Primary Hydraulic Fractures Research Articles

Modeling interactions between hydraulic fracture and pre-existing microcracks in crystalline rocks using hydro-grain-texture model

The heterogeneity of the mineral grains and pre-existing microcracks significantly impacts the cracking behavior of crystalline rocks. However, these characteristics have not been adequately addressed in the existing hydraulic fracturing studies. To bridge this gap, this study introduces a fluid-solid coupling method enhanced by a microcrack simulation component, called Hydro-Grain-Texture Model (HGTM), to investigate the influence of mineral structures and pre-existing microcracks on hydraulic fracturing processes in granite. Compared with existing methods, the HGTM incorporates a “grain growth” algorithm that can more accurately represent the characteristics of mineral grains. This study investigates the base case of intact rock, and four additional cases featuring microcracks oriented in various directions, i.e., horizontal, diagonal, vertical and complex microcracks, under both hydrostatic and non-hydrostatic in-situ stress conditions. The HGTM effectively captures a range of microscopic behaviors during the hydraulic fracturing of granite, including the formation of rock fragments, fracture branches, and dry fractures, among others. Furthermore, by comparing numerical results for breakdown pressure with analytical results, the accuracy of the HGTM in predicting breakdown pressure is substantiated. The findings indicate that mineral structures (grain boundaries) and microcracks contribute to a more intricate pattern of hydraulic fractures propagation. The pre-existing microcracks significantly influence the propagation path of primary hydraulic fractures. Under fluid-driven pressures, these pre-existing microcracks experience shear failure distinct from tensile failure observed in the surrounding rock matrix.

A New Mode of Visible Fracture System in Coal Seams and Its Implications for Coalbed Methane Seepage

As the central flow channel for fluid seepage through rock layers, the visible fracture system (VFS) significantly affects geoenergy extraction for petroleum, natural gas, geothermal resources, and greenhouse gas sequestration. In this work, we propose a new mode of VFS in coal seams, including hydraulic fractures, exogenetic fractures, interlayer fractures, gas-expanding fractures, and cleats. The development characteristics of VFSs in coal seams are analyzed, including containing their geometry, orientation, scale, distribution, and connection between each other. Furthermore, the implications of the VFS for fluid (gas and water) and solid (coal fines) flow through coal seams are discussed. The development of the VFS determines the effective flow conductivity, affecting the flow of gas, water, and coal fines. Additionally, as the reservoir pressure transfer channel, the VFS significantly influences depressurization with reservoir depletion, determining the extension of the methane desorption range. The exogenetic fractures and interlayer fractures dominate the expansion of the primary hydraulic fractures, and gas-expanding and cleats usually control the branch of hydraulic fractures. Furthermore, we find that the daily production rate distribution of most CBM wells presents a particular banded, L-shaped, or T-shaped pattern. It is thought that the VFS dominates the productivity of CBM in coal seams. The field production data also provide evidence that the occurrence of the VFS makes the CBM reservoir heterogeneous. This study presents a recommended framework involving the characteristics of the VFS and its influences on CBM production.

Semi‐Empirical Error Ellipsoid Clustering for Identifying the Second‐Order Structural Features From a Laboratory AE Source Location Cloud: Method, Validation, and Application to a Hydraulic Fracturing Test

AbstractPoint cloud of sources in the form of acoustic emission (AE) or seismicity at both field‐ and laboratory‐scales are indicative of causative structures. The error ellipsoid clustering (EC) method, whose underlying premise is reducing the amount of discarded data, is helpful for seeking the causative structure(s) from field‐scale seismic sources. However, a proper EC method does not exist for laboratory sources. Interpretation of laboratory AE sources usually involves systematic discarding of the assumed “low‐quality” data. We seek the successful transfer of the field‐scale EC method into the investigation of laboratory‐scale sources. For that, a new semi‐empirical EC method (serendipity method) is devised, and we have systematically modified the previous EC method (standard method) in (1) error ellipsoid formation, (2) iterative clustering algorithm, and (3) clustering stopping criterion. In the literature, the standard method and its limitations were validated using synthetic data. We validate the modifications by comparing its post‐clustering results with the original source locations and with the in‐situ and post‐mortem inspections of the laboratory rock fractures; and similarly for the serendipity method. We apply the serendipity method to a laboratory hydraulic fracturing test. The serendipity method implies the existence of a 3D damage zone as the second‐order feature caused by the hydraulic fracturing in addition to the primary hydraulic fracture. This complex damage zone provides a logical explanation to the previously observed reverse permeability‐distance relationship for hydraulic fracture.

