The natural gas in the Marcellus Shale is produced most efficiently through horizontal wells through multi-stage hydraulic fracturing stimulation treatment. Even though advances in technology have unlocked considerable reserves of hydrocarbon, the long-term production behavior of the horizontal well with multiple hydraulic fractures is not well understood. Therefore, it is essential to study and evaluate the impact of the different treatment parameters and formation properties on fracture properties and production performance. The objective of this study is to investigate the impact of the stress shadowing, stage sequencing, and the mechanical properties on gas production from multi-stage hydraulic fractured horizontal well completed in Marcellus Shale. A commercial hydraulic fracturing software was employed to predict the fracture properties for a multi-stage hydraulic fractured horizontal well in Marcellus Shale. The available information included gamma ray, density, resistivity, and sonic logs as well as the fracture treatment data. Minimum horizontal stress, instantaneous shut-in pressure (ISIP), process zone stress (PZS), and leak off mechanism were obtained from a Diagnostic Fracture Injection Test (DFIT). The predicted treating pressures by the model were matched to field data by adjusting the pipe friction and the number of perforations. The predicted hydraulic fracture properties were then incorporated in a reservoir model (simulator) to predict the gas production. The impact of stress shadowing, treatment size, fracturing sequencing, and formation mechanical properties on fractures properties (fracture half-length and conductivity) and gas production were then investigated. Stress shadowing was found to impact fracture properties especially, the fracture width. This in turn, resulted in lower gas recovery. The impact of the stress shadowing increases as the treatment size increases and stage spacing decreases. It must be noted that as the treatment size increases and the stage spacing decreases (more stages), the gas recovery will increase due to larger stimulated volume. At the same time, the stress shadowing would have more negative impact on the gas recovery. Additionally, the results indicated that the reduction in fracture width, and as a consequence the reduction in gas recovery, is more significant in sequential fracturing as compared to simultaneous fracturing.

In modern logging practices, the Poisson ratio and the Young Modulus as measures of rock Brittleness may be estimated from the dipole sonic and bulk density logs. This is important when subterranean formations are considered for fracturing or when unintended fracturing can be a concern under high injection gradients in fluid injection processes. For most oilfields, the bulk of well log suites run in the past has been limited to basic lithology logs and occasionally some porosity logs. In particular, the sheer sonic velocity log, an important component for estimation of geomechanical properties, has not been a standard measurement on common log suits. In this paper, we present the result of a study where shear travel time is correlated with measurements from caliper and shale content. The training set we used consisted of well logs for wells that included the shear travel time. We experimented with various approaches and developed a process for in cooperating DNN (deep neural network) to correlate the shear log data to other measurements.

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.

One of the critical issues that might happen in some oil and gas wells is the failure of the cement sheaths and its debonding from the casing string. Cement shrinkage during setting is regarded as one of the main causes behind formation of microannulus cracks. In this paper, a new class of polymer-based expandable additives is presented in the form of fibers to address shrinkage and debonding issues in the subsurface. The proposed fiber additives are made from shape memory polymers. These fibers expand upon exposure to temperatures above certain limits; which is selected to be below the temperature of the cementing zone. In this situation, the expansion occurs before the cement setting but after its placement. If the expansion occurs after cement setting, it may lead to microfractures. As a result of the controlled expansion of the cement paste, the creation of channels and fluid migration can be minimized while maintaining the mechanical properties required for cement integrity. Considering the inert property of the proposed additive, the cement water ratio and its chemical properties do not change. The cement expansion, fluid loss, gel strength, compressive strength, and tensile strength of the samples containing these fibers are examined by destructive and non-destructive methods and presented here. The proposed class of expandable additives can help the operators reach sustainable well integrity by improving the bonding between the cement and casing.

