Acid fracturing can be potentially used in calcareous shale/mudstone reservoirs to stimulate the unpropped fractures. The unpropped fractures are created in large amount during hydraulic fracturing and provide considerable productivity, which, however, fails to sustain in the production stage. To understand how acid fracturing affects the fracture performance in laboratory is a critical step before field trial and can provide valuable guidance for fracture design. In this paper, we benchmarked the performance of acid-treated to brine-treated unpropped fracture using a "half-core" approach. The half cores to compare split from one shale core had very close mineralogy, they were treated with brine or acid independently and then form a composite core with a stainless steel half for conductivity measurement. This approach minimized the effect of mineralogy anisotropy in shale and cyclic stress that involved in traditional methods and enabled more meaningful comparison. Preserved Eagle Ford shale categorized into low, medium and high carbonate content were used; uniform and non-uniform flow patterns were compared in the treatment. Fracture conductivities and their response after cyclic stress, etched surface profiles and mechanical properties were systematically investigated. With uniform flow, acid resulted in lower fracture conductivity and restored conductivity after cyclic stress than brine. Both conductivities further decreased with carbonate content. On the contrary, non-uniform flow led to a higher acid-treated than brine-treated conductivity. The difference reached two orders of magnitude at reservoir pressure in sample with high carbonate content. The restored conductivities after acid treatment were higher than or close to that after brine treatment. Non-uniform etching was shown critical in a successful stimulation of unpropped fractures, and it could be achieved by viscous fingering or presence of carbonate veins. Most samples after acid etching developed isolated pits with depth within 50 µm on surface, channels were only observed for the sample with carbonate content etched with non-uniform flow and the one with calcite vein. Acid treatment reduced hardness in all samples, and the reduction tended to increase with the original carbonate content in samples. Mineralogy impacted the unpropped fracture conductivity, even in the cases of brine treatment, where no chemical reaction happened. We experimentally demonstrate the feasibility of acid fracturing in shale and provide insight to shale candidate selection for acid fracturing.

The publicly available multi-terabyte dataset of the Marcellus Shale Energy and Environmental Lab (MSEEL) consortium provides a unique opportunity to develop fracture models and analyze the effectiveness of the stimulation of a reservoir on a consistent base. Sonic, microresistivity image and production logs, microseismic data, and raw fiber optic measurements are examples of such data. Abundant core samples supplied demonstrate reservoir complexity and high density of natural fractures. The planar fracture model allows us to compare and contrast multiple stimulation strategies and propose engineered completions that cannot be done solely by data-driven approaches. Conclusions about stage spacing, stimulation design, wellbore placement, and stage isolation are shared. The workflow will be detailed to allow others to use, verify, and critique our findings using the same initial data. Introduction The wells chosen for this study are part of the Marcellus Shale Energy and Environmental Laboratory (MSEEL) a joint project between the Department of Energy's National Energy Technology Laboratory (NETL) and its partners, West Virginia University (WVU) and Northeast Natural Energy (NNE), to develop and test completion technologies (DOE Award No.: DE-FE0024297). The objective of the MSEEL is to provide a long-term collaborative field site to develop and validate new technologies to improve future wells economics, recovery efficiency, and minimize the environmental concerns of unconventional gas production (Carr et al. 2019). At the time of this writing, the MSEEL has conducted three phases. The first two consisted of a multi-well pad development instrumented with advanced measurement tools. A multi-terabyte dataset produced from both pads is made public to allow for better collaboration among engineers and scientists across disciplines and to validate learnings (Carr 2020). Project Background and Setup As previously mentioned, the MSEEL contains two pads drilled and completed at different times. The first pad named MIP after Morgantown Industrial Park will be the focus of this study. The nearby Boggess pad is producing since 2019 and has limited publicly available data for a comprehensive analysis. A full release of Boggess data is scheduled for the end of the year 2020, opening a door for future research.