Modeling for Volume-Fracturing Vertical Wells in Tight Oil Reservoir considering NMR-Based Research on Imbibition

Abstract The lateral broadband fracturing (LBF) technique for vertical well in tight oil reservoir has been proven to provide much larger stimulated reservoir volume (SRV) by widening its width. Although this new fracturing technique has been successfully applied to the development of tight oil reservoirs in Ordos Basin, China, there is still a lack of models and methods to characterize the imbibition of matrix-fracture system, which is heterogeneous permeability distribution. In this paper, a multilinear fractal model considering Nuclear Magnetic Resonance-based research on imbibition (MFMI) is established to characterize the flow characteristics of lateral broadband fracturing vertical wells (LVWs) in tight oil reservoirs by combining the dual-porosity fractal model considering imbibition and the quad-linear flow model. Due to the application of LBF, the nonuniform distribution of fracture system is characterized by fractal porosity and fractal permeability. In addition, the imbibition in SRV of tight oil reservoir is quantitatively characterized by Nuclear Magnetic Resonance (NMR) data. And the production performance of LVWs is quantified by the MFMI. By using the Laplace transformation, Bessel function, iteration, and Stehfest numerical inversion algorithms, the approximate analytic solutions of our established model, including primary hydraulic fractures, SRV, and unstimulated reservoir volume (USRV), are derived. The solutions of pressure and production are used to compare and analyze in order to discuss the influence of parameters related to lateral broadband fracturing (such as fractal parameters, reservoir parameters, and width of SRV) on flow behavior of LVWs in a tight oil reservoir. The modeling results show that the fractal parameters of fracture system have great effect on the fluid flow in LVWs, and LBF contributes to imbibition production.

Optimization of Re-Fracturing Method and Fracture Parameters for Horizontal Well in Mahu Conglomerate Oil Reservoir

Mahu Oilfield, the largest conglomerate oilfield around the world, is facing the severe problems of rapid production decline and low recovery ratio. Re-fracturing of horizontal wells is an effective method to improve this situation. The study of horizontal well re-fracturing has increased popularity recently, but the optimization of re-fracturing parameters has not been thoroughly investigated, especially for the conglomerate reservoir. The optimal selection of re-fracturing parameters such as length and conductivity is unclear, which significantly influences re-fracturing treatment and economic cost. In order to fill this gap, a series of numerical models are established based on filed data to predict horizontal well production after re-fracturing. The parameters of primary hydraulic fractures are calculated by net pressure matching and are imported into the numerical models. A production matching is conducted to confirm the reliability of numerical models. The cumulative productions of different re-fracturing stimulation methods, including lengthening old fractures and perforating new fractures, are simulated, and the corresponding re-fracturing parameters are optimized. The results have shown that the length of primary fractures is smaller than designed, which means lengthening old fractures is necessary. Lengthening old fractures and perforating new fractures between primary clusters can increase production. On the condition of the same fracture length, the increasing ranges of production corresponding to perforating new fractures are larger than that of lengthening old fractures. Lengthening old fractures is particularly suitable to the situation that the length of primary fractures is smaller than designed, and the optimal value in lengthening half-length of old fractures is 160 m. By contrast, perforating new fractures between old clusters applies to the case that the cluster spacing of primary hydraulic fracturing is larger than 35 m, and the optimal fracture half-length is 140 m.

