displacement of fracture surfaces [enhanced geothermal systems (EGS)].

Optimization of Multiple Hydraulically Fractured Horizontal Wells in Unconventional Gas Reservoirs

Accurate placement of multiple horizontal wells drilled from the same well pad plays a critical role in the successful economical production from unconventional gas reservoirs. However, there are high cost and uncertainty due to many inestimable and uncertain parameters such as reservoir permeability, porosity, fracture spacing, fracture half-length, fracture conductivity, gas desorption, and well spacing. In this paper, we employ response surface methodology to optimize multiple horizontal well placement to maximize Net Present Value (NPV) with numerically modeling multistage hydraulic fractures in combination with economic analysis. This paper demonstrates the accuracy of numerical modeling of multistage hydraulic fractures for actual Barnett Shale production data by considering the gas desorption effect. Six uncertain parameters, such as permeability, porosity, fracture spacing, fracture half-length, fracture conductivity, and distance between two neighboring wells with a reasonable range based on Barnett Shale information, are used to fit a response surface of NPV as the objective function and to finally identify the optimum design under conditions of different gas prices based on NPV maximization. This integrated approach can contribute to obtaining the optimal drainage area around the wells by optimizing well placement and hydraulic fracturing treatment design and provide insight into hydraulic fracture interference between single well and neighboring wells.