The study focuses on the MIP and Boggess pads of the MSEEL (Marcellus Shale Energy and Environmental Laboratory), a public-private partnership with a mandate to publicly release data for scientists and engineers to engage with. Multiple diagnostic tools are used to characterize the formation and monitor fracture treatment and propagation. Geomechanical modeling is used to understand the in-situ stresses, microseismic to describe half-lengths and heights, and fiber optics to characterize offset well Fracture Driven Interactions (FDI's) and interstage communication. Recent publications covering the MSEEL MIP-3H and MIP-5H wells are reviewed and discussed. A preview of the findings from the Boggess pad (first production in November 2019) is also shared here. Introduction The Marcellus Shale Energy and Environmental Laboratory (MSEEL) is a joint project between the Department of Energy’s National Energy Technology Laboratory (NETL) and its partners, West Virginia University (WVU), and Northeast Natural Energy LLC (NNE), to develop and test completion technologies (DOE Award No.: DE-FE0024297). The objective of the MSEEL is to provide a long-term collaborative field site to develop and validate new knowledge and technology to improve recovery efficiency and minimize the environmental implications of unconventional resource development (Taylor 2019). At the time of this writing, the MSEEL has conducted three phases, two of which consisted of a multi-well pad instrumented with advanced diagnostics. Multi-terabyte datasets were produced from both pads and are made public to allow for better collaboration among engineers and scientists across disciplines and to validate crucial conclusions (Carr 2020). Project Background and Setup The analysis will focus on both MSEEL pads, the MIP pad (Phase 2) and the Boggess pad (Phase 3), with an initial emphasis on the older MIP pad. Both have multiple fracture stimulated horizontal wells all targeting the Marcellus shale. Figure 1 shows a map view of both pads. The MIP pad has four wells that were drilled and completed in pairs as noted in Figure 2. MIP-3H and MIP-5H wells have a spacing of approximately 1,700 ft.

Abstract It has often been reported that the peak production of a well drilled in tight formations is highly dependent on the fracture contact area. However, there is no efficient approach to estimate the fracture surface area at present. In this paper, we propose a method to calculate the fracture surface area based on the falloff data after each stage of the main hydraulic fracture treatment. The created hydraulic fracture closes freely before its surfaces hit on the proppant pack, and this process can be recognized on the pressure falloff data and its diagnostic plots. The pressure decline rate during fracture closure is mainly caused by fluid leakoff from the fracture system into the formation matrix. For a horizontal well drilled in the same formation, we may assume the same leakoff coefficient among all stages, so the total fracture surface area can be calculated for all stages to meet the requirement of the fluid leakoff rate. Wellbore storage effect, friction dissipation and tip extension dominate the early pressure falloff data. While the transient dominated by friction losses typically lasts about one minute, tip extension may end after about 15 minutes. Therefore, falloff data should be acquired for at least 30 minutes to observe a fracture closure trend. The fracture closure behavior can be identified on the G-function plot as an extrapolated straight line or on the Bourdet derivative in log-log plot as a late time unit slope. The behavior of the late unit slope depends on the pressure decline rate, or correspondingly, to the fluid leakoff rate. Therefore, the total fracture surface area can be estimated using hydraulic fracture design input values for formation leakoff coefficient and fracture closure stress. The calculated fracture surface area represents the combined area of primary and secondary fractures, effectively all fracture surfaces contributing to the fluid leakoff. We applied the approach to all stages in a horizontal well that exhibit the fracture closure behavior. The approach shows promise as a straightforward way to estimate fracture surface areas that could, enable, in turn, an early estimate for the expected well performance.

