Geomechanics plays a significant role in hydraulic fracture initiation and propagation and in the interaction between hydraulic fractures and natural fractures, especially in unconventional reservoirs. This paper provides a detailed description of a geomechanical characterization and modeling study for evaluating the impact of geomechanics on completions and hydraulic fracturing stimulations optimization in the Montney resource play, Canada. Following an integrated workflow, 1D mechanical earth models (MEM) for ten wells were constructed in the study area. These 1D MEMs include elastic and strength properties, pore pressure, direction and magnitude of in-situ stresses. Extensive rock mechanics core testing data were used to calibrate the elastic and strength properties. Pore pressure and fracture closure pressure data from diagnostic fracture injection tests were also available to calibrate pore pressure and minimum in-situ stress. Maximum horizontal stress was constrained by modeling wellbore stability and matching it with caliper logs and wellbore stability features on wellbore image. A 3D mechanical earth model was subsequently constructed using a 3D geological model, the 1D MEMs, and seismic inversion data. Elastic properties from seismic inversion were used to populate mechanical properties in the 3D model. In-situ stresses were numerically simulated to account for the impact of faults and structural and mechanical property variation on in-situ stress distribution. The geomechanical analysis shows that there is a decreasing trend in Young’s modulus from upper Montney to lower Montney while Poisson’s ratio is relatively constant in the Montney. The pore pressure in some parts of the field is high and varies across the field. Stress regime is predominantly strike-slip with relatively large stress anisotropy, and this has implications on the hydraulic fracture network that would be simulated, shearing of natural fractures and the stimulated reservoir volume. Rock elastic and strength properties, pore pressure, and in-situ stresses were found to be heterogenous across the whole field. The relatively large variation in pore pressure in the study area and the structural complexities have large impact on the distribution of stresses. Faults alter the stress distribution locally and could affect hydraulic fracture propagation. Hydraulic fracture simulations were subsequently performed, and the geometry of the simulated hydraulic fractures and the stimulated reservoir volume were validated with microseismic events. The effects of geomechanics on fracture geometry and ultimately reservoir production were evaluated. Because of the significant impact of geomechanics on hydraulic fracturing, it is critical to characterize and model geomechanics accurately. This paper provides a comprehensive approach and application to a field in the Montney, showcasing the integrated method of geomechanical characterization and hydraulic fracture simulation and production modeling using various data. The analysis provides an interrelationship among geomechanical parameters, microseismicity and stimulated reservoir volume.

Reducing fracture/well spacing and increasing hydraulic fracture stimulation treatment size are popular strategies for increasing hydrocarbon recovery from multi-fractured horizontal wells (MFHWs). However, these strategies can also increase the chance of fracture interference, which not only can negatively impact the overall production, but also introduce complexities for production data analysis. To analyze the production data from two communicating wells, a semi-analytical model is developed and applied to a field case. The new semi-analytical model uses the dynamic drainage area (DDA) concept and assumes that the reservoir consists of two regions: a primary hydraulic fracture (PHF) and an adjacent enhanced fracture region (EFR) or non-stimulated region (NSR) in the reservoir. 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 degree of communication between the wells by matching the production data. The model is first verified against more rigorous numerical simulation for a range of fracture/reservoir properties. These comparisons demonstrate that there is excellent agreement between the reservoir simulation results and the new semi-analytical model. The semi-analytical model is then employed to history match production data from six MFHWs (drilled from two adjacent well pads) exhibiting different degrees of communication. First, only strong communication between pairs of wells (intra-pair communication) is considered. Then sink/source terms are added to account for intermediate degrees of communication between well pairs (inter-pair communication). Addition of the source/sink terms improves the history-matching quality of the three well pairs, while total material balance of the entire section is honored. A flexible, yet simple, semi-analytical 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.

Effective stimulation of infill (child) wells can be challenging: pressure sinks resulting from production of existing (parent) wells can impair child wells’ completions leading to a loss of production potential. Special completion techniques are required to better stimulate the new rock volume and divert the fracture energy away from the depleted zones. This study investigates pre-loading and re-fracking of parent wells as potential Pressure Sink Mitigation (PSM) techniques to minimize fracture asymmetry in child wells. The impact of these techniques on possible production uplift for both parent and child wells are also investigated. A black-oil reservoir flow simulation model was created and history matched to production from three existing parent wells in a Montney field. Three new child wells have been drilled in close proximity (100m-200m) to the parent wells and were subjected to fracture generation and subsequent production. The fracture generation of the child wells was directly modelled in the reservoir simulator with hydraulic fracture conductivity as an exponential function of pressure. The conductivity-pressure relationship of the newly created hydraulic fractures were validated quantitatively to field history data and qualitatively to a third-party fracture creation software. To limit the influence of the depleted zone, water was injected into the parent wells before the child well fractures are created. Since the child well fracture behavior is directly related to the pressure, a theoretical "reservoir pressure vs injected pre-load volume" relationship was generated. From the relationship, a series of simulation sensitivities were performed where the child well fracture creation and successive production were subjected to different pressure (pre-load) scenarios. The production uplift of each scenario over the non-preload base case was calculated to determine the efficacy of the technique and optimum injection volumes. Additionally, the time for the parent wells to return to their pre-child well production levels was quantified. A practical and robust simulation workflow to evaluate a pressure sink mitigation technique was successfully developed using an actual field case in the Montney formation. As infill drilling and high well density become standard operational practice, understanding how to limit the influence of existing depleted wells is essential for optimizing recovery from hydraulically fractured formations.