Numerical Simulation and Modeling on CO2 Sequestration Coupled with Enhanced Gas Recovery in Shale Gas Reservoirs

CO2 geological sequestration in shale is a promising method to mitigate global warming caused by greenhouse gas emissions as well as to enhance the gas recovery to some degree, which effectively addresses the problems related to energy demand and climate change. With the data from the New Albany Shale in the Illinois Basin in the United States, the CMG-GEM simulator is applied to establish a numerical model to evaluate the feasibility of CO2 sequestration in shale gas reservoirs with potential enhanced gas recovery (EGR). To represent the matrix, natural fractures, and hydraulic fractures in shale gas reservoirs, a multicontinua porous medium model will be developed. Darcy’s and Forchheimer’s models and desorption-adsorption models with a mixing rule will be incorporated into the multicontinua numerical model to depict the three-stage flow mechanism, including convective gas flow mainly in fractures, dispersive gas transport in macropores, and CH4-CO2 competitive sorption phenomenon in micropores. With the established shale reservoir model, different CO2 injection schemes (continuous injection vs. pulse injection) for CO2 sequestration in shale gas reservoirs are investigated. Meanwhile, a sensitivity analysis of the reservoir permeability between the hydraulic fractures of production and injection wells is conducted to quantify its influence on reservoir performance. The permeability multipliers are 10, 100, and 1,000 for the sensitivity study. The results indicate that CO2 can be effectively sequestered in shale reservoirs. But the EGR of both injection schemes does not perform well as expected. In the field application, it is necessary to take the efficiency of supplemental energy utilization, the CO2 sequestration ratio, and the effect of injected CO2 on the purity of produced methane into consideration to design an optimal execution plan. The case with a permeability multiplier of 1,000 meets the demand for both CO2 sequestration and EGR, which indicates that a moderate secondary stimulation zone needs to be formed between the primary hydraulic fractures of injection and production wells to facilitate the efficient energy transfer between interwell as well as to prevent CO2 from channeling. To meet the demand for CO2 sequestration in shale gas reservoirs with EGR, advanced and effective fracking is essential.

Performance evaluation of SDAGM‐coated microproppants in hydraulic fracturing using the lattice Boltzmann method

AbstractHydraulic fracturing has become a standard stimulation technology to enhance hydrocarbon production in unconventional reservoirs in recent decades. During organic‐rich tight carbonate reservoir stimulation, extensive microfractures will be created and pre‐existing microfractures will be opened in the far‐field during hydraulic fracturing, but they tend to close after the release of hydraulic pressure due to the larger sizes of the conventional proppants not fitting into the microfractures. The well productivity will be further enhanced if these microfractures can be held open during production, like the primary hydraulic fractures supported by proppants. Based on this idea, industry has introduced microproppants into the pad or pre‐pad fluid so that they can be placed into opened microfractures during hydraulic fracturing. In this work, we propose further enhancing the stimulation efficiency by introducing solid delayed acid generating materials (SDAGM)‐coated microproppants into the stimulation for the dual function of keeping microfractures open, and, through subsequent reactions of the coating materials with the carbonate formation, creating extra void space inside the microfractures. To prove this concept and help select the appropriate microproppant coating plan, lattice Boltzmann simulation is performed to measure the hydraulic conductivity of the stimulated microfractures under different scenarios that represent corresponding stimulation treatment schemes. The simulations showed that fracture conductivity of the microfractures can be significantly improved by placing SDAGM‐coated microproppant into them. Using the mixed uncoated and SDAGM‐coated microproppants (Scheme II) may have better fracture conductivity improvement than using the coated microproppant alone (Scheme I).

Analysis of Production Data from Communicating Multifractured Horizontal Wells Using the Dynamic Drainage Area Concept

Summary Reduction of fracture/well spacing and increases in hydraulic fracture stimulation treatment size are popular strategies for improving hydrocarbon recovery from multifractured horizontal wells (MFHWs). However, these strategies can also increase the chance of fracture interference, which can not only negatively impact the overall production but also introduce complexities for production data analysis. A semianalytical model is therefore developed to analyze production data from two communicating MFHWs and applied to a field case. The new semianalytical model uses the dynamic drainage area (DDA) concept and assumes three porosity regions. The three-region model is comprised of a primary hydraulic fracture (PHF), an enhanced fractured region (EFR) adjacent to the PHF, and a nonstimulated region (NSR). Assuming a well pair primarily communicates through PHFs, the equations for two communicating wells are coupled and solved simultaneously to model the fluid transfer between the wells. This method is used within a history-matching framework to estimate the communication between the wells by matching the production data. The semianalytical model is first verified against a more rigorous, fully numerical simulation model for a range of fracture/reservoir properties. These comparisons demonstrate that there is excellent agreement between the fully numerical simulation model results and the new semianalytical model. The semianalytical model is then employed to history-match production data from six MFHWs (drilled from two adjacent well pads) exhibiting different degrees of communication. For the purpose of history matching the data, only strong communication between pairs of wells (intrapair communication) is considered in the three-region model, and the results show good agreement with the field data. A flexible, yet simple, semianalytical model is developed for the first time that can accurately model the communication between multiple well pairs. This approach can be used by reservoir engineers to analyze the production data from communicating MFHWs.