Abstract In this study, a state-of-the-art seismic driven 3D geological model was built and calibrated to a petrophysical and geomechanical analysis, 1D-MEM (Mechanical Earth Model), on chosen wells within the Arkoma Basin of Oklahoma. The well information utilized in this study included basic wireline logs and core analysis, including XRD (X-Ray diffraction) data. The traditional petrophysical analysis was augmented with advanced rock physics and statistical techniques to generate the necessary logs. Hydrostatic, overburden and pore pressures were calculated with a petrophysical evaluation model. The 1D-MEMs were based on the Eaton/Olson/Blanton approach with the HTI (Horizontal Transverse Anisotropy) assumption. The 1D-MEMs were calibrated to laboratory data (triaxial tests) and field observations (mud logs, wellbore failure, frac pressures). Therefore, a very good confidence was achieved on Biot's coefficient, tectonic components, anisotropy and dynamic to static conversion factors for Young's Modulus and Poisson's Ratio. Seismic inversions were performed in different time windows and merged to generate high resolution P- and S-Impedance attributes from surface down to the target interval after careful AVO compliant gather preconditioning. A density volume estimate was calibrated to well data, accounting for different geological formations, to decouple P- and S-Wave components as a 3D volume, as well as dynamic Young's modulus (E) and Poisson's ratio (PR). Dynamic E and PR were converted to static parameters using results from 1D-MEMs; and 3D models of Biot's coefficient (α) and tectonic components were built to compute 3D fracture pressure volumes calibrated to well data. The final products were seismic-driven 3D pore pressure and fracture pressure calibrated to 1D-MEMs. The correlation between measured/estimated well logs and corresponding seismic-derived pseudo logs was more than 80%, which indicates good quality of seismic inversion results and hence 3D-MEM. Also, stress barriers, anisotropy, and brittleness indices were calculated on well scale which would help to identify best zones to place hydraulic fractures. The 3D geological model will aid in identifying sweet-spots and optimizing hydraulic fractures.

Abstract Diagnostic Fracture Injection Tests (DFIT) help to estimate various formation and fracture parameters such as closure stress, reservoir permeability, pore pressure, fracture compliance/stiffness and conductivity of un-propped fractures. All of the above require a precise depiction of the fracture closure process for accurate estimation of the various parameters. The fracture closure process is a strong function of the reservoir parameters such as stress, pressure, and permeability. Heterogeneity of these parameters in the reservoir and the nonlinear behavior of fracture closure with respect to fracture width further complicate the analysis of the observed pressure trends recorded during a DFIT. In this work, we discuss the application of a 3-D implicitly integrated poroelastic fracture-reservoir-wellbore model to simulate DFITs. The model is validated by simulating a DFIT for a homogeneous formation for which semi-analytical solutions are available. The surface pressure is implicitly calculated by the integrated model during closure of the fracture. The simulated closure pressure response is analyzed, and the results are compared with specified simulation inputs. Various models are used for interpreting the simulated DFIT response to identify the differences between the interpretation methods and validate the numerical simulation. The numerical model is then used to simulate pressure depletion in a typical unconventional reservoir by a horizontal well with multiple fractures. Our poroelastic model predicts the stress variation in the reservoir induced by depletion. DFIT simulations are then performed in a child well in this asymmetrically depleted environment at various distances from the depleted well. The pressure in the closing fracture is then analyzed to understand the effect of depletion, fracture asymmetry and production duration on the DFIT response. This work for the first time presents the expected DFIT response in a depleted reservoir (with a non-uniform stress and pore pressure distribution) and the best practices for analyzing such data. Such an analysis cannot be performed by any existing analytical methods and requires poroelastic numerical simulations. The impact of key depletion parameters on DFIT interpretation is explored for the first time. The results from this work can be directly applied to interpret DFIT data acquired in child wells to accurately determine reservoir closure stress, pore pressure, reservoir permeability, fracture compliance and fracture conductivity.