The purpose of this paper is to quantify the importance of lateral heterogeneity of permeability and porosity when modeling horizontal, multi-fractured tight unconventional wells exhibiting layer-wise fluid heterogeneity. Fluid and petrophysical properties are taken from the Eagle Ford basin. A numerical simulation model of a horizontal well drainage volume with multiple planar fractures is created for two layers having distinct fluids (e.g. solution GORs). The model is populated with laterally-heterogeneous, correlated porosities and permeabilities (k=aφ b ) ranging from 4 to 14 %, and 59 to 2600 nd, respectively. The layer petrophysical properties can map differently for each layer, but the arithmetic average properties are equal for each layer. For all cases studied we assume the initial solution GOR to be areally homogeneous in a given layer; the solution GORs considered range from 1000 to 8000 scf/STB. The petrophysical heterogeneous cases are compared with homogeneous cases (no lateral property variation), both models with the same average petrophysical properties. Results show that for a heterogeneous-petrophysical case with varying lateral contrast between the petrophysical properties in the two layers, individual fractures produce with distinct GORs, even showing a variation of producing GOR (R p ) from different locations within a single hydraulic fracture. However, the total, well-producing GOR behavior is very similar for the heterogeneous- and homogeneous-petrophysical cases, regardless of the fluid contrast in the two layers, when the maximum-to-minimum permeability ratio k max /k min <10. These observations apply when flowing bottomhole pressure (BHP) is above (single-phase) or below (two-phase) in-situ saturation pressure. These results indicate that lateral petrophysical heterogeneity can often be ignored when modeling tight unconventional wells. The explanation for this non-intuitive result is that the producing surface area from many hydraulic fractures is so extensive that the well-average GOR is very close to the GOR of a well producing from two petrophysically-homogeneous layers having arithmetic-average porosity and permeability. This finding reduces considerably the simulation run time (CPU) using a single "average" hydraulic fracture element, where the key fluid heterogeneity is solution GOR in each layer. Another important finding is that significant time-variation of producing well GOR may result even when flowing BHP remains higher than in-situ saturation pressures (i.e. single-phase flow). This behavior is caused by differential depletion of the individual layers with fluid contrast in viscosity and compressibility, i.e. without any contrast in layer permeabilities.

Well spacing and completion optimization in tight and shale reservoirs is a multi-dimensional task which comprise reservoir rock and fluid characterization, well performance study, inter-well communication analysis, and economic evaluation. Two sources of pressure data for characterization of inter-well communication include offset well pressure monitoring during hydraulic fracturing and controlled communication (interference) tests through staggered production. Both types of inter-well communication tests have become common among the operators in tight and shale reservoirs. However, quantitative analysis tools for interpretation of the test results are in their infancy. The focus of this study is quantitative analysis of pressure interference tests. In this study, an analytical model is developed for quantitative analysis of communication between multi-fractured horizontal wells (MFHWs) using pressure data from production and monitoring well pairs. The governing partial differential equation for the more general case of coupled flow in hydraulic fracture and matrix systems is solved using the Laplace transform. In order to validate the analytical model, the results from the analytical solution are compared against numerical simulation models. The analytical model of this study is applied to two field case from Montney formation. In these cases, a well from a multi-well pad is put on production and bottom-hole pressure of a monitoring well from the same pad is recorded using down-hole recorders. Communications between the wells is quantified using the analytical models of this study. The model of this study serves as a novel and practical tool for quantitative analysis and interpretation of inter-well communication in MFHWs. Integration of the model with other direct diagnostic and measurement tools can provide insight into optimized completion intensity for MFHWs.

