Low injected fracturing fluid recovery has been an issue during flowback period that is highly impacted by the fracture closure behavior. Although existing flowback models consider fracture closure volumetrically, they do not represent the true situation of non-uniform fracture closure. In this paper, we proposed a coupled geomechanics and fluid flow model for early-time flowback in shale oil reservoirs. The fluid flow model is coupled with an elastic fracture closure model through finite element methods. In this study, three stages are modeled: fracture propagation, well shut-in and flowback. Cohesive Zone Method (CZM) has been used for modeling fracture propagation. The presented model distinguished the propped part from the unpropped part of the fracture. At the beginning of flowback, the proppants may not be completely compacted in early shut-in time. Thus, permeability evolution during closure is tracked using a smooth permeability transition function. The numerical results have shown that fracture closure during the flowback period is often not uniform. While the uniform fracture closure leads to maximum fracturing fluid recovery, an aggressive pressure drawdown strategy may damage fracture connectivity to the wellbore. An integrated flowback model enables modelling nonuniform fracture closure in a complex fracture network. This study highlights that by choke/pressure drawdown management, operators can influence fluid recovery and even maintain high fracture conductivity. Furthermore, the methodology presented in the paper can also be used for inverse analysis on early flowback data.

Due to the complexity of shale reservoir geology, hydraulic and micro-fractures can be coupled into an extremely complex symmetrical or asymmetrical fracture network around vertically fractured wells (VFW) after fracturing. The important and useful work is to analyze the transient pressure response of the VFW, to more accurately predict the productivity of VFW. In this paper, a numerical method to accurately simulate the complex fracture network geometry and analyze the transient pressure responses of the VFW, due to the complexity of the fracture network geometry. The results show a longer fracture length on one side causes a smaller pressure depletion, a shorter bilinear flow, and a deeper and longer the degree of "dip". The more fractures on one side can lead to a greater degree of "dip" and a smaller pressure depletion. With the fracture conductivity on the right side increases, while that in other side remains constant value, it results in a shorter bilinear flow, a deeper and longer the degree of "dip", a smaller pressure depletion, and a weaker bi-radial flow (BRF). In addition, it is found that flow regimes affected by magnitude of fracture networks are mainly bi-linear flow (BLF), "dip" and BRF. The pressure behaviors between asymmetrical fracture networks and symmetrical fracture networks are mainly in the periods of BLF, "dip", and BRF. Through analyzing the transient pressure responses of the VFW, the parameters of the complex fracture network can be well predicted, so that the productivity of the VFW can be estimated more accurately.

Production data and analytical models derived from coupling the linear flow in the reservoir and the linear flow in hydraulic fractures were used in this study to optimize fracture spacing for maximizing productivity of shale oil and gas wells through refracturing. This study concludes that productivity of multi-fractured horizontal wells is inversely proportional to the fracture spacing. The shortest possible fracture spacing should be used to maximize well productivity through refracturing. This supports the practice of massive volume fracturing where as many as perforation clusters with the shortest possible spacing are used for pumping massive proppant into the created hydraulic fractures. Production data analysis indicates that the multi-fractured horizontal oil and gas wells could have higher productivity if they were fractured with less perforation cluster spacing. Mathematical model analysis implies that reducing the cluster spacing from 70 ft to 15 ft through refracturing can doubled well productivity, with the Minimum Required Cluster Spacing (MRCS) determined by well completion constraints (packers, perforation clusters, and casing couplings). Result can be checked for fracture trend interference on the basis of analyses of pressure transient data or production data.