A multi-mechanism multi-pore coupled salt flowback model and field application for hydraulically fractured shale wells

Flowback records matching has been increasingly used for reservoir and fracture parameters inversion for hydraulically fractured unconventional oil and gas wells. However, previous publications mainly focus on flowback water transients but flowback salinity transient analyses are few. In this study, a salt flowback model characterizing salt transport in a hydraulically fractured shale reservoir has been proposed. The physical model treats the hydraulically fractured shale reservoir as a multi-pore medium, which includes wellbore, primary hydraulic fracture, secondary hydraulic fracture, clay-dominant pore and other matrix pore. The salt transport accounts for three mechanisms, i.e. advection, diffusion and clay-dominant adsorption. We apply semi-implicit algorithm for mathematical model solution and numerical simulator development. The simulation results indicate that advection predominates in the salt flowback. Salts and water flow into shale matrix from secondary hydraulic fractures at the beginning of flowback and then the flowing direction reverses. The cumulative flowback salinity of well exhibits an increase with the flowback time. However, the instant flowback salinity of well first increases and then decreases along with the increase in shut-in time. Finally, 2 wells from field in X shale formation, have been applied to match the flowback salinity and water records. The parameter combinations of the conductivity and half-length of hydraulic primary fractures, as well as the number of secondary fractures are recovered based on the good match of flowback salinity records and water load recovery. This study provides another way for post-stimulation evaluation and supplements existing flowback model.

A rock self-supporting high conductivity acid fracturing technique in a deep carbonate reservoir

As carbonate reservoirs in deeper strata continue to develop, reservoir closure stress has significantly increased, where conventional acid fracturing technology cannot maintain acid-etched fracture conductivity and single well production rates are decreasing more quickly. This study proposes a rock self-supporting, highly conductive acid fracturing technique, where the shielding materials cover a portion of the primary hydraulic fracture surface to block the acid rock reaction. After acid injection, the unetched part will be a bearing surface, which serves as a large area and self-supporting high strength rock. This technique fundamentally changes the existing point support pattern of acid-etched fractures. Experimental results demonstrate that when the closed stress is <50 MPa, the self-supporting conductivity is 42% higher than the conventionally acid etched fractures. At 90 MPa closed stress, it can still maintain high support strength, which is more than eight times that of a conventional acid etched fracture. The equilibrium relationship between the fracture conductivity and rock support strength was determined using finite element stress simulation and fluid mechanics simulation. The results demonstrate that using a small cylindrical area, dislocation support, and multi-point support is conducive to the dispersion of high closure stress; moreover, the concentrated stress intensity of supporting rock can be reduced by 3–12 MPa. With decrease in supporting area, the stress intensity of the supporting rock is higher. Considering the compressive strength of the rock, the supporting area is >25%. When the rock is in the form of a dislocation support, the fluid disperses in the larger void channels, thus effectively maintaining fracture conductivity. The self-supporting acid fracturing technique is useful for increasing the utility of acid fracturing stimulation in deep and ultra-deep wells.

Rigorous Estimation of the Initial Conditions of Flowback Using a Coupled Hydraulic-Fracture/Dynamic-Drainage-Area Leakoff Model Constrained by Laboratory Geomechanical Data