With increased drilling activity associated with development of unconventional reservoirs, many operators are reporting both stimulation and production interference between wells. Interference between existing production wells (parent wells) and newly completed infill wells (child wells) is often associated with production impairment ( Marongiu-Porcu et al. 2015 ; Ajisafe et al. 2017 ; Defeu et al. 2018 and Manchanda et al. 2018 a). The objective of this work is to develop guidelines concerning infill wells completion scheme to minimize parent-child wells interference in a typical pad, with infill drilling in the Duvernay formation. The area of interest selected within the Duvernay formation consists of three parent wells and two child wells. An integrated mechanical earth model (MEM) was constructed for the area using public databases. The created 3D-geological model included petrophysical and geomechanical properties along with a 2D discrete natural-fracture network representing the distribution of natural fractures in the reservoir. Hydraulic fractures in parent wells were modeled using original stress settings from the 3D-MEM. Then, a dynamic model was constructed for the three parent wells and production simulation was run for five years. Pressure distribution at the time when child wells came into production was extracted and 3D depleted stress distribution was computed using a finite element method that included the effect of pore pressure decrease and principal stress magnitude and orientation changes. Then, hydraulic fracture modeling was performed for the two child wells using the new depleted stress distribution, and finally a five-well dynamic model was created. Sensitivity analyses were performed on the hydraulic fracture parameters of the child wells with the objective of maximizing recovery by accessing more virgin reservoir area between the parent wells. Hydraulic fracture modeling followed by dynamic simulation was done in the pad for multiple cases. Fracture geometry, hydraulic/propped surface area, and fracture conductivity in child wells were extracted and analyzed against production performance of the wells. This study shows a holistic approach in modeling the impact of completion modifications on the child wells performance in an infill drilling scenario. A 3D-geomechanical model coupled with reservoir simulation allowed simulating the propagation of hydraulic fractures in the presence of pressure depleted regions. Results confirmed that the main reason for under-performance of child wells in Duvernay is the stress change induced by the reservoir pressure depletion associated with the parent wells production hence, influencing the child wells hydraulic fractures propagation patterns.

Cyclic gas injection in hydraulically-fractured wells has been successfully applied as an enhanced oil recovery (EOR) method in tight unconventional basins such as the Permian and Eagle Ford. However, displacement processes (continuous gas, solvent or water injection) such as those piloted in the relatively more permeable Bakken formation have not been considered in tighter basins. In this work, we present a novel displacement process that uses alternating injecting and producing hydraulic fractures to flood the inter-fracture region around a horizontal well. We demonstrate that the method is feasible as long as suitable fracture geometries can be generated. A reservoir geomodel of a typical Montney gas condensate reservoir was constructed using publicly available data. Rock mechanics parameters were integrated into the model alongside completion and pumping schedule information to predict hydraulic fracture propagation and geometries representative of the typical stimulated volumes in Montney. A compositional numerical reservoir simulator was then used to test the proposed EOR process in a gas condensate reservoir where we forecast liquid recovery under different frac-to-frac continuous gas injection flooding scenarios. Sensitivities to study the effect of fracture spacing and complexity, solvent composition, starting time of gas injection, and matrix permeability were performed. With simultaneous injection and production from alternating hydraulic fractures, it is possible to flood the volumes between them and consequently avoid the drawbacks of huff ’n’ puff processes. By using a more rigorous fracture description, we can reproduce the interactions between fractures and determine how they affect the conformance of the displacement front. Modeling results showed that frac-to-frac displacement process can significantly improve the condensate recovery compared to primary or even huff n puff EOR process. They also showed that the frac-to-frac EOR process is feasible only if the formation mechanical properties and in-situ stresses are such that the resulting hydraulic fractures exhibit aligned planar geometries. If high-intensity natural fracture networks are present, the hydraulic fractures tend to form complex geometries that negatively affect the conformance of the flooding front. The study also showed that there is an optimal spacing between the injecting and producing fractures that would allow for the efficient utilization of the EOR agent; this spacing was shown to have a strong dependence on matrix permeability. Composition of injected solvent and starting time of gas injection doesn’t seem to have considerable impact on incremental recovery due to frac-to-frac displacement.

Hydraulic fracturing is an important method to improve the oil and gas production in low and ultra-low permeability reservoirs. A remarkable progress has been made in the technology and materials. However, the existing conventional hydraulic fracturing technology faces problems, such as reservoir damage, equipment abrasion, low effective propped area, and early screen-out. Therefore, a novel self-propped fracturing fluid (SPFF) was proposed, which remains in the liquid-phase before entering the fracture, and forms solid proppant particles when stimulated by the reservoir temperature after entering the fracture (Chemical proppant, CP). In this paper, the micro-morphology of CP was studied by SEM, and the temperature of the CP-formed was measured by the CP formation experiments at room temperature and field conditions. Furthermore, the compressive strength, thermal stability, stability in formation fluid, acid and alkali, leak-off, core damage, and fracture conductivity of the developed SPFF were tested. The test results show that the leak-off volume and core damage level of SPFF were less than that of conventional fracturing fluid, thereby effectively reducing the damage to the reservoir permeability. The CP exhibited good performance in terms of compressive strength, thermal stability, stability in reservoir fluid and treatment fluid. Besides, the conductivity of the propped fracture was high. These advantages determine that CP can meet the field treatment requirements. The CP could enter any narrow fractures, and effectively solved the existing problems in the conventional fracturing technology by significantly improving the fracturing effect, especially the network fracturing effect in tight reservoir systems.