During the hydraulic fracturing process, the rough surface of fractures and the viscous proppant suspension flow bring great challenges to the distribution of proppants evenly at the fracture thin apertures. As a result, a detailed understanding of the effect of surface roughness on proppant sedimentation seems essentially indispensable. Apart from that, how the roughness of Nano-scale conduits and their orientations, such as microfracture channels, affect the flow through the damaged fracture process zone (FPZ) have not been well understood. A newfangled developed algorithm using image analysis software (ImageJ) is applied to characterize the morphological features of the damaged fracture system, including surface roughness, microcrack types and microcrack density indicators. Hydraulic fracturing experiment is conducted on a Tennessee sandstone core using a triaxial loading system. The fractured samples are ion milled, and its cross section plane images are recorded by scanning electron microscope (SEM). Statistical analysis of surface roughness, the degree of damage at FPZ, the density of microcracks and effective connection indicator of microfractures to the main fracture are quantitatively investigated, in addition to Young's modulus and Poisson's ratio. We found that the higher roughness of microfracture network significantly enhances the effective conduits open to fluid flow while taking the density of the microfracture within FPZ into account within the fracture processed region, depending upon how much damage is presented. In other words, the overall ease of fluid delivery to the main fracture essentially depends on the level of the damage in FPZ. The heavily deformed rock grains cause a partial blockage at the fracture surface and will be detached on the main fracture. The leftover is the induced intercrystalline microfracture network in the vicinity of the main fracture. Additionally, mechanical moduli were interpreted by image analysis, where a novel approach was developed to calculate the mechanical rock properties. The results from image analysis were compared to other failure criteria and fracturing pressure data interpretation. We also validated the obtained mechanical properties by collating the literature records. The microfracture network creates the significant incremental amount of fluid conduits to hydrocarbons. The better understanding of the fracture network serves as a valuable guide to the fracturing job design and managing the damaged FPZ. This novel approach will commit to supporting the lab measurements, gives field preliminary mechanical property assessment and lower the cost needed for hydraulic fracturing design.

Drilling problems such as stick slip vibration/hole cleaning, pipe failures, loss of circulation, BHA whirl, stuck pipe incidents, excessive torque and drag, low ROP, bit wear, formation damage and borehole instability, and the drilling of highly tortuous wells have only been tackled using physics-based models. Despite the mammoth generation of real-time metadata, there is a tremendous gap between statistical based models and empirical, mathematical, and physical-based models. Data mining techniques have made prominent contributions across a broad spectrum of industries. Its value is widely appreciated in a variety of applications, but its potential has not been fully tapped in the oil and gas industry. This paper presents a review compiling several years of Data Analytics applications in the drilling operations. This review discusses the benefits, deficiencies of the present practices, challenges, and novel applications under development to overcome industry deficiencies. This study encompasses a comprehensive compilation of data mining algorithms and industry applications from a predictive analytics standpoint using supervised and unsupervised advanced analytics algorithms to identify hidden patterns and help mitigate drilling challenges. Traditional data preparation and analysis methods are not sufficiently capable of rapid information extraction and clear visualization of big complicated data sets. Due to the petroleum industry's unfulfilled demand, Machine Learning (ML)-assisted industry workflow in the fields of drilling optimization and real time parameter analysis and mitigation is presented. This paper summarizes data analytics case studies, workflows, and lessons learnt that would allow field personnel, engineers, and management to quickly interpret trends, detect failure patterns in operations, diagnose problems, and execute remedial actions to monitor and safeguard operations. The presence of such a comprehensive workflow can minimize tool failure, save millions in replacement costs and maintenance, NPV, lost production, minimize industry bias, and drive intelligent business decisions. This study will identify areas of improvement and opportunities to mitigate malpractices. Data exploitation via the proposed platform is based on well-established ML and data mining algorithms in computer sciences and statistical literature. This approach enables safe operations and handling of extremely large data bases, hence, facilitating tough decision-making processes.

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.