Summary The application of rate-transient-analysis (RTA) concepts to flowback data gathered from multifractured horizontal wells (MFHWs) completed in tight/shale reservoirs has recently been proposed as an independent method for quantitatively evaluating hydraulic-fracture volume/conductivity. However, the initial fluid pressures and saturation in the fracture network and adjacent reservoir matrix are generally unknown at the start of flowback, creating significant uncertainty in the quantitative analysis of flowback data. In this study, we present a semianalytical flow model, coupled with a hydraulic-fracture (fracture) model and constrained with laboratory-based geomechanical data, for evaluating the initial conditions of flowback. In previous work, a semianalytical model based on the dynamic-drainage-area (DDA) concept was used to simulate water-based fluid leakoff from an MFHW into a tight oil reservoir (Montney Formation, western Canada), with minimal mobile water, during and after fracturing operations. The model assumed that each fracturing stage can be represented by a primary hydraulic fracture (PHF) containing the majority of the proppant, and an adjacent nonstimulated reservoir (NSR) or enhanced fracture region (EFR), which is an area of elevated permeability in the reservoir caused by the stimulation treatment. Each region was represented by a single-porosity system. The DDA propagation speed within the PHF during the stimulation treatment was constrained through using a simple analytical fracture model. Although this approach was considered novel, several improvements and additional laboratory constraints were considered necessary to yield more accurate predictions of initial flowback conditions. In the current work, the modeling approach described previously was improved by representing the EFR with a dual-porosity system; fully coupling the fracture model (used for PHF creation and propagation) with the DDA model for fluid-leakoff simulation into the EFR and adding a proppant-transport model; and modeling the shut-in period. Finally, to ensure that model geomechanics were properly constrained, a comprehensive suite of previously gathered laboratory data was used. Laboratory-derived propped (PHF) and unpropped (EFR) fracture-permeability/conductivity data as a function of pore pressure, as well as fracture-compressibility data, were used as constraints for the model. It should be noted that our model assumes that fracture closure has no effect on the pressure/saturation of the PHF/EFR/matrix. The improved model was reapplied to the tight oil field case and yielded more realistic estimates of initial flowback conditions, enabling more confident history matching of flowback data. The results of this study will be important to those petroleum engineers interested in quantitative analysis of flowback data to accurately obtain fracture properties by ensuring proper model creation.

Extracting Hydrocarbon From Shale: An Investigation of the Factors That Influence the Decline and the Tail of the Production Curve

AbstractUnderstanding physical processes that control the long‐term production of hydrocarbon from shale formations is important for both predicting the yield and increasing it. In this work, we explore the processes that could control the tail of the production curve by using a discrete fracture network method to calculate the total travel time from the rock matrix to small‐scale fractures to the primary hydraulic fracture network. The factors investigated include matrix diffusion, extent of the small‐scale fracture zone (or tributary fracture zone/TFZ) consisting of natural, reactivated and induced fractures, and the percentage of free hydrocarbon in the primary fracture network. Individual and combined parameter spaces are explored for each of these to understand the limits of these parameters as well as any systematic correlations between pairs of parameters. Although recent studies have shown that the matrix diffusion in virgin shale influences the production tail only after nearly 20 years, we demonstrate that matrix diffusion in the region of the TFZ significantly impacts production within the first year itself. Additionally, we found that the depth of TFZ fracturing region had no effect on the shape of the production curves although the total mass of the hydrocarbon produced increases with the depth. We also show that one can fit the production data using a site‐specific set of parameters representing the diffusion in the TFZ, depth of the TFZ, and the free hydrocarbon in the large‐scale fractures.

Well-Placement Timing, Conductivity Loss Affect Production in Multiple-Fracture Wells

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 180448, “Effects of Well-Placement Timing and Conductivity Loss on Hydrocarbon Production in Multiple-Hydraulic-Fracture Horizontal Wells in a Liquids-Rich Shale Play,” by Shameem Siddiqui, SPE, Doug Walser, SPE, and Ron Dusterhoft, SPE, Halliburton, prepared for the 2016 SPE Western Regional Meeting, Anchorage, 23–26 May. The paper has not been peer reviewed. Horizontal wells in liquids-rich shale plays are now being drilled such that lateral and vertical distances between adjacent wells are significantly reduced. In multistacked reservoirs, fracture height and orientation from geomechanical effects coupled with natural fractures create additional complications; therefore, predicting well performance using numerical simulation becomes challenging. This paper describes numerical-simulation results from a three-well pad in a stacked liquids-rich reservoir (containing gas condensates) to understand the interaction between wells and production behavior. Numerical Simulation The reservoir simulator used for this study was designed to handle unstructured-grid-based simulation cases. Most of the numerical reservoir simulators that are used for modeling horizontal wells with multiple hydraulic fractures are based on structured grid cells in which the hydraulic fractures are modeled as symmetric biwing fractures perpendicular to the wellbore. In most cases, they use local grid refinement (LGR) to incorporate the hydraulic fractures into the model, which generally works well if a single well is involved and the grids are not tied to the Earth models. However, if the wells and the hydraulic fractures are not orthogonal to the Earth-model grids or if the reservoir contains nonorthogonal secondary fractures (natural or induced), modeling them with LGR becomes a challenge. When multiple wells that are not parallel are drilled from a single pad, properly representing the wells with hydraulic fractures in a structured-grid-based reservoir-simulation model becomes even more challenging. By contrast, the unstructured-grid-based reservoir models are not restricted by any of these limitations—they can have any geometry, size, or orientation for the wells and can include primary hydraulic fractures, secondary fractures, and open natural fractures. Instead of using grid cells that are parallel in shape, the unstructured grid cells can have any arbitrary shape. Incorporating realistic induced hydraulic fractures in a reservoir model is easier if unstructured grids are used. Reservoir-Simulation Model The reservoir model consisted of five horizontal layers with varying properties in each layer. The horizontal sections of Wells 1 and 3 go through the middle of Layer 2, and that of Well 2 goes through the middle of Layer 4. Each well is completed exactly the same way.