Two earthquakes with the moment magnitude of 3.9 and 4.1 occurred in January 2015 and January 2016 near the Crooked Lake region, Alberta. Both earthquakes were attributed to the hydraulic fracturing operations of three horizontal wells located at the same well-pad. The underlying mechanisms of both earthquakes are still unclear and required to be investigated to mitigate risks of future seismicity in this region. In this study, the coupled simulations of the fluid flow and geomechanics were conducted to characterize the temporal and spatial evolution of pore pressure diffusion and stress perturbation during and after hydraulic fracturing operations. The Coulomb Failure Stress along the pre-existing fault near the horizontal wells were then calculated to study the reactivation of the fault. Sensitivity analysis was finally conducted to understand the effects of the fault's orientation, injection layer permeability, and distance between the fault and hydraulic fractures on the induced seismicity. The results showed that one North-South-oriented fault was activated twice after the sequential fracturing operations of three horizontal wells in 2015 and 2016. The M w 3.9 earthquake was triggered by the stress and pore pressure changes that activated the fault in the basement. The relatively long-time interval between the stimulation and the induced earthquake was attributed to the low permeability and geomechanics property from the injection layer to the fault. The subsequent M w 4.1 event was triggered by the direct connection between the hydraulic fractures, natural fractures, and the fault. Sensitivity analysis has suggested that the activation of faults were susceptible to the proximity between stimulated well and seismogenic faults, low permeability of the injection layer, and the low angle between the fault strike and the maximum horizontal stress.

This paper introduces a 3D hydraulic fracturing propagation model (3D-HFPM) for evaluating fracture extension, geometry, stress response, fracture spacing, and potential for refracturing. The model is illustrated with data of the Horn River shale of Canada. The model is developed using a combination of finite element method (FEM) and boundary element method (BEM) for evaluating fluid-flow, fracture deformation, and stress change in the reservoir. The model is calibrated using a limited amount of microseismic observations and recreate the fracture network when microseismic data are unavailable. An adapting meshing algorithm is incorporated to improve the capacity of the model to handle large and complex fracture networks such as the ones found in low permeability reservoirs. The continuity of fracture propagation and fluid leak-off during stimulation may be high enough to connect different production intervals and to create interference between stages, especially in wells with small path fracture spacing and multi-level completions. The comparison between the propagation model and microseismic data shows good agreement as the number of events increases as the fracture propagates into the reservoir. However, using only microseismic data to calculate the extension of the hydraulic fracture results in an overestimation of the fracture length. The model quantifies the altered stress zone, which is helpful to determine possible fracture reorientation and spacing. The evaluation of stress shadow and fracture reorientation reveals the advantages of refracturing using new over old perforations. The operation restores fracture conductivity and increases the fracture network as well as the drainage areas leading to an economic operation. The model improves the characterization of the Stimulated Reservoir Volume (SRV) in tight and shale reservoirs in those cases where microseismic data are scarce. Furthermore, the model is a viable tool for evaluating potential refracturing candidates.

In today's data-driven economy, operators that integrate vast stores of fundamental reservoir and production data with the high-performance predictive analytics solutions can emerge as winners in the contest of maximizing estimated ultimate recovery (EUR). The scope of this study is to demonstrate a new workflow coupling earth sciences with data analytics to operationalize well completion optimization. The workflow aims to build a robust predictive model that allows users to perform sensitivity analysis on completion designs within a few hours. Current workflows for well completion and production optimization in unconventional reservoirs require extensive earth modeling, fracture simulation, and production simulations. With considerable effort and wide scale of sensitivity, studies could enable optimized well completion design parameters such as optimal cluster spacing, optimal proppant loading, optimal well spacing, etc. Yet, today, less than 5% of the wells fractured in North America are designed using advanced simulation due to the required level of data, skillset, and long computing times. Breaking these limitations through parallel fracture and reservoir simulations in the cloud and combining such simulation with data analytics and artificial intelligence algorithms helped in the development of a powerful solution that creates models for fast, yet effective, completion design. As a case study, the approach was executed on Eagle Ford wells. Over 2000 data points were collected with completion sensitivity performed on a multithreaded cluster environment on these wells. Advanced machine learning and data mining algorithms of data analytics such as random forest, gradient boost, linear regression, etc. were applied on the data points to create a proxy model for the fracturing and numerical production simulator. With the gradient boost technique, over 90% accuracy was achieved between the proxy model and the actual results. Hence, the proxy model could predict the wellbore productivity accurately for any given change in completion design. The operators now had a much simpler model, which served as a plug-and-play tool for the completion engineers to evaluate the impact of changes in completion parameters on the future well performance and making fast-tracked economic decisions almost in real time. The approach can be replicated for varying geological and geomechanical properties as operations move from pad to pad. Although the need for heavy computing resource, simulation skillset, and long run times was eliminated with this new approach, regular QA/QC of the model through manual simulations makes the process more robust and reliable. The methodology provides an integrated approach to bridge the traditional reservoir understanding and simulation approach to the new big data approach to create proxies, which allows operators to make quicker decisions for completion optimization. The technique presented in this paper can be extended for other domains of wellsite operations such as well drilling, artificial lift, etc. and help operators evaluate the most economical scenario in close to real time.