Recently, the United States (US) oil and gas industry has dramatically increased its production, primarily due to technological advances in horizontal drilling and hydraulic fracturing. Current hydraulic fracturing practices require a significant amount of water. Section 9.2.1 of the API Recommended Practice (2015) states that of development activities including drilling and completion activites, hydraulic fracturing, typically results in the most significant water use. For context, hydraulic fracturing operations in 2000 used approximately 177,000 gallons of water per oil and gas well. According to USGS, hydraulic fracturing requirements increased to over four million gallons of water per oil well and 5.1 million gallons of water per gas well in 2014 ( USGS, 2015 ). The Environmental Protection Agency's multiyear study found an increasing trend in water use per well attributed to growing numbers of wells drilled, with longer laterals and more stages completed ( Dunn-Norman, et al., 2018 ). Many US oil and gas companies’ annual reports and public communications currently feature sustainability and environmentally-responsible development strategies. However, opportunities to minimize negative environmental impact without affecting the value of a large-scale unconventional development is extremely difficult, particularly in the current low oil price market. Operators throughout the industry are developing water management facilities focused on safe, reliable and environmentally friendly water management practices. This paper discusses utilizing in-situ mechanical rock property data to optimize completion strategies, which can help reduce the negative impacts of hydraulic fracturing, while maintaining, and often increasing, production.

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.

Microseismic data and post-fracturing production have confirmed the positive role of fracture complexity on production enhancement in fractured wells. While operators are looking for different fluids and pumping schedules to enhance fracture complexity, the mechanisms ruling the process is not fully understood. This paper provides a comprehensive workflow to model the fracture pattern development by accounting for interactions with numerous natural fractures. We present a robust finite element model with adaptive insertion of three-dimensional cohesive elements for fracture propagation through the intact rock as well as the network of intersecting natural fractures. Cohesive elements are coupled with general Darcy's flow to incorporate fluid flow as well as elastic and plastic deformations of rock during initiation, propagation and closure of hydraulic fractures. Hydraulic fracturing treatment has been simulated for different natural fracture patterns. Fluid injection pressure fluctuations are observed while reopening natural fractures. The impact of operation schedules on network complexity such as hesitation time is investigated. The complexity of fracture network is characterized by the ratio of total fracture length to its effective radius from the wellbore. Our analysis has shown that in addition to the differential stress and the fracture intersection angle which are already determined by the nature, pumping injection rate and hesitation time can play a significant role in fracture branching and its diversion to different natural fracture sets. Higher injection rate is found to have a positive effect to overcome the resistance of natural fractures in different directions, and hesitation in the middle of pumping can force the fracture to divert into other directions, both of which help develop a more complex fracture pattern.

In the Appalachian Basin, the primary focus has shifted from exploratory wells to full pad development. Therefore, generational affects--the relationship between parent and child wells--are becoming a primary concern to operators that are fully developing their lease positions. This study examined bottomhole gauge data from a parent Marcellus Shale well that was recorded during the hydraulic fracture stimulation of three children wells in the Marcellus Shale and two children wells in the Burket Shale. The characteristics of the children wells created a robust data set due to variation in inter-well spacing, producing formation, completion design, and stimulation timing. Fracture modeling was performed in advance of the completion operations in order to mitigate possible parent-child communication. The parent well produced natural gas and condensate for nine months prior to being shut-in for the completion of the children wells. Rate transient analysis was performed on the parent well to further understand the depletion of the producing zone. Detailed bottomhole pressure and temperature data were measured in the parent well during the stimulation. Once operations were completed, the bottomhole gauge data was examined to identify frac hits to the parent well. The general magnitude and timing of the frac hits were examined in relation to the rock matrix and completion design parameters, and completion sequence. It was concluded that over 75 percent of Marcellus frac stages communicated with the parent well, with the most frac hits being attributed to the nearest child well. Logistic regression tests were performed on individual parameters to determine key influencers on the likelihood of a frac hit. Detailed bottomhole gauge data, as presented in this paper, is limited in the current literature due to the expense of data acquisition. The unique characteristics of the wells involved in this field experiment provide for robust statistical analysis that is not typically available publicly in the Appalachian Basin.