Simulation of coupled hydro-mechanical-chemical phenomena in hydraulically fractured gas shale during fracturing-fluid flowback

Fracturing-fluid flowback in hydraulically fractured gas shale is a complicated transport behavior involving hydrodynamic (H), mechanical (M) and chemical (C) processes. Although, many flowback models have been published, none of the models flly coupled the transient fluid flow modeling with chemical-potential equilibrium and fracture closure phenomena.In this paper, a coupled hydro-mechanical-chemical (HMC) model based on hydrodynamics, linear-elastic fracture mechanics, and chemical-potential equations is presented to simulate the fracturing-fluid flowback behavior in hydraulically fractured gas shale. The HMC model takes into account a gas-liquid two-phase flow and a triple-porosity medium, which includes primary hydraulic fractures, secondary induced fractures and shale matrix. The flowback simulation with the HMC model accounts for all the important processes in fractured shale system, including (1)water transport driven by hydraulic, capillary and osmotic convections, (2)gas transport induced by both hydraulic pressure driven convection and adsorption, and (3)fracture closure considered as an elastic deformation. The fluid transport, coupled with rock deformation, are described by a set of partial differential equations. The semi-implicit finite-difference method is used to solve these equations.The evolution of pressure, saturation, salinity and aperture profiles of hydraulic fractures, induced fractures and matrix is calculated, revealing the multi-field coupled flowback behavior in fractured gas shale. The sensitivity analysis is also performed to investigate the physiochemical properties of shale on the water load recovery and gas production rate during the fracturing-fluid flowback. The results indicate that the capillarity has the most effect followed by chemical osmosis and induced fracture closure. The sub-irreducible water saturation has the weakest effect. Moreover, the matrix-related physiochemical parameters cause opposite influences on water load recovery and gas production rate. While, the influence of induced fracture-related parameters on both water load recovery and gas production rate is consistent. Results from this study are expected to explain which is the predominant mechanism for fracturing-fluid retention and the inherent relationship between fracturing-fluid flowback and gas production for different initial physiochemical properties of shale.

Analytical modeling of linear flow with variable permeability distribution in tight and shale reservoirs

Horizontal wells with multiple fractures, producing from tight and shale reservoirs, may exhibit linear flow for long periods of time. Majority of the available analytical solutions that model this flow behaviour assume uniform permeability, which most likely is an over-simplification of the unconventional reservoirs. Non-homogeneous shear or tensile failure away from the main induced (primary) hydraulic fractures can lead to a non-uniform permeability distribution that depends on the distance away from the hydraulic fractures.In this work, linear flow in a reservoir with non-uniform permeability adjacent to the primary hydraulic fracture is modeled rigorously using perturbation theory. The diffusivity equation is solved for the pressure response of a fractured well located in a reservoir of infinite extent with permeability as an arbitrary function of position. For constant terminal rate (CTR) or constant terminal pressure (CTP) conditions, the linear flow parameter (LFP=xfk) is calculated from the slope of the square-root-of-time plot (plot of rate-normalized pressure vs. square root of time).It is demonstrated herein that the calculated LFP corresponds to a weighted average of permeabilities (and fracture half-lengths); different parts of the reservoir contribute differently to the LFP at different production times. The LFP is influenced most strongly by permeabilities at a distance y=0.056(kt)ϕμct. The derived weighting functions during CTR and CTP production can be applied in inverse mode for determining LFP distribution near the hydraulic fractures. This is particularly useful in evaluating the effectiveness of hydraulic fracturing operations and assessing the performance of different fracturing techniques in unconventional reservoirs. In addition, this work gives significant insight into the concept of distance of investigation (DOI) in tight and shale reservoirs, and the differences when producing under CTR and CTP conditions.