The objective of this paper is to improve the evaluation and characterization of the fracture network as well as the production matching in the Horn River Shale of Canada. The task is carried out by extending the hybrid hydraulic fracture (HHF) model introduced by Urban et al. (2017) to a fully coupled fluid flow-geomechanical model that considers the far field stress stemming from the overburden, sideburden and underburden of the shale reservoir in an optimized simulation grid. The model evaluates the effects of depletion, of fracture closure and of permeability change using a discretized complex fracture network. In this paper, the fracture network is discretized using microseismic observations, when available. However, microseismic data may be limited in some of the fractured stages, or like in the case of most hydraulically fractured wells it might be non-existent. The fully coupled HHF model is developed to (1) improve the shale characterization and the simulation history matching, (2) study the fracture closure and permeability change in the fracture network due to gas production, and (3) alleviate microseismic data scarcity by generating a representative fracture network of those stages where microseismic data are unavailable. The stress change from the initial hydraulic fracturing is evaluated in nine paths multi-level horizontal wells that penetrated the Horn River Shale. The stress shadow is corroborated with microseismic observations and exhibited areas with high fracture density and productivity. The HHF model further evaluates the reservoir response to pore pressure depletion stemming from production, which leads to stress and permeability changes, fracture closure, and fracture reorientation. The procedure improves the simulation history matching by improving reservoir characterization, especially in stages closer to the toe where an understanding of fracture network geometry is problematic due to the cloud dispersion and scarcity of the microseismicity. The model also evaluates interference between well-paths and helps to determinate the optimum well, fracture and stage spacing. The HHF model was used to observe changes in volume, permeability and fracture connectivity in undepleted areas close to the fracture network. These areas reveal possible candidates for refracturing. A refracturing scenario that restores fracture conductivity and increases the drainage area of the fracture network is analyzed economically for evaluating the viability of that type of operation in the Horn River Shale. The HHF simulation model improves the shale reservoir understanding and simplifies the use of a highly complex fracture network for evaluating history matching, fracture closure and permeability changes during gas production. Furthermore, it provides a viable methodology to optimize well and stage spacing, and to evaluate potential refracturing candidates, where microseismic data is unavailable and a fracture network needs to be developed.

Research on stress shadows between stages and wells has provided new elements for understanding how the initial stress state in the subsurface is altered by the creation of hydraulic fractures. Furthermore, variations in pore pressure and the presence of faults and natural fractures are key factors contributing to heterogeneous initial stress conditions that ultimately influence fracture propagation patterns. In this case study, time-based poroelastic and viscoelastic approaches are used to quantify lateral stress gradients between wells and analyze stress shadow interactions at the stage-to-stage scale observed during completion of two Upper Montney siltstone wells. Utilizing interpreted microseismic data and offset well pressure monitoring data recorded during continuous-pumping completions of the two wells, a fault and pore pressure constrained poroelastic stress and relaxation model is derived. This model is used to map local modification of the initial stress state along parallel Upper Montney laterals. Initial stress conditions and stress shadow influences on observed fracture propagation patterns in the second well at multiple points during the completion is then used to determine dynamic, reservoir specific stress state modification characteristics as a function of time. Microseismic data from the two wells showed preferential fracture growth toward a fault identified in the seismic volume and an existing production Well 1. Well 2 situated closest to the fault and the existing producer Well 1, showed a modal fracture growth bias to the southwest, towards Well 1. Well 3, situated furthest from the fault and existing producer exhibited a bimodal fracture propagation direction. The initial southwesterly propagation bias repeatedly alternated to the northeast, away from the low stress envelope caused by the fault and existing producer. Based on the initial conditions and the unique fracture propagation patterns in the two wells, lateral stress variation is mapped and modeled using poroelasticity. To better understand the short-term stress relaxation effects on fracture propagation and the phenomenon of repeated asymmetric growth on either side of Well 3 (NE-SW-NE-SW…), a viscoelastic model is used to quantify the impact of stress shadowing and various relaxation times on fracture propagation. These observations led to the conclusions that the initial stress state is locally modified during hydraulic fracturing operations and that the stress disturbance caused by the depletion in one compartment around the existing production well continues to affect the stress conditions over significant distances, even in hydraulically disconnected reservoir compartments. This in turn affects the stimulation patterns of recently completed wells.