The Marcellus formation has begun to attract more attention from the oil and gas industry. Despite being the largest shale formation and biggest source of natural gas in the United States, it has been the subject of little research. To fill this gap, this study experimentally examined the rock properties of twenty core samples from the formation. Five tests were performed on the core samples: X-ray computerized tomography (CT) scan, porosity, permeability, ultrasonic velocity, and X-ray diffraction (XRD). CT-scans were performed to identify the presence of any existing fracture(s). Additionally, helium was injected into the core samples at four different pressures (100 psi, 200 psi, 300 psi, and 400 psi) to determine the optimal pressure for porosity measurements. Complex Transient Method was employed to measure the permeabilities of the core samples. Ultrasonic velocity tests were conducted to calculate the dynamic Young's moduli (E) and the Poisson's ratios (ν) of the core samples at various confining pressures (in increments of 750 psi between 750 psi and 4,240 psi). Finally, the mineralogical compositions of the core samples were determined using the XRD test. The results of the CT-scan experiments revealed that seven core samples contained fractures. The porosity tests yielded an optimal pressure of 200 psi for porosity measurement. The measured porosities of the samples were between 6.43% and 13.85%. The permeabilities of the samples were between 5 nD and 153 nD. The results of the ultrasonic velocity tests revealed that at the confining pressure of 750 psi, the compressional velocity (V p ) ranged from 18,411 ft/s to 19,128 ft/s and the average shear velocities (V s1 and V s2 ) ranged from 10,413 ft/s to 11,034 ft/s. At the same confining pressure, the Young's modulus and Poisson's ratio ranged from 9.8 to 10.8 million psi and 0.25 to 0.28, respectively. Increase in the confining pressure resulted in increases in the V p , V s, Young's moduli, and Poisson's ratios of the samples. The results of the XRD test revealed that the samples were composed of calcite, quartz, and dolomite. This study is one of the first to characterize core samples obtained from the formation outcrop by performing five tests: CT-scan, porosity, permeability, ultrasonic velocity, and XRD. The results provide detailed insights to researchers working on the formation rock properties.

Horizontal wells with hydraulic fractures enable economical hydrocarbon extraction from unconventional reservoirs, and the associated transient production data is a reliable source for reservoir characterization. However, the complicated convolution of rate-pressure-time history leads to a less informative analysis of true reservoir characteristics. This paper presents a novel data-driven deconvolution approach using physics-based superposition to reconstruct constant-rate-drawdown pressure response, which are further translated into diagnostic plots for efficient production analysis. Traditional deconvolution in pressure transient analysis is usually an ill-conditioned "inverse" process that requires systematic curve-fitting, and the deconvolution response is highly sensitive to noise. Our proposed approach uses superposition equations as training features to honor the transient physics, and further projects them into higher dimensional ‘reservoir’ space (kernel-space) for the purpose of rigorous regression. Additionally, by implementing Laplacian eigenmaps, our algorithm is relatively insensitive to noise owing to its locality-preserving character. After training, the constant-rate-drawdown pressure response is reconstructed and a diagnostic plot is generated to identify key reservoir characteristics such as flow regimes. We first validated our approach with two synthetic cases, a horizontal well with single and multiple transverse fractures (MTFW), and the drawdown pressure response was obtained through simulation using a highly variable flow rate history. Additionally, we added artificial white Gaussian noise to the simulation output to mimic measured signals collected in the field, and we input this data into our model for deconvolution. The model-reconstructed constant-rate-drawdown pressure response was used to determine flow regimes and reservoir properties such as permeability and stimulated reservoir volume (SRV) using traditional transient testing diagnostic tools and specialized plots. The deconvolved response for each case were in alignment with the fractured-basement reservoir model proposed by Kuchuk et al. (2012) , and the flow regimes identified during MTFW production followed the theory proposed by Song et al. (2011) . All deconvolved responses were further validated through comparison with both simulation results and analytical solutions. Through the inherent locality-preserving character, our proposed algorithm was able to handle a moderate level of noise in addition to the variation of pressure-rate signals. We then applied the methodology to a field case, and the outcomes were satisfactory. This study showed that our proposed methodology is a reliable diagnostic tool to interpret pressure-rate data using traditional pressure transient analysis for unconventional reservoirs. Rapid and accurate deconvolved pressure response greatly enhances the analysis of data with moderate noise and highly variable production histories, enabling engineers to recognize flow patterns and estimate reservoir properties. We demonstrated the versatility and applicability of our proposed approach with synthetic and field cases.

