bluuebunny/crossref_metadata_2025_split huggingface dataset:
Is Complexity of Hydraulic Fractures Tunable? A Question from Design Perspective
Authors: Yu Hao , Dahi Taleghani Arash , Gonzalez Chavez Miguel , Lian Zhanghua 
Published: October 2018

Abstract
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.
A New Algorithm for Processing Distributed Temperature Sensing DTS
Authors: Carr Timothy , Ghahfarokhi Payam Kavousi , Carney BJ , Hewit Jay , Vagnetti Robert 
Published: October 2018

Abstract
Distributed temperature sensing (DTS) was used to record temperature from early 2016 to present for a Marcellus Shale horizontal dry gas well, MIP-3H, located in Monongalia County, West Virginia. In addition, after wellbore clean-out with water and nitrogen a flow scanner production log was conveyed on March 02, 2017. The flow scanner provides one day of gas and water production from each of the 28 stages in MIP-3H and from each of the clusters. The DTS data provides an opportunity to inspect the reservoir for Joule-Thompson (JT) effect, a phenomenon that describes cooling of an non-ideal gas as it expands from high pressure to low pressure, and obtain a relative production attribute along the lateral of the MIP-3H. The original fiber-optic DTS data shows the temperature along the lateral; however, due to the geometry of the well with toe up and the presence of a small fault and minor water production at Stage 10 relative gas production of each stage cannot be directly determined from the raw DTS data. We present two methods to generate DTS attributes that can be used to better reveal relative gas and water production through time from each perforation cluster and each stage of the MIP-3H. The first attribute deals with the deviations of the DTS measurements from the calculated geothermal temperature, while the second attribute calculated the difference between DTS temperature and the average daily DTS temperature along the lateral of the MIP-3H. We show that the latter DTS attribute provides a more robust image of temperature variations regime along the lateral than the former attribute. Negative values of the DTS attributes reveals JT cooling, resulting from stages of the MIP-3H with higher natural gas production. A correlation analysis of the production log with the calculated DTS attributes suggests that the production log is not representative of the entire production life of MIP-3H well. Temporal correlation with the DTS attributes is highest close to the production log recording day (March 2, 2017) decrease rapidly and the weak correlation switches from positive to negative.
LPG Fracturing in the Marcellus Shale Using Public Domain Information
Authors: Myers Roger 
Published: October 2018

Abstract
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.
Estimation of Fracability of the Marcellus Shale: A Case Study from the MIP3H in Monongalia County, West Virginia, USA
Authors: Zhu Yixuan , Carr Timothy R. 
Published: October 2018

Abstract
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.
Application of Machine Learning Algorithms for Optimizing Future Production in Marcellus Shale, Case Study of Southwestern Pennsylvania
Authors: Shahkarami Alireza , Ayers Kimberly , Wang Guochang , Ayers Alivia 
Published: October 2018

Abstract
The Marcellus Shale has more than a decade of development history. However, there are many questions that still remain unanswered. What is the best inter-well spacing? What are the optimum stage length, proppant loading, and cluster spacing? What are the ideal combinations of these completion parameters? And how can we maximize the rate return on our investment? This study proposes innovative tools that allow researchers to answer these questions. We build these set of tools by utilizing the pattern recognition abilities of machine learning algorithms and public data from the Southwestern Pennsylvania region of the Marcellus Shale.
By means of artificial intelligence and data mining techniques, we studied a database that includes public data from more than 2,000 wells producing from the aforementioned study area. The database contained completion, drilling, and production history information from various operators active in Allegheny, Greene, Fayette, Washington, and Westmoreland counties located in the Southwestern Pennsylvania. Extensive preprocessing and data cleansing steps were involved to prepare the database. Various machine learning techniques (Linear Regression (LR), Support Vector Machines (SVMs), Artificial Neural Networks (ANNs), and Gaussian Processes (GP)) were applied to understand the non-linear patterns in the data. The objective was to develop predictive models that were trained and validated based on the current database. The predictive models were validated using information originating from numerous wells in the area. Once validated, the model could be used in reservoir management decision-making workflows to answer questions such as what are the best drilling scenarios, the optimum hydraulic fracturing design, the initial production rate, and the estimated ultimate recovery (EUR). The workflow is purely based on field data and free of any cognitive human bias. As soon as more data is available, the model could be updated. The core data in this workflow is sourced from public domains, and therefore, intensive preprocessing efforts were necessary.
Production Facility Emissions Reduction in Liquids-Rich Shales: An Update
Authors: Porter Matthew , Natili Rich , Strathman Andrew 
Published: October 2018