The recent success in developing unconventional reservoirs has caused many new challenges to the theory of reservoir engineering. In this paper, we try to investigate the anomalous diffusion phenomenon caused by the heterogeneity due to the fracture network on the reservoir scale. Firstly, we revisit the physical background of the single-phase flow diffusivity equation by discussing the equivalent single particle diffusion. Combining the characteristics of single particle diffusion with complex fracture geometry, it is indicated that anomalous diffusion phenomenon will be dominant on the reservoir scale, even for single phase production behavior. Then a model based on Markov chain is presented to demonstrate the proposed anomalous diffusion by simulating the partical normal diffusion on a geometric graph and then calculating the relation of the mean square displacement vs. time in the embedding Euclidean space. Based on the simulation results, in consequence, we make a discussion on the characteristic size of the heterogeneity due to the fracture network on the reservoir scale, summarize 2 types of pattern for the anomalous diffusion, and provide a supportive argument for using the fractional diffusivity equation, in place of the classical one, to model the flow and production behavior in highly fractured unconventional reservoirs.

The primary goal of this work is to demonstrate that the fractal geometry can be used to accurately model the rate and pressure performance behavior of highly heterogeneous reservoirs such as shale oil/gas reservoirs. There are multi-scale heterogeneities that can hinder modelling and diagnostic analyses, and the use of large stimulation treatments ( e.g. , multi-fractured horizontal wells) can further complicate the modeling of heterogeneous reservoir systems. The primary objective of this work is to provide analytical reservoir models and diagnostic interpretation relations that can be used to estimate the well and reservoir parameters for the case of a hydraulic fracture intercepting a horizontal well within a fractal reservoir. This work presents a semi-analytical solution for the pressure and rate transient behaviors of a horizontal well intercepting a single finite-conductivity fracture within a fractal reservoir considering either single or naturally-fractured/dual porosity reservoir conditions. The shape of the imposed hydraulic fracture can be either circular or rectangular. The media (the reservoir and the fracture) are "coupled" by discretizing the fracture, which defines a system of equations, the solution of which provides the pressure at any position inside the fracture. Naturally-fractured/dual porosity and anomalous diffusion effects are included by modifying the solution of the diffusivity equation for the reservoir in the Laplace domain. The diagnostic signatures ( i.e. , the pressure derivative functions) for the proposed semi-analytical solution illustrate the following features: Period 1 (Fracture flow): Radial or linear flow (depending on the geometry of the fracture) at very early times. As in classic studies for the case of a single finite-conductivity fracture, this period will never be observed in practice. Period 2 (Fracture-reservoir interaction): "Radial-Fractal" or "Linear Fractal" at intermediate-transient times. This period can be subdivided into two sub-periods: (1) early-intermediate and (2) late-intermediate. The early-intermediate period is analogous to the bilinear flow regime for a finite-conductivity vertical fracture in an infinite-acting homogeneous reservoir, whereas the late-intermediate is analogous to the formation-linear flow regime observed at most times for a case with a very high conductivity vertical fracture and at later times for cases with a medium to high conductivity vertical fracture. Period 3 (Reservoir dominated flow): "Pseudo-Fractal" flow. This flow period is dominated by the reservoir and yields power-law behavior ( i.e. , a straight line in the pressure drop and pressure derivative functions versus time on a log-log plot). In this "mechanistic"-style of study, we found that the heterogeneities of the reservoir represented by the fractal parameters, and/or the characteristics of the fracture itself can distort the pressure response during early/very early-times. Specifically, this work shows that the interaction between the fracture and the fractal reservoir can exhibit power-law pressure drop and pressure drop derivative signatures which are different from the distinctive one-quarter slope expected for bilinear flow. The following contributions are derived from this work: Proposed solution for the pressure drop and pressure drop derivative behavior of a horizontal well intercepting a hydraulic fracture within a fractal reservoir that exhibits several "power-law" flow regimes. Proposed features from our analytical solution for the characteristic early-time pressure drop and pressure drop derivative responses that may be of use in the diagnostic evaluation of fracturing treatments ( e.g , the effectiveness of the fracture treatment in connection with existing/enhanced natural fractures).