Though seemingly straightforward, the concept of "net-to-gross" (NTG) is often a source of confusion. Its proper use is still being debated in some portions of the oil and gas industry. NTG is a method to account for non-reservoir quality rock when calculating oil volumes within a reservoir. This is normally accomplished by applying cutoffs to calculated quantities, such as porosity, which then get excluded from the volumetric calculation. To the extent there have been recent discussions of this, the focus has been primarily on how to determine appropriate cutoffs. There has been very little mention of the implications of using NTG in flow equations within a reservoir simulator. The paper discusses the derivation and implied assumptions for the simulator NTG formulation and possible errors and proposes modifications to account for inconsistencies. Resolving the NTG flow equations can be viewed as an upscaling problem, subject to implied assumptions about reservoir continuity. Many fine-scale reservoir simulations were run to test this and to calibrate the NTG equations. The underlying attributes were sampled from a bimodal distribution, which represent pay and non-pay. The results show the effects of NTG ratio, values of fine-scale attributes and spatial correlation on steady state, single phase effective permeability and immiscible flow displacements. They demonstrate errors in effective horizontal and vertical permeability when using NTG within a simulator. These errors cause potentially significant differences in production responses between underlying detailed fine-scale models and coarser models. The results demonstrate a possible need for corrections to the simulator net-to-gross formulations due to underlying implied assumptions and inconsistencies. Some possible modifications are also presented. Both standard and machine learning techniques were used to analyze the results.

Production from shales can be dependent on many things, including multiple reservoir properties, drilling, completion and production methods. Designs and analyses often focus on drilling and completion issues, such as number of stages, wellbore length and fracture properties, such as conductivity, length, spacing and complexity. As a result, many aspects of the reservoir, fractures and production methods can be significant. Flow from the reservoir to production points is driven by pressure drops. If an entire well including fractures and surrounding reservoir is considered as a single system, then the production behavior is driven by the magnitude of three pressure drops and corresponding resistances to flow in the system. Those that need to be considered are: pressure drop between the reservoir and the fractures, pressure drop along the fractures to the wellbore perforations and pressure drop along the wellbore to the pump inlet or tubing head. Different aspects of the well/fracture/reservoir system become important, or unimportant, depending on the relative magnitude of these pressure drops and resistances to flow. For example, many people believe that fractures should be as long as possible assuming they can be restricted to zones of interest and do not interfere with other wells and/or fractures. However, since the pressure along a fracture increases as you move further away from the wellbore, increasing fracture length can have diminishing returns for reservoirs with small reservoir to fracture pressure drops and/or low fracture conductivities. Similar effects pertain to number of fractures, fracture spacing and wellbore lengths. This paper analyzes effects of different reservoir, fracture and wellbore properties and the influence of different pressure drops on shale well productivity.

The present study used the workflow presented in Al-Ameri et al. (2018a , 2018b ) to evaluate the impact of the fracturing fluid imbibition on the near fracture face shale matrix. Al-Ameri et al. (2018b) used carbonate-rich outcrop shale core samples that had very low and no clay content. However, in this workflow, core samples from the Barnett reservoir that had an abundant amount of quartz and clay were used. The primary aspect of the current study is to investigate the mutual effect of the shale rock petrophysical properties and the polymer adsorption; moreover, the effect of the shale mineralogical composition on the rock prone to adsorb polymer. The effect of the non-ionic surfactant on the imbibition rates, and also the anisotropy on the rock ability for polymer adsorption were also investigated. The results of this workflow were compared to the Marcellus samples results presented in Al-Ameri et al. (2018b) . The workflow incorporates conducting three systematic imbibition experiments for a same shale core sample using brine, slickwater, and brine again. The sample brine permeability was measured before and after the imbibition experiments using a constant rate steady-state permeability setup. The results showed that the polymer adsorption reduces the brine spontaneous imbibition volumes. Moreover, the shale petrophysical properties could dominate the polymer adsorption more than the mineralogical composition. Adding a non-ionic surfactant to the slickwater enhanced the imbibition rate considerably into both of the Barnett and Marcellus shale samples, and that improves the fluid flowback in these shales. The bedding planes and their orientation are among the factors that control the effect of the polymer adsorption on the fluid imbibition rate. The more obvious are the bedding planes, the higher impact of the polymer adsorption on the fluid imbibition rate. However, the petrophysical properties have more effect on the shale prone to adsorb the polymer than the bedding plane orientation. The effect of the polymer adsorption slightly increased the capillary pressure curve. However, as the porosity and permeability increase, the effect of the polymer adsorption on the capillary pressure increases. In comparison to the Eagle Ford shale, the Barnett and Marcellus shales had lower capillary pressure, and that could be one of the reasons of their higher fluid flowback. The impact of the polymer adsorption on the water relative permeability was less for the Barnett sample in comparison to the Marcellus sample because of its lower porosity and permeability.