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.

Throughout multiple shale plays, high viscosity friction reducers (HVFRs) have successfully placed more proppant mass with lower treating fluid volume; thus, the industry is accelerating adoption of these treating fluids. Previous published studies have included treatments in Bakken shale and Permian Basin formations. The characteristics of the Marcellus shale make it particularly beneficial to minimize water and gel injection into the formation. At the same time, operational constraints related to smaller footprint and pad sizes in the Marcellus region make it beneficial to reduce gel hydration equipment on location. In spite of these potential benefits, application of high viscosity friction reducers has only recently begun in the Marcellus region. One factor delaying the introduction of HVFRs into the Northeast has been the challenging waters and brines often used in treatments. This study documents the successful introduction of a brine tolerant, high viscosity friction reducer with multiple operators in the Marcellus region. Marcellus operators compared several different friction reducer chemistries through field trials on multiple pads. Based on measurements of surface treating pressure and proppant placement, an optimum fluid system was selected that is effective in a range of water qualities and allow increased pump rate. The friction reducer was also compared to conventional gel technology based on the same method. The brine tolerant friction reducer was found to be an effective replacement for linear gel fluids and allowed reduction of equipment on location. A brine tolerant, high viscosity friction reducer enabled treatments to be placed with increased sand loadings, higher pump rates, and decreased surface treating pressures. The fluid system was able to work with a variety of water conditions, including brines having more than 30,000 ppm chlorides. In one case the new fluid system allowed operations to entirely move away from gel chemistry and surface hydration equipment. The study presents measured results during the frac on one of the first applications of a high viscosity friction reducer in Marcellus shale treatment.

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.

In the late summer of 2009 an American oil and gas producer teamed up with a Canadian pumping service company and performed a series of Liquified Petroleum Gas (LPG) fracturing treatments in Pennsylvania's Marcellus Shale. A total of four stages were pumped on three different vertical wells in three different counties Centre, Lycoming, and Indiana. Questions surrounding damage associated with pumping large volumes of fresh water in nano-to-micro Darcy shale along with environmental pressures about water supply and disposal led to consideration of an alternative, non-aqueous fracturing fluid. A hydraulic fracturing process utilizing 100% LPG as a fracturing fluid to carry proppant into shale or a coal seam or other water sensitive pay zone was developed. The new LPG fluid could be easily viscosified with oil gelling chemicals allowing for excellent proppant transport. LPG was an appealing choice of fracturing fluid because its phase behavior in the Marcellus Shale at bottomhole conditions would theoretically render it non-damaging. The fracturing process brought sand into the gelled LPG so that it could be pumped under high pressure and into created fracture geometry in a pay zone. With respect to well cleanup post-frac LPG held the promise of greater cleanup and improved effective fracture half-lengths. This paper will provide details about the LPG fracs and the resulting production response using a mix of readily available public domain information and information obtained by service providers or vendors. Initially, it was author's intention to use only public data but changes in the local market made access to more information available. A comparison of LPG fracturing treatments with slickwater treated wells will be shown for two of the three wells. Concluding remarks will discuss the current state of LPG fracturing in North America and a possible explanation for production results that did not meet expectations.