The most commonly used technology for development of unconventional liquid-rich and light oil reservoirs is horizontal wells combined with large multi-stage hydraulic fracture treatments. However, even with these technological advancements, primary recovery factors are generally less than 10% ( Shoaib and Hoffman, 2009 ) of the original oil in place (OOIP). Logically, operators have investigated the use of waterflooding to improve recovery in some tight oil reservoirs, but the success has been mixed. Low matrix permeability in some unconventional (tight) oil reservoirs will not allow effective displacement or movement of water through the reservoir. In some cases, even flooding with a gas will be a challenge, if matrix permeabilities are too low. This study investigates the feasibility of enhanced oil recovery (EOR) in a prominent tight oil reservoir in North America using cyclic solvent injection (CSI, sometimes referred to as "huff-n-puff") with carbon dioxide (CO 2 ) as the solvent. CSI is a single well process, with the solvent remaining in the vicinity of the wellbore, as flow of the solvent through the reservoir to another well is not necessary. This type of process may be attractive from a capital cost point-of-view, as large expenditures on specialized facilities, in-field pipelines and well conversions are unnecessary. In this study, the success and profitability of huff-n-puff is evaluated for the Bakken tight oil reservoir. Knowledge gained from a parallel study ( Kanfar and Clarkson, 2017 ) served to provide guidelines for optimizing the huff-n-puff process. Importantly, a genetic algorithm (GA) is utilized to find the optimum huff-n-puff program that maximizes net present value (NPV). Optimized parameters include: the number of cycles; duration of injection, soaking and production periods; and the start time of huff-n-puff operations. The target reservoir for evaluation is the US Bakken deep tight oil reservoir in North Dakota. The huff-n-puff EOR scheme was found to be successful, but only after the aforementioned operational parameters are optimized with GA. In particular, it is important to delay huff-n-puff until production rates decline and boundary-dominated flow (after fracture interference) is reached. Importantly, as with the parallel study ( Kanfar and Clarkson 2017 ), the gridding scheme used in the simulation is found to have a profound impact on results of huff-n-puff.

The purpose of this work is to perform an improved method to optimize different CO 2 Enhanced Oil Recovery (EOR) processes in unconventional liquid reservoirs, particularly in the volatile oil region of the Eagle Ford shale. Previous simulation studies of CO 2 EOR in the unconventional liquid reservoirs were not done in full field-scale and were not history matched before applying CO 2 EOR to the model. Without history matching step, the simulation might generate misleading results in CO 2 EOR studies. The dual-porosity, structured grid model in this paper will be history-matched with actual data collected from the field to ensure the results of CO 2 EOR study to be meaningful. In addition, we are implementing the simulation in the dual-porosity mode to account for the presence of natural fractures which have been observed on Eagle Ford outcrop. First, all data will be gathered from public sources. These data include production reports, outcrop map, natural fracture, hydraulic fracture, geology, rock, and fluid. Multiple grid sizes and number of refinements for hydraulic fractures will be tested to ensure the accuracy of the simulation is preserved yet speed up computational time. Several sensitivity analyses will be conducted to investigate which parameters from the matrix system and the natural fracture system would have a significant impact on the incremental oil recovery. These parameters will be adjusted scientifically in the process of history matching to capture the primary depletion. Then, this history-matched model will be used to apply multiple CO 2 EOR studies. The history matched model suggests that matrix porosity in the volatile oil region of Eagle Ford shale might be overestimated in many previous investigations. Also, the sensitivity analyses show that the natural fracture permeability perpendicular to the direction of the horizontal well has a significant impact on oil rates in numerical simulation. Among different CO 2 EOR methods tested in this research, huff-n-puff yields the most promising outcome as compared to continuous injection and WAG (Water-alternating-gas) in both oil production and economic performance in the volatile oil region of the Eagle Ford shale. In some circumstances, continuous injection method might yield great utilization efficiency but it contains high possibility of negative incremental oil recovery at the end of EOR practice due to pressure loss during CO 2 injection time, incomplete miscible process between CO 2 and residual oil, and viscous fingering.

Many stimulated shale gas wells experience surprisingly low fracturing fluid recoveries. Fracture closure, gravity segregation, fracture tortuosity, proppant distribution, and shut-in (soaking) time have been widely postulated to be the contributing factors. This study examines the impacts of these factors on fracturing fluid distribution using flow and geomechanical simulations. The results are analyzed to understand the circumstances under which fluid recovery might be beneficial or detrimental to well performance. A series of 3D numerical models are constructed based on petrophysical parameters, fluid properties and operational constraints representative of Horn River shale gas reservoir. Hydraulic fracture is modeled explicitly in the computational domain. Complex partially-propped fracture geometry is computed using numerical constitutive models. The physical process of fracture closure during shut-in and production periods is modeled by adjusting the fracture volume and fracture conductivity dynamically. Non-Darcy behavior due to high gas velocity in fracture and matrix desorption are considered. The coupled effect of multi-phase flow, gravity and geomechanics is simulated to examine the mechanisms responsible for the low fracturing fluid recovery and the ensuing fluid distribution away from the wellbore. Water uptake into the matrix is influenced by forced and spontaneous imbibition due to the large pressure differential across the matrix-fracture interface and matrix capillarity. Additional water is displaced into the matrix as pressure depletes and fracture closes. Gravity segregation may lead to water accumulating near the bottom of a vertical planar fracture, but fracture tortuosity could limit the segregation and promote a more uniform fluid distribution. The influence of proppant distribution is far more complex: results of the geomechanical simulation confirm the formation of a residual opening above of the proppant pack in a partially-propped fracture. Despite gas production is often hampered by non-uniform proppant distribution, the residual opening offers a highly conductive flow path for gas, which is much more mobile than the water-based fracturing fluid; this further aggravates the phenomenon of gravity segregation. Extended shut-in time may enhance the initial gas rate, but lower late-time production is observed. Analysis of the residual opening of a partially-propped fracture and its implications on production performance is novel. The results highlight the interactions between different mechanisms on fracturing fluid distribution in 3D. A few practical insights pertinent to the optimal operation strategy are explained.