Fundamental research targeting the interactions of CO 2 and fluids with unconventional shale systems is limited from the perspective of using carbon dioxide 1) as an alternative fracturing fluid, 2) as an agent to enhance hydrocarbon production, and 3) as an injection agent into the shale formation for storage purposes to avert emissions to the atmosphere. In this work, we apply in-situ infrared spectroscopy (FT-IR), scanning electron microscopy coupled with energy dispersive spectroscopy (SEM-EDS), and Brunauer-Emmett-Teller (BET) surface area and density functional theory (DFT) pore size analysis to examine the effects of CO 2 and fluid on the Marcellus and Utica Shales. Results show changes to the shale at both the micron and nanometer scale after reaction with CO 2 and water. These alterations could potentially alter overall permeability and fracture networks that may cause issues for future EOR activities, CO 2 storage, and/or the practice of using CO 2 as a hydraulic fracturing material.

Nano-Roughness coating reduces the fluid/solid interaction leading to super-hydrophobicity or the Lotus effect. The objective of this study is to determine how this phenomenon can be applied in petroleum production system to enhance fluid flow in propped fractures using nano-roughness coating on the surface of proppants. The permeability and the wettability of coated proppant packs are compared with non-coated packs to determine the reduction in friction or enhancement in fracture conductivity. The simulation of flow in a proppant pack is done using sand packs of different permeabilities. The base case for the work is established using sandstone samples with various permeabilities. The sandstone samples include Gray-Berea with uncoated absolute permeability of 86 mD, Buff Berea with uncoated absolute permeability of 374 mD, Bentheimer sandstone with uncoated absolute permeability of 277 mD and Leopard sandstone with the uncoated absolute permeability of 803 mD. The sand packs used are 20/40 mesh with uncoated absolute permeability of 31 D, 40/60 mesh with uncoated absolute permeability of 22 D and 50/70 mesh with uncoated absolute permeability of 21 D. After measuring the absolute permeability, wettability (using contact angle method) and relative permeability, all the samples were coated and the properties were measured again. The results show that the modification enhances fluid flow through pores. The surfaces for all the samples were altered from a hydrophilic to a hydrophobic surface. The contact angle between the fluid and samples was observed to be almost 90° with water and >60° for oil, after modification. This confirms modification of samples to partial-wetting state. An increase in absolute permeability is observed from 14.54% for Gray-Berea to 184% for Leopard sandstone. The increase in absolute permeability for sand packs is observed from, 23% for 20/40 mesh sand, to 5.28% for 50/70 mesh sand. It was observed that modification is more efficient for a sample with a higher permeability, but further studies are in process to relate the permeability enhancement to total surface area. Since the production rate of tight sandstone and shale reservoirs is low, especially in liquid-rich reservoirs and significant amount of water is injected for reservoir stimulation, enhancement in fracture conductivity resulting from proppant surface modification can have a meaningful impact on the recovery of these reservoirs. This study uses experimental techniques to show the effectiveness of nano-roughness coating on the reduction of friction which can lead to enhancement in fracture conductivity.