Abstract The diagnostic fracture injection test (DFIT) is a reliable technique to evaluate formation and get essential parameters for the hydraulic fracture designs. Among these parameters, hydraulic fracture closure stress might be the most important factor, followed by reservoir permeability and pressure. Several methods to pick Fracture Closure Stress(FCS) are published in last few years, such as the holistic method and the variable fracture compliance method, but they are inconsistent in identification of the final FCS because of distinct assumptions of closure mechanism. In this paper, a field case, designed with two successive injections in one single formation through the same horizontal well, is used to see if the different methods can pick consistent closure stress from multiple injections. Two successive injections are recorded in the same formation and same well. The first injection was a small volume DFIT, pumped at a low rate. After shut-in, pressure falloff was recorded for a relatively long time. Then, a much larger volume was injected in the second injection (breakdown/ step-rate injection) at a higher rate, which is to create a larger hydraulic fracture. The second falloff was then recorded after the shut-in, and compared with the first one to pick a consistent fracture closure. Due to small volume and low rate of the first injection, the first falloff presents fairly normal leakoff with little abnormal leakoff behavior. Besides, small fracture size and long monitoring time enable fast fracture closure, afterclosure pseudo-linear flow and even pseudo-radial flow, which was rarely observed in the tight formation. While, because of much larger injection volume and higher rate in the second injection, the second falloff shows much more complicated behaviors potentially including tip extension, pressure dependent leakoff (PDL), and transverse storage or height recession. The final fracture closure pressure picked with holistic method is proved to be identical to that picked from the first falloff, while the closure picked with variable fracture compliance method is not consistent with and larger than that from first falloff. The case with two successive injections is very informative and could be used as benchmark for comparing different methods of pressure decline analysis. The paper provides a field case in a tight gas sand formation to support that the final fracture closure can be consistently picked with the holistic method instead of the variable fracture compliance method in conventional tight gas reservoirs.

Abstract The productivity from hydraulically fractured wells is contingent to different mechanisms of formation damage by the fracturing fluid, such as fluid leakoff, proppant embedment, and fines generation from proppant crushing. Particle plugging during fluid invasion in hydraulic fracturing is considered to have a significant detrimental effect on production. In this work, we developed a multi-physics pore-scale plugging simulator integrated with a fracture simulator to investigate the impact of particle plugging and quantify the formation damage of the invaded region near hydraulic fractures. Our multi-physics simulator bridges pore-scale phenomena with those occurring at the reservoir scale. The pore-scale particle-plugging simulator uses 3-D pore-network models based on pore-body and pore-throat characteristics derived from petrophysical measurements. Based on filtration theory we compute transport and retention of particles, and permeability changes due to fracturing-fluid invasion. These parameters are interfaced with a fracture simulator that provides pressure, leak-off rate, proppant size and concentration to the pore-network model. These parameters are representative of typical multi-stage hydraulic-fracturing operations. The fracture simulator also provides fracture-geometry and fracture-conductivity. Our methodology enables a novel and practical way to understand the particle-plugging process in the matrix-fracture interface during hydraulic-fracturing operations. The coupled model considers heterogeneity at pore scale to account for the role of pore structure on particle transport, concurrently studying its behavior on the fracture. We used petrophysical measurements and well log data obtained from Wolfcamp shales in this study. From the sensitivity analysis performed for different hydraulic-fracturing operational constraints and fluid properties like proppant size and concentration, we are able to determine the effect of these variables on matrix-fracture permeability impairment at the pore-scale. The multi-scale integration allowed us to quantify the influence of filtration on the fracturing operations. Introduction Advancements in horizontal drilling and hydraulic fracturing technologies enabled hydrocarbon exploitation from unconventional reservoirs like shale formations viable and economical. However, these formations without any stimulation, have insufficient permeability to allow fluid flow to the wellbore for commercial production. During a hydraulic fracturing operation, fractures are created by pumping large quantities of fluids at high pressures, to provide enhanced permeability by increasing the contact area between the well and the reservoir. The key for successful operations is to design treatments that maximize the conductivity of the created fractures and reduce the detrimental effect on the formation.