A composite dual-porosity fractal model for channel-fractured horizontal wells

ABSTRACTThe channel fracturing technique has been proven to provide much higher conductive fracture networks by placing discontinuously proppant inside fracture packs. Despite the great success of this new fracturing technique, there is still a lack of models and methods to characterize non-uniform placement of fracture proppant and heterogeneous permeability distribution within stimulated-reservoir-volume (SRV). In this article, a dual-porosity model is coupled with the tri-linear flow model to quantify the production performance of channel fractured horizontal wells. As a consequence of channel fracturing, the non-uniform distribution of fracture networks, and the heterogeneities of both matrix/fracture porosity and permeability are characterized using fractal theory. By implementing the Bessel Function and Laplace transform techniques, analytical solutions are derived by integrating fluid flow across primary hydraulic fractures, SRV and unstimulated reservoir matrices. Through quantitative comparisons of well bottom-hole pressure history, a synthetic fine-grid numerical simulation example is implemented to verify the accuracy of analytical solutions. Sensitivity analysis of fractal dimension, fractal connectivity-index and primary fracture conductivity is carried out to quantify the temporal and spatial consequences of channel fracturing on both reservoir/facture heterogeneity and well productivity throughout well life.

Analysis of the Influencing Factors on the Well Performance in Shale Gas Reservoir

Due to the ultralow permeability of shale gas reservoirs, stimulating the reservoir formation by using hydraulic fracturing technique and horizontal well is required to create the pathway of gas flow so that the shale gas can be recovered in an economically viable manner. The hydraulic fractured formations can be divided into two regions, stimulated reservoir volume (SRV) region and non-SRV region, and the produced shale gas may exist as free gas or adsorbed gas under the initial formation condition. Investigating the recovery factor of different types of shale gas in different region may assist us to make more reasonable development strategies. In this paper, we build a numerical simulation model, which has the ability to take the unique shale gas flow mechanisms into account, to quantitatively describe the gas production characteristics in each region based on the field data collected from a shale gas reservoir in Sichuan Basin in China. The contribution of the free gas and adsorbed gas to the total production is analyzed dynamically through the entire life of the shale gas production by adopting a component subdivision method. The effects of the key reservoir properties, such as shale matrix, secondary natural fracture network, and primary hydraulic fractures, on the recovery factor are also investigated.

Simulation of the Impact of Fracturing-Fluid-Induced Formation Damage in Shale Gas Reservoirs

Summary The unconventional gas resources from tight and shale gas reservoirs have received great attention in the past decade and have become the focus of the petroleum industry. Shale gas reservoirs have specific characteristics, such as tight reservoir rock with nanodarcy permeability. Multistage hydraulic fracturing is required for such low-permeability reservoirs to create very complex fracture networks and therefore to connect effectively a huge reservoir volume to the wellbore. During hydraulic fracturing, an enormous amount of water is injected into the formation, where only 25–60% is reproduced during flowback and a long production period. A major concern with hydraulic fracturing is the water-blocking effect in tight formations caused by the high capillary pressure and the presence of water-sensitive clays. High water saturation in the invaded zone near the fracture face may reduce gas relative permeability greatly and may impede gas production. In this paper, we consider the numerical techniques to simulate during hydraulic fracturing the water invasion or formation damage and its impact on the gas production in shale gas reservoirs. Two-phase-flow simulations are considered in a large stimulated reservoir volume (SRV) containing extremely low-permeability tight matrix and multiscale fracture networks including primary hydraulic fractures, induced secondary fractures, and natural fractures. To simulate the water-blocking phenomenon, it is usually required to explicitly discretize the fracture network and use very fine meshes around the fractures. On the one hand, the commonly used single-porosity model is not suitable for this kind of problem, because a large number of gridblocks is required to simulate the fracture network and fracture–matrix interaction. On the other hand, a dual-porosity (DP) model may also be not applicable, because of the long transient duration with large block sizes of ultralow-permeability matrix. In this paper, we study the applicability of the MINC (multiple interacting continuum) method, and use a hybrid approach between matrix and fractures to correctly simulate the fracturing-fluid invasion and its backflow during hydraulic fracturing. This approach allows us to quantify the fracturing water invasion and its formation-damage effect in the whole SRV.