Well spacing optimization is one of the most important considerations in unconventional field development. The Appalachian basin development has been increasingly prevalent in the last decade due to substantial production performance from Marcellus, Upper Devonian, and Utica/Point Pleasant Shale plays. The majority of operators have been in a manufacturing mode, where a standard well spacing and completions design have been applied to a field with less emphasis on optimizing the net asset value of the field. NAV can be improved through modeling and various optimization workflows such as numerical simulation, machine learning, and linear programming. The essence of field development and optimization is to use completions design, as well as well spacing, to optimize the net present value of the field based on current commodity pricing, capital expenditure, operating cost, cycle time, and net revenue interest. A substantial change in any of these essential factors must be studied to make sure the appropriate changes are accounted for in the field development and optimization. Determining the optimum well spacing that coincides with the completion design can often be challenging and time consuming due to complexity of some governing factors such as geology, engineering, and economic analysis. For instance, if optimum well spacing and completions design were developed in a geologically noisy and complex reservoir, the outcome may no longer be valid in a discreet and quiet area. In addition, if well spacing and completions design were developed for a high commodity pricing environment, performing the same workflow and evaluation at a lower commodity pricing would yield an increase in well spacing. The dynamic nature of the oil and gas industry, specifically these essential factors, could cause complications with selecting the optimum well spacing and completion design to maximize the shareholder's value. Therefore, a fast-paced and dynamic workflow has been developed, that can be applied in different shale reservoirs, to maximize the present value of these assets. This paper will walk through the step-by-step process that can be applied to any unconventional shale play to optimize the field considering geology, engineering, and economic analysis. The objective of this paper is to go through a fast-paced optimization workflow, starting with a fracture model, coupled with a production model using numerical simulation to obtain a calibrated model, and finally performing detailed economic and sensitivity analysis to obtain the optimum well spacing and completions design, which would yield the highest net present value of the field.

Unconventional reservoirs have high initial production rates followed by a steep decline as compared to conventional reservoirs. The increase in the net stress with the production results in matrix and fissure permeability reduction and hydraulic fracture compaction and conductivity impairment due to proppant embedment. At the same time, the pressure decline will result in gas slippage and matrix permeability enhancement. The impact of the net stress and pore pressure changes are often neglected when evaluating the production performance of the shale wells. The objectives of this study are to investigate the impacts of net stress changes (geomechanical) and pore pressure changes (gas slippage) on the gas production from horizontal wells with multiple hydraulic fractures completed in the Marcellus Shale. Laboratory measurements on Marcellus shale core plugs provided the foundation for evaluating the impact of pore pressure and net stress changes on the matrix permeability. Additionally, these laboratory measurements on Marcellus shale core plugs provided the fissure closure stress. The results of the published studies on Marcellus shale core plugs were also utilized to develop relationships for hydraulic fracture conductivity and the fissure permeability as a function of the net stress in the shale. Core, log, completion, stimulation, and production data from the wells located at the Marcellus Shale Energy and Environment Laboratory (MSEEL) were utilized to generate the formation and completion properties for the base model for a horizontal well completed in Marcellus Shale. The results of the laboratory measurements and published studies were then incorporated into the base model to account for the impact of the stress on the matrix, fissure, and hydraulic fracture permeability (conductivity), and consequently on the production performance. The model was utilized to determine the effective properties of the hydraulic fractures by history matching the production data from two horizontal wells at MSEEL site. For the comparison purposes, the geomechanical effects were excluded from the model, individually and all combined, to history match the same production data from the horizontal wells. The results indicated that the geomechanical effects for fissure permeability have a significant impact on gas production as compared to geomechanical effect for matrix permeability and hydraulic fracture conductivity. The gas slippage was found to have an insignificant impact on the production. The base model was finally used to perform a number of parametric studies to investigate the impact of fracture half-length, initial fracture conductivity, and fracture stages spacing on the stress-dependent fissure permeability.

A semi-analytical framework for predicting the onset of sand production in a horizontal well is presented. The approach couples the flow in perforation tunnels with flow in the wellbore itself, to obtain a more accurate estimate of maximum sand free production rate in a well. The elastic equations of equilibrium are combined with the Mohr–Coulomb failure criterion to calculate the critical radius. A numerical, iterative solution method is used to compute the location of the elastic-plastic zone during well production. Instead of computing the pressure change in a cavity, which is difficult to characterize and implement in practice, the proposed model integrates the cavity stability criteria into the perforated wellbore inflow model to determine maximum sand-free wellbore flow rate. In addition to the typical perforation tunnel parameters such as cohesive strength, friction angle and perforation radius considered in past efforts, pressure loss effects in a wellbore (wall friction, acceleration, and fluid mixing) are incorporated into the proposed model. A numerical shooting method is then used to iteratively arrive at the maximum sand free rate for a perforated horizontal wellbore in a reservoir of known properties. Results show that without incorporation of the inflow model, the predicted maximum sand-free rates from prevailing approaches can be over-optimistic. The proposed method can be used to optimize perforation parameters to prevent sanding when designing well completions.