Abstract Fracture conductivity in shale formations can be significantly impaired due to water-rock interactions. The mechanisms of water damage to fracture conductivity include clay swelling, surface softening, excessive proppant embedment, and fines migration due to fracture surface spalling and failed proppant particles. Fracture conductivity is influenced by many factors, however the formation's mechanical properties and mineralogy, or more specifically the clay content and clay type, can have the most significant effects on the resulting fracture conductivity when the fracture surfaces are exposed to water. This paper presents a comparative study on the effects of clay content on fracture conductivity impairment of the Eagle Ford shale and the Marcellus shale formations. Laboratory experiments were conducted to investigate the effect of flowback water on fracture conductivity for Eagle Ford shale and the Marcellus shale samples. The majority of the Eagle Ford test samples were obtained from an outcrop located in Antonio Creek, Terrell County, Texas; while the remaining samples were obtained from downhole core provided by an industry partner. Samples of the Marcellus shale consisted of outcrop samples collected from Elimsport Quarry as well as a site in Allenwood, Pennsylvania. Saline water with a similar chemical composition to the typical field flowback water was utilized. Fracture conductivity measurements were conducted in three stages. In the first stage, dry nitrogen was flowed to ascertain the undamaged initial fracture conductivity. In the second stage, the saline solution was injected into the fracture until steady state behavior was observed. In the third stage, dry nitrogen was once again flowed to quantify the recovered fracture conductivity. Reported mechanical properties from the same outcrop rock samples, consisting of Poisson's ratio and the Brinell hardness number, were considered in this study. Additionally, reported mineralogy obtained using X-ray powder diffraction (XRD) microscopy was taken into consideration. The elemental composition along the fracture surface was obtained using X-ray fluorescence (XRF) microscopy, and fracture surface topography was obtained using a laser surface scanner and profilometer.

Abstract The proper design and execution of a drawdown schedule for hydraulically fractured wells in overpressured, tight reservoirs is an important step to maintain well productivity and protect against fracture damage. To accurately design a drawdown plan requires knowledge of how stresses will evolve in the subsurface. Calculating dynamic stress changes during reservoir depletion, however, typically requires coupled-geomechanics simulators which are very specialized and time-consuming tools. In this work, we develop a methodology using analytical models to quickly estimate reservoir stress changes and predict effective stress on the fracture network in real-time. In tight reservoirs, the drawdown management procedure has a direct link to flowing bottomhole pressure and the resulting stress on the proppant pack. To estimate the effective stress on the hydraulic fractures over time, a series of coupled-geomechanical models were built using realistic formation properties. These geomechanical modeling results were then used to calibrate an analytical model based on poroelastic theory. The analytical model is able to accurately reproduce the coupled-geomechanical results across a wide range of depletion scenarios with a small margin of error. Once calibrated, the analytical model can be used to quickly estimate the stress on the fracture network during routine well surveillance. A case study will be shown demonstrating how the workflow led to field decisions in a high pressure unconventional reservoir in North America. After careful analysis of lab-measured fracture conductivity, the decision was made to decrease the production rate in order to keep the stress on the fracture network below a threshold value where reduced fracture conductivity was observed. The well with this managed drawdown schedule has maintained well productivity and has not flowed damaged proppant fines to surface in contrast to observations from other wells in the field. This workflow has improved the asset team's ability to predict, identify, and mitigate fracture damage on unconventional horizontal wells, thereby avoiding the loss of estimated ultimate recovery (EUR) and enhancing project economics.

Abstract Fracture conductivities have been extensively studied in laboratory to assess the impact of different fracturing fluids. However, if downhole shale samples are used, the comparison can be compromised or even biased due to significant sample variations caused by shale heterogeneity. The heterogeneity often leads to quite different mineralogy and mechanical properties among shale samples, even for those harvested from the same reservoir whole core. The variations in these properties have a strong impact on fracture conductivity, and create difficulties in evaluating and comparing different fracturing fluids. In this work, the "half-core" approach is developed to obtain shale samples with almost identical properties to improve the evaluation on fracturing fluids. In this approach, shale cores are split into two half cores, which are then subjected to different fluids independently. 16 preserved shales from Barnett, Eagle Ford, Haynesville and Utica spanning a wide range of mineralogy were used to investigate the effectiveness of the approach. Mineralogy and mechanical properties on the half-core surfaces were compared. Measured and simulated fracture conductivities between paired half cores were also examined. The half cores demonstrated similar mineralogy and mechanical properties. Among all the 16 selected shales, their paired half cores showed an average difference of 3.22 ± 1.90 % in mineralogy and of 6.89 ± 8.45 % in hardness. The differences were substantially reduced compared to the shale samples from a vertical well in the Utica Basin and those from a horizontal well in the Midland Basin, whose average mineralogical differences range from 30% to 40 %. Similar fracture conductivities were also found between the half cores subjected to a series of closure stress: difference in the measured fracture conductivities between half cores from an Eagle Ford shale varied from 1.1% to 10.7%; while the simulated conductivities between the 16 pairs of half cores presented an average difference of 15.3% ± 18.9%. The differences in both of the measured and simulated fracture conductivities between half cores were lower than the conductivity difference among shales when the traditional approach is used. The half-core approach is experimentally proved to be effective in creating a baseline with reduced sample variation among shales to improve evaluation of fracturing fluids. The approach is applicable in both propped and unpropped fractures.