Traditionally, in order to estimate the production potential at a new, prospective field site via simulation or material balance, one needs to collect various forms of expensive field data and/or make assumptions about the nature of the formation at that site. Decline curve analysis would not be applicable in this scenario, as producing wells need to pre-exist in the target field. The objective of our work is to make first-order forecasts of production rates at prospective, undrilled sites using only production data from existing wells in the entire play. This is accomplished through co-kriging of decline curve parameter values, where the parameter values are obtained at each existing well by fitting an appropriate decline model to the production history. Co-kriging gives the best linear unbiased prediction of parameter values at undrilled locations, and also estimates uncertainty in those predictions. Thus, we can obtain production forecasts at P10, P50, and P90, as well as calculate EUR at those same levels, across the spatial domain of the play. To demonstrate the proposed methodology, we used monthly gas flow rates and well locations from the Marcellus shale gas play in this research. Looking only at horizontal and directional wells, the gas production rates at each well were carefully filtered and screened. Also, we normalized the rates by perforation interval length. We kept only production histories of 24 months or longer in duration to ensure good decline curve fits. Ultimately, we were left with 5,637 production records. Here, we chose Duong’s decline model to represent production decline in this shale gas play, and fitting of this decline curve was accomplished through ordinary least square regression. Interpolation was done by universal co-kriging with consideration to correlate the four parameters in Duongs’ model, which also showed a linear trend (the parameters show dependency on the x and y spatial coordinates). Kriging gave us the optimal decline curve coefficients at new locations (P50 curve), as well as the variance in these coefficient estimates (used to establish P10 and P90 curves). We were also able to map EUR across the study area. Finally, the co-kriging model was cross-validated with leave-one-out scheme, which showed significant but not unreasonable error in decline curve coefficient prediction. We forecasted potential gas production in the study area using co-kriging. Heat maps of decline curve parameters as well as EUR were constructed to give operators a big picture of the production potential in the play. The methods proposed are easy to implement and do not require various expensive data like permeability, bottom hole pressure, etc., giving operators a risk-based analysis of prospective sites. We also made this analysis available to the public in a user-friendly web app.

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.

Hydraulic fracturing is critical to economic production of shale oil and gas from unconventional reservoirs. Success of completion is closely related to gas production. The brittleness index is widely used as a measurement of ability of hydraulic fracturing. However, the index may not be a unique and explicit indicator for estimating "fracability". In the Marcellus Shale of our study area, there is discrepancy between brittleness index calculated from mineralogy and that from elastic moduli. In addition, the brittleness index does not explain why the large majority of microseismic events were generated well above the Marcellus Shale. Two other factors appear to control fracture stimulation. One is the presence of pre-existing natural fractures. Natural fractures, measured and interpreted from the FMI log, show that fractures developed in similar patterns with high dip angle in the Marcellus and overlying Mahantango shale units, which are favorable for vertical fracture propagation. The other factor is geomechanical characterization. The Marcellus Shale has obvious presence of overpressure. According to the study on stress state using a Mohr's circle, overpressure in the Marcellus Shale increases the possibility of frictional sliding of pre-existing fractures especially at lower value of least principal stress, and will keep some fractures at certain dip angles open, although some of them are in non-active state. Unconfined compressive strength (UCS) is used to estimate rock strength in overpressure strata. The result calculated from empirical equations shows that the Marcellus Shale has significantly lower rock strength, which continues up into the Mahantango Formation, and explain vertical hydraulic fracture growth.

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.

Perforation parameters have a great influence on the performance of the multi-stage fracturing horizontal wells in tight oil reservoirs. Optimizing perforation cluster parameters is able to solve many detrimental issues, including many null perforation clusters without the produced oil, the unevenly distributed output in each stage along horizontal wells, and no complex fracture network always created near the fractured wellbore. To achieve the better performance of the volume fracturing, a practical integrated approach is proposed to optimize perforation cluster parameters. First, based on the good logging data, we establish an evaluation method for the fracability and reservoir properties to select the perforation interval. Second, a mathematical model based on the stress shadow and hydraulic fracture propagation are proposed to optimize the cluster spacing and cluster parameters within each cluster in the same stage, and the un-uniform cluster spacing and perforation number in each cluster are studied. Finally, a case well is successfully conducted with the proposed approach in the tight oil reservoir. Results show that i) the lateral with higher fracability index and property index can be treated as perforation intervals; ii) the un-uniform perforation cluster spacing and the uneven perforation number can obtain a more uniform fracture propagation morphology. The approach can better prevent the generation of ineffective perforation clusters and obtain more complex fracture networks and a better SRV. This also guides to design completion strategy and improves the economic benefits.