A deep insight into tight gas transient flow behavior is important for understanding the production behavior of tight gas reservoirs. In this work, we constructed a two-dimensional model to illustrate one methodology of evaluating effective permeability of fractured flow media. Pulse-decay experiments on one fractured core to study porosity and permeability for both matrix and the fracture, under a series of pore pressure and effective stress. Based on the results, the approach proposed in this study has the advantage over the steady-state method that can capture the character of transient flow if the fracture network penetrates the core. The transient gas propagation in the matrix, fractured cored with the fracture width of 1 μm and 1 cm are in shapes of piston-like, arrow-like, and dumbbell-like, respectively. Though the fracture width is only 1 μm, it reduces the time to reach pressure equilibrium to about one-fourth and the effective permeably ratio is 3.98. Totally 59 pulse-decay experiments were performed on one fractured core. We successfully history matched all the pulse-decay experiments on a fractured core by a commercial simulator with the Global Match Error (GME) less than 0.2%, that the readers can readily adopt this approach. Based on the history matching of upstream and downstream pressure curves, the fracture permeability and porosity are 6 orders’ and 1 order's magnitude higher than the matrix. The matrix permeability is the most sensitive to the pore pressure and effective stress, and no consistent trend is observed for the fracture permeability and porosity as the pore pressure and effective stress change.

Proper design and analysis of field tests requires two critical components: 1) availability of quality production data from appropriate control wells, and 2) a normalization process capable of isolating the impact of well and/or completion design changes on well performance. We will present a normalization workflow currently employed in our Marcellus Shale assets. Normalization methodologies published by others will be summarized and discussed in this paper as well. Lastly, we will compare these published methodologies to our proposed approach, noting the pros and cons of the various approaches. We begin by discussing an updated rate transient analysis (RTA) workflow (update of SPE-165711) that is based on analysis of 1,000+ Marcellus Shale wells with several years of production history, and incorporates several "lessons learned" in regard to non-uniqueness issues and input uncertainties. Details of our proposed normalization process will then be presented, which involves Production Data Analysis (PDA), Rate Transient Analysis (RTA), and analytical modeling. Lastly, we will explore a case history illustrating the value of this normalization process. The case history will demonstrate the use of this normalization process to assess the value of different completion designs. This study will clearly illustrate the value of implementing an adequate normalization process to 1) assess field tests, 2) accurately forecast well productivity, 3) evaluate well economics associated with further testing, and 4) better understand why a new design performs differently from previous designs.

In multi-fractured horizontal wells (MFHW), fracture properties such as permeability and fracture half-length significantly deteriorate during early production, which negatively affects gas production from shale reservoirs. Therefore, it is crucial to evaluate the temporal changes in fracture properties based on production data. This paper presents a workflow in which both flowback and long-term production data are used to quantitatively evaluate hydraulic fracture closure and changes in the fracture properties. In addition, we develop a two-phase semi-analytical model based on rate transient analysis (RTA) that assumes boundary dominated flow during the flowback period. The proposed workflow consists of three steps. First, we used the flowback data to calculate fracture properties, such as initial fracture permeability and fracture half-length, by employing the two-phase semi-analytical model. Then, we calculated initial fracture permeability by using a single-phase bilinear flow model as well as the fracture half-length and matrix permeability by using a single-phase linear flow model from the long-term gas production data. These models consider pressure dependency of permeability. Last, we compared the results that are calculated from both flowback and long-term production data to evaluate fracture closure and its effects on fracture permeability. We validated the semi-analytical flowback model and the workflow against numerical simulations. The results show that the developed model is capable of predicting fracture properties and evaluating fracture closure. Furthermore, the proposed workflow provides quantitative insights on the performance of fracture stimulation and is able to closely estimate permeability modulus using flowback and long-term production data instead of conducting laboratory experiments.