Summary The superb operational efficiencies that the industry has achieved when completing horizontal wells has allowed low permeability reservoir development to continue, even in a low commodity price environment. One casualty of this is the diagnostics of injection and decline pressures to determine characteristics of the created fracture system. Other than intermittent injections into the first frac stage, little pressure data is acquired during completions. Shut-ins early in the treatment are no longer common and can be difficult to interpret when near-well pressure losses are high, and when using brines with poorly known pipe friction profiles. Even post-frac pressure declines are limited to just a few minutes as frac plug and perforation gun pump down operations quickly commence. One dataset that is always available but rarely utilized is the pressure response during the pump down sequence between frac stages. The presence of proppant in the lateral or the quality of the communication between the near-well fracture and the wellbore can also be assessed. In microdarcy to millidarcy reservoirs it is possible to bound fracture closure pressure, determine Net Pressure and approximate fracturing fluid efficiency. This fluid efficiency can afford information on the degree of interconnection of the stimulation treatment with proximate fracture systems. This process is made more rigorous when integrating diagnostic injections with extended shut-ins. This paper proposes a diagnostic technique that examines the pressure response of the pump down sequence and compares it to data acquired during the fracturing treatment. The integration of this data, along with pre-stimulation injection tests, can provide an estimation of closure pressure, the generated Net Pressure, fracturing fluid efficiency, total leakoff coefficient, a notion of the stress increase associated with closely spaced fractures, and an indication of communication with other stimulation treatments. This paper incorporates examples from the 2nd Bone Springs Sand to demonstrate the practical application of this workflow. Two pump down examples from an organic shale are included to show the pressure response when sand remains in the lateral and when pumping is into an open fracture.

Selecting the right proppant for hydraulic fracturing combines an economic evaluation of well performance which then quantifies performance materials under appropriate application conditions. Since proppant experiences variable reservoir closure stress over the life of a hydraulically fractured well, mechanical integrity and quality are key factors dominating proppant performance and therefore production performance. However, proppant selection criteria and day to day proppant quality control analysis presently involves laboratory testing that only partially simulates fracture application conditions as the vast shale market dominates the hydraulic fracturing market today. This analysis expresses proppant performance in terms such as crush resistance which may seem ambiguous to field personnel as there is no straightforward correlation to an actual well performance metric. Here the presented work compares laboratory measured proppant performance to well performance in the Williston basin for different proppant types in order to establish such correlation. An investigation of the performance of a group of horizontal wells located in the Williston basin compares the normalized production performance of both ceramic proppants and white sand. The production analysis performed using rate transient analysis software compares retained fracture half lengths, cumulative oil production and oil production rate associated with these wells. This study then compares laboratory measured performance of ceramic proppant to white sand, under closure stress conditions comparable to those seen in the Williston basin. Initial proppant mechanical performance is measured using the API specified procedure. Then, using the same apparatus, mechanical degradation rate is measured as a function of stress application time. Finally, the production for the normalized oil production is then correlated to the laboratory measured mechanical degradation rate of both ceramic proppant and white sand to ascertain the time projected to achieve ceramic proppant return on investment.