Semi-analytical model for matching flowback and early-time production of multi-fractured horizontal tight oil wells

Analysis of multi-fractured horizontal well (MFHW) production data completed in low-permeability (tight) oil reservoirs has traditionally focused on long-term (online) production after the initial flowback period. Recent studies, however, have demonstrated that important information about hydraulic fractures can be ascertained from flowback data and simulation studies are now being designed to model flowback along with the online production.In this work, a new semi-analytical model is developed specifically for modeling water and hydrocarbon production during flowback and early-time production for tight oil wells. Two flow regions are assumed: a primary hydraulic fracture (PHF) and an enhanced fracture region (EFR) adjacent to the hydraulic fracture, where reservoir permeability has been enhanced due to stimulation. Alternatively, a non-stimulated matrix region (NSR), where reservoir permeability is not enhanced due to stimulation, may be placed adjacent to the PHF. A coupled PHF-EFR model is created by assigning the average pressure in the PHF as the inner boundary condition of the EFR, and wellbore flowing pressure as the inner boundary-condition for PHF. If the initial fracture pressure is greater than reservoir pressure, the coupled model forecasts initial production to be single-phase flow of fracturing fluid, followed by two-phase flow of fracturing fluid and formation oil from the EFR to the PHF after breakthrough to the fracture. Transient flow of fluids through the PHF and EFR is modeled with the dynamic drainage area approach. Equations of coupled flow/material balance are solved iteratively at each timestep. Stress-dependent properties of fractures and matrix are handled in the solution.The robustness of this innovative approach is tested through comparison with more rigorous numerical simulation, and its practicality demonstrated with a field example. The new technique should serve as a useful tool for petroleum engineers responsible for forecasting tight oil wells exhibiting these complexities.

When Is Induced Fracture Complexity Necessary for Unconventionals Stimulation?

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 168976, “Induced Fracture Complexity—When Is It Really Required in Unconventional Reservoir Stimulation?” by Leopoldo Sierra, SPE, and Mike Mayerhofer, SPE, Pinnacle—A Halliburton Service, prepared for the 2014 SPE Unconventional Resources Conference—USA, The Woodlands, Texas, USA, 1–3 April. The paper has not been peer reviewed. Induced-fracture-complexity maximization in addition to the primary hydraulic fractures has been accepted and fully implemented to improve recovery efficiency or productivity in unconventional reservoirs. This paper aims to develop criteria for identifying situations in which induced fracture complexity and sustained conductivity are or are not required. The results show that the fracture complexity and sustained conductivity are generally important for reservoir permeabilities lower than 100 nd for gas production and 500 nd for liquid production. Introduction The industry-implemented completion strategy for unconventional gas- or liquid- producing reservoirs considers increased reservoir contact to maximize productivity and hydrocarbon recovery through the following methods: Drilling long horizontal wellbores Optimizing the horizontal-wellbore placement to maximize the vertical coverage of the prospective formation Placing multiple transverse fractures by perforating the most-brittle and -prospective areas to generate complex fractures Alternating fractures in parent horizontal wellbores to induce stress interference that could result in more-complex fractures Engineering stimulation fluids to help induce complex fractures Although the existing completion strategy for each shale play has been optimized or is in the optimization process, a correlation between production and the perceived fracture surface area was not observed in some cases. Assuming the stimulation process is adequate and properly implemented in the field, the observed production behavior might be related to the combination of unknown reservoir permeability and induced fracture complexity. This paper investigates the benefits of induced fracture complexity in the stimulation of unconventional gas-or liquid-producing reservoirs for a wide range of reservoir permeabilities (10 nd to 0.001 md) and with a variable stimulation efficiency. Ultimately, this paper aims to answer the question of when induced fracture complexity is really necessary.