Natural fractures are the main producibility factor in the weathered granite reservoirs (basement rock) and volcanic-rock reservoirs. Production practices show that these reservoirs could have high production rate, but the difference of well productivity between single wells is obvious. These reservoirs have complex natural fractures oriented at medium-high angles, which could bring high complexity and heterogeneity to the reservoirs, adding anisotropy to reservoir permeability. It is very hard to effectively simulate complex fractures in naturally fractured reservoirs and study the applicability of different well type and well pattern by using common reservoir simulators. A fast EDFM (Embedded Discrete Fracture Model) method was put forward for production simulation of complex fractures in naturally fractured reservoirs. The EDFM processor combining commercial reservoir simulators (ECLIPSE or CMG) is fully integrated to forecast production performance of the weathered granite reservoir. With a new set of EDFM formulations, the non-neighboring connections (NNCs) in the EDFM are converted into regular connections in traditional reservoir simulators, and the NNCs factors are linked with gridblock permeabilities. So complex dynamic behaviors of natural fractures can be captured, which can maintain the accuracy of DFMs (discrete fracture models) and keep the efficiency offered by structured gridding. In this paper, a 3D model with complex natural fractures was built to model the performance of different well types and well patterns. The results show that wells with higher density of natural fractures produce higher oil production, and horizontal wells with higher density of natural fractures have larger oil production than vertical wells because horizontal wells have a larger contact area than vertical wells. What’s more, heterogeneity and anisotropy have a great effect on well pattern and well type, which need to be studied carefully in the oilfield development.

The development of shale assets has reached a point where operators face the challenge of infill drilling. The scope of this project is to investigate the impact of neighboring well pads on the performance of a newly developed well/pad. This paper highlights the differences in production performance of "old" pads versus "new" well and analyzes how the depletion history of the existing pads affects the performance of new well. The study area covers two pads: Pad A and Pad B which have 10 and 12 wells respectively; these wells have been producing since 2016 from the dry gas region of Marcellus Shale in southwestern Pennsylvania. Pad A and Pad B are more than 9000 ft apart, and the region between these two pads has potential for future development. For this project, a 3-D reservoir simulation model that includes both pads was built and calibrated to match past performance of Pad A and Pad B. The calibrated simulation model then was utilized for developing new wells. The reservoir simulation model was used to perform a sensitivity analysis on reservoir characteristics and the impact of Pad A and Pad B's depletion history on the performance of new well(s). The workflow involves optimizing the well spacing of proposed well(s) with/without considering the depletion history. Usually, with the very low permeability of shale reservoirs, the depletion history of neighboring wells is expected to affect the performance of newly developed wells. The new wells are considered as a different well pad, and their stimulated reservoir volume does not overlap with the Pad A and Pad B. However, the region average reservoir pressure is reduced due to the Pad A and Pad B production history. In most of shale reservoir numeral simulation studies, the reservoir is considered virgin. The average reservoir pressure potentially impacts the well spacing optimization workflow as well as the designing of an effective well completion job. In this study we compare two scenarios. One scenario considers the depletion history of neighboring well pads and the other one does not. The net present value optimization was done with and without considering the impact of depletion history. This project studies the effects of neighboring well pads on production performance of newly developed pad. Compared to the interaction of parent/child well in a single well pad, multi-pad studies are rare primarily because of the high computational cost associated with a multi-pad numerical simulation analysis.