Fracture potential of challenging rocks determines the ability of rock to create complex, extensive and highly connected fracture networks that remain open during production. Prediction of a robust fracture potential is a prerequisite for optimized stimulation design and maximized conductive reservoir volume. However, fracture potential is not a material property. Contrary to common belief, fracability, brittleness are not characteristic properties but rather a rate and stress dependent material behavior for a given rock type. During hydraulic fracture operations and/or production, not all stages respond the same. Certain stages along a wellbore respond to fracturing operations better and exhibit increased fracturing potential. Current industry practice involves using logs to perform quick look analysis along wellbores to unlock this potential, and usually results in a general fracability or brittleness indicator. Stage locations, number and size selection are based on parameters that are not appropriately integrated and correlated to the fracturing potential. In order to fully characterize the fracture behavior and optimize stimulation design, key attributes that control fracture initiation, propagation, opening and closure need to be identified, their relative impact/weight(s) need to be quantified and integrated. Attributes can include a combination of elastic properties, unconfined compressive strength (UCS), anisotropy, cohesion, friction angle (FA), fracture toughness, stress, mechanical/stress anisotropy, natural fracture reactivation and petrophysical properties such as hydrocarbon potential, permeability, porosity, and characterization of lithology. In this paper, a new approach is introduced to evaluate fracture potential and optimize hydraulic fracture stage design. This approach serves as an uplift to standard fracability predictions and provides proxies for near wellbore fracture initiation and closure characteristics. In addition, the proposed workflow provides a fully automated stage design algorithm that can run on multiple parameter combinations and available data according to the nature and evolution of the reservoirs' environment. The automated procedure employs an optimization approach, which mathematically formalizes the notion of stage design by seeking to minimize the total intra-stage variability of fracturing potential subject to any desired operational constraints. The integrated and automated workflow for selecting and designing stages is quick, efficient, repeatable and flexible. The workflow is described in detail and application of stage design algorithm is demonstrated using a field data set.

Introduction The challenges of development, in a play such as the Bakken formation, include managing vast amounts of data coming in on a daily basis and using the data to make timely, intelligent decisions. Geomodels organize, track, and incorporate large amounts of data into a single environment; managing data from a single environment leads to making more informed decisions about well spacing, perforation locations, and target interval selection. The data stream of wells in unconventional plays usually includes well log data, mud logging information, geosteering data and core information. Straightforward geomodeling workflows are able to incorporate this information with existing data such as seismic data, geological interpretations and petrophysical, geomechanical, or facies models. As new data is added to the environment, rapid model updates can be performed to ensure that the models are up to date and useful. Futhermore, geomodeling efforts foster collaboration and synergy amongst the subsurface disciplines and has benefitted Hess Corporation's Bakken asset by creating a better regional and sub-regional understanding of the basin by consolidating available technical information. Finally, the geomodeling work has created a more complete understanding of the geosteering results, fluid distributions, completion and reservoir simulations, and ultimately has given us a better understanding of productivity in the basin.

Abstract While production from shale formation has been made possible mainly by advances in horizontal drilling and hydraulic fracturing, there are still many challenges in production from these reserves. While slick water fracturing technique stimulates a large reservoir volume through generation of complex fracture systems, very sharp production decline has been observed in many reservoirs. One of the main reason for this rapid decline is the limited contribution to flow from smaller fracture networks generated, which do not received much proppant. These proppant-less artificial and natural fractures heal up once the net pressure in the fracture goes below the closure stress and hence reduce the producible region only to the primary fractures. To make the production from the shale plays sustainable over the life of a well, there is a need to make sure that the network of natural fractures, secondary, and tertiary artificial fractures are conductive and remain productive even after increase in closure stress. While generation of massive fracture system will not be possible without low viscosity slick water, proppant placement will be limited only to the primary fractures with this technique. In order to overcome this challenge of low conductivity fracture network, we tested a technique of combining reactive fluid with slick water fracturing.