This paper presents a new integrated workflow that couples geology, geomechanics and geophysics (3G) with a constrained asymmetric frac model as applied to a Wolfcamp well to address the concerns of well interference. The proposed workflow enables the ability to adapt the frac design of each stage based on the in-situ geologic and geomechanical variability. The objective of this approach is to identify the variable treatment parameters required to overcome the stress heterogeneity and estimate the impact of the adaptive frac design on the final fracture geometry. The lateral stress gradients resulting from the pressure depletion due to a nearby producing well and the fluid leak-off due to opening of natural fractures are fine-tuned to account for asymmetry observed in the geomechanical modeling. The role of the natural fractures is emphasized and practical approaches to estimate a validated natural fracture model are described and illustrated. A validation well is used to highlight the importance of the input natural fracture model in calculating validated differential stress and strain that reproduce the main features of the microseismic. With this validated strain model, a constrained frac design provides the proper asymmetric fracture geometry able to pinpoint the poor and good frac stages. Once the workflow is extensively validated, it can be used on target wells to avoid frac hits. In this Wolfcamp example, the challenge was to find the optimal frac design to minimize interference of an infill well with existing offset producers. To address the possible zones of interference, the stage spacing was locally increased to 152 m (500 ft), and the treatment was especially modified in the middle stages of the well. This resulted in reducing the number of stages from 40 to 34, specifically in zones indicating high probability of interference. The design was altered from pumping a mixture of 320,000 lb of 100 mesh and 40/70 mesh sand to 220,000 lb of 40/70 mesh sand, and the injected fluid viscosity was increased from 10 centipoise (cP) for slick water to 30 cP for linear gel as better carrying capacity was required to pump only 40/70 mesh sand. Additonally, the injection rate was reduced from 105 bbl/min to 80 bbl/min. The integrated approach allows for the ability to adapt the frac design to in-situ conditions including heterogeneity in the stress fields and the pressure depletion from existing producers. Adaptive frac design significantly reduces the probability of frac hits and well interference. The proposed modeling workflow enables greater investment efficiency and overall field development optimization.

Many operators have used in the past various methods to analyze and optimize the horizontal well (HW) completions in the Eagle Ford play with varied results. Typically, such methods focus on different parts of this complex problem in relative isolation and as a consequence do not utilize all available data simultaneously. This paper presents a simulation-based method for analyzing the problem in an integrated fashion by modeling the fracturing and Stimulated Reservoir Volume (SRV) creation process, followed by well cleanup and production. Consequently, all available data are used to constrain the history match (HM), resulting in a more reliable tool for optimization. In this work, the authors developed a comprehensive integrated model of a typical Eagle Ford well in the Dimmit County. The HM process showed that injection and production scenarios must be modeled in tandem to get better insights into the flow physics rather than simulating them separately. The best accuracy is obtained when the real sequence of fracturing is modeled. It was found that only a fraction of the created fracture and SRV lengths contribute to production. Whereas fracture half-lengths of ~250 ft were generated during injection, only about ¼ of fracture and ¾ of SRV contributed. Effect of completion efficiency was also investigated. It was shown that the assumption of only 2 perforation clusters per stage is not plausible while assuming some other scenarios offers good HM and prediction very similar to uniform efficiency. Optimization work considered several scenarios. Cases with larger cluster/stage spacing with the same pumped volume are not desirable. However, the use of double the cluster spacing gives slightly higher estimated ultimate recovery in 30 years, and could offer significant completion cost savings. Use of current injection volumes and current well spacing (500 ft) leaves significant reservoir volume undrained, which is a target for well spacing optimization. Pressure (as opposed to stress) dependent permeability functions adequately capture the permeability variation both for injection and production. The work shows how the integrated reservoir/fracturing/geomechanics modeling can be used to optimize completions and EUR for shale wells.