The natural gas from Marcellus Shale can be produced most efficiently through horizontal wells stimulated by multi-stage hydraulic fracturing. The objective of this study is to investigate the impact of the geomechanical factors and non-uniform formation properties on the gas recovery for the horizontal wells with multiple hydraulic fractures completed in Marcellus Shale. Various information including core analysis, well log interpretations, completion records, stimulation design and field information, and production data from the Marcellus Shale wells in Morgantown, WV at the Marcellus Shale Energy and Environment Laboratory (MSEEL) were collected, compiled, and analyzed. The collected shale petrophysical properties included laboratory measurements that provided the impact of stress on core plug permeability and porosity. The petrophysical data were analyzed to estimate the fissure closure stress. The hydraulic fracture properties (half-length and conductivity) were estimated by analyzing the completion data with the aid of a commercial P3D fracture model. In addition, the information from the published studies on Marcellus Shale cores plugs were utilized to determine the impact of stress on the propped fracture conductivity and fissure permeability. The results of the data collection and analysis were utilized to generate a base reservoir model. Various gas storage mechanisms inherent in shales, i.e., free gas (matrix and fissure porosity), and adsorbed gas were incorporated in the model. Furthermore, the geomechanical effects for matrix permeability, fissure permeability, and hydraulic fracture conductivity were included in the model. A commercial reservoir simulator was then employed to predict the gas production for a horizontal well with multi-stage fracture stimulation using the base model. The production data from two horizontal wells (MIP-4H and MIP-6H), that were drilled in 2011 at the site, were utilized for comparison with the model predictions. The model was then also used to perform a number of parametric studies to investigate the impact of the geomechanical factors and non-uniform formation properties on hydraulic fractures and the gas recovery. The matrix permeability geomechanical effect was determined by an innovative method using the core plug analysis results. The results of the modeling study revealed that the fracture stage contribution has a more significant impact on gas recovery than the fracture half-length. Furthermore, the predicted production by the model was significantly higher than the observed field production when the geomechanical effects were excluded from the model. The inclusion of the geomechanical factors, even though it reduced the differences between the predictions and field results to a large degree, was sufficient to obtain an agreement with field data. This lead to the conclusion that various fracture stages do not have the same contribution to the total production. Based on well trajectory, variation in instantaneous shut-in pressure ISIP along the horizontal length, shale lithofacies variation and natural fracture (fissure) in the reservoir, it is possible to estimate the contribution of different stages to the production for both wells MIP-4H and MIP-6H.

Throughout fracturing treatment, millions of gallons of water are injected, but commonly less than 50% is recovered after stimulation. This study was constructed to evaluate the impact of the fracturing additives on the fluid flowback and fluid loss during hydraulic fracturing. Different pad fluids types were considered including; friction reducer fluid, friction reducer with a non-ionic surfactant fluid and 3 wt% HCl acid. Flooding experiments were conducted for core samples from the Eagle Ford outcrop to measure the brine permeability, time of breakthrough and water relative permeability. The measurements were performed for intact samples and also after flooding the samples with the fracturing fluids. A simulation sector modeling for a hydraulically fractured vertical well in the shale formation was constructed to investigate the effect of the fracturing additives on the fluid flowback and fluid loss during hydraulic fracturing. A sensitivity analysis was considered to study the effect of the formation capillary pressure and reservoir pressure on the fluid flowback and fluid loss due to counter-current capillary imbibition. The study results showed that the fluid saturation in the near fracture face shale matrix is highly reduced by the effect of the high capillary pressure. Therefore, the fluid had not flow back from the near fracture face matrix. Moreover, adding a non-ionic surfactant to the friction reducer pad fluid or using 3 wt% HCl increased the fluid loss during pumping and the fluid imbibition during shut-in, flowback, and production. Therefore, the dilute HCl acid and small well shut-in times are recommended when no flowback occurs from the near fracture face matrix due to low fluid saturation. The fluid loss from the near fracture face region due to counter-current capillary imbibition reduced the effect of the fluid saturation on the gas production. However, the high fluid saturation and the polymer adsorption may cause water blocks. Thus, reducing the gas production or leading to a complete gas block. For shales with moderate capillary pressure, a flowback from the near fracture face matrix has occurred. Hence, the friction reducer with a non-ionic surfactant fluid and 3 wt% HCl enhanced both of the fluid loss due to counter-current capillary imbibition and the fluid flowback. However, a non-ionic surfactant and long shut-in time are recommended for the hydraulic fracturing. Shales with low reservoir pressure had less fluid flowback and more fluid loss. To minimize the fluid loss during pumping and to overcome the water block problem, it is recommended to use a friction reducer fluid in the pad stage while injecting a non-ionic surfactant or dilute acid during the subsequent fracturing steps.