Abstract
Operators in unconventional shales are constantly looking for ways to reduce potential emissions from production facilities. This is especially challenging in liquids-rich regions, such as the Marcellus Shale, which is highlighted. As regulations and various industry best practices evolve, facility designs and equipment must evolve as well. Examined are facilities design improvements and successful operational procedures to eliminate or significantly reduce emissions.1
By taking a proactive approach, operators can reduce emissions significantly. In review, an earlier paper (M.D. Porter et. al., 2016) discussed the key elements to a successful program: (1) a facilities design and operational philosophy that takes emission controls into consideration, (2) a comprehensive maintenance program that addresses all unplanned or unintended releases encountered during optical gas imaging inspections and allows for feedback to facilitate corrective action, and (3) a focused plan for improving technology to diminish the quantity of future leaks. Applying enhanced technology, and lessons learned, to older designs is often the most efficient measure for reducing potential emissions. While these elements are crucial, equally important is the historical defining and tracking of actual identified leaks and documentation of corrective actions that have been taken.1 This paper further corroborates these key elements.
Additional facility designs for maximum emissions reduction will be compared to facility designs in the previous work using calculated emissions for each scenario. As well production increases from drilling longer laterals and enhanced stimulation practices, well site liquids handling and vapor control can become challenging. Techniques for effectively controlling vapors and mitigating emissions are explored in detail using an actual case study. Also, a previous leak detection field study with preliminary data is updated with additional years of data, which yields further clarification of emissions released on a field and pad level and resulting variations with time. Using detailed data analysis resulting from inspections, the most common areas where leaks occur within a production facility area are identified - the majority of which are located on atmospheric stock tanks. Data further demonstrates the effectiveness of higher quality tank relief valves for reducing fugitive leaks.
Production facility emissions can be managed utilizing effective production facility designs and technologies. The present work offers an improved understanding of how technological evolutions can support effective design solutions and processes in a modern shale gas development.1
Completion Diagnostics Learnings from Shale Development Projects
Authors: Ramos Claudio R , Woodroof Robert A , Warren Mark N 
Published: October 2018

Abstract
Accelerating the learning curve in the development of the Vaca Muerta utilizing lessons learned in North American unconventional resource plays is the focus of this paper. Reducing completion costs while maintaining high productivity has become a key objective in the current low-price environment. Completion diagnostics have been demonstrated to optimize stimulation and completion parameters that have shaped successful field developments.
The paper reviews stimulation diagnostic data from wells completed in the Tuscaloosa Marine Shale, Eagle Ford, Wolfcamp and Niobrara shale formations. Case histories are presented in which proppant and fluid tracers were successfully employed in completion optimization processes. In the examples presented, diagnostic results were used to assess the stimulation of high productivity intervals within a target zone, evaluate various completion methods, and optimize stage and cluster spacing. The diagnostic data were compared with post-frac production rates in an effort to correlate completion changes with well performance. Results presented compare first, engineered perforations versus conventional geometrically spaced perforations to drive up effectiveness in cluster stimulation. Second, new chemistries, such as nanosurfactant, versus conventional chemistries to cut either completion cost or prove their profitability. Third, employing an effective choke management strategy to improve well productivity. Last, as in any stacked pay, determining fracture height growth in order to optimize well density, well spacing, field development and ultimately the recovery of the natural resources.
Completion effectiveness is shown to be improved by landing laterals in high productivity target intervals, increasing proppant coverage across the lateral by utilizing the most effective completion methods, optimizing cluster spacing and decreasing the number of stages to reduce completion costs while achieving comparable production rates. Cluster treatment efficiency (CTE), in particular, has become a critical metric when optimizing hydraulic fracturing treatment designs based on current and future well densities. It can be used to rationalize well performance as well as to identify possible candidates for a refrac program.
Using completion diagnostics, successful completion techniques were identified that led to production enhancements and cost reductions in prolific plays such as the Tuscaloosa Marine Shale, Eagle Ford, Wolfcamp and Niobrara.
Effects of Aqueous Solubility and Diffusion of Multi-Components on Shale Reservoir Recovery during CO2 EOR
Authors: Lee Ji Ho , Lee Kun Sang 
Published: October 2018

Abstract
The purpose of this study is to investigate effects of aqueous solubility and aqueous phase molecular diffusion of gaseous components when CO2 Huff and Puff process is applied into shale reservoirs. The gaseous components of CO2 and CH4 have solubility in water. In addition, flow of the CO2 and CH4 in shale reservoir is also affected by aqueous phase molecular diffusion phenemonon. Therefore, this study simulates CO2 Huff and Puff in shale gas-condensate and shale oil reservoirs considering the aqueous solubility and aqueous phase molecular diffusion of CO2 and CH4.
The aqueous solubility during CO2 Huff and Puff increases the CO2 storage capacity in shale reservoirs, but provides negligible change on production. However, aqueous phase diffusion phenomenon of CO2 increases contacting area between CO2 and oil in matrix and enhances the production of CO2 Huff and Puff in shale oil reservoir. To be significant in the simulations of CO2 Huff and Puff, considering mechanisms of aqueous solubility and aqueous phase molecular diffusion is necessary in shale reservoirs.
Determining Optimal Well Spacing in the Marcellus Shale: A Case Study Using an Integrated Workflow
Authors: Pankaj Piyush , Shukla Priyavrat , Kavousi Payam , Carr Timothy 
Published: October 2018

Abstract
Naturally fractured reservoirs such as the Marcellus shale require an integrated reservoir modeling approach to determine well spacing and well-to-well interference. The Marcellus Shale Energy and Environment Laboratory (MSEEL) is a joint project between universities, companies, and government to develop and test new completion technologies and acquire a robust understanding of the Marcellus shale. The study presented in this paper aims to reveal an approach to determine reservoir depletion with time through coupled geological modeling and geomechanical evaluation followed by completion and well performance history matching for a multiwell pad in the Marcellus shale.
The geomechanical model was prepared with interpreted vertical log data. A discrete natural fracture (DFN) model was created and used to determine the complexity of hydraulic fracture geometry simulated through complex fracture models on a two well pad. The microseismic data obtained during the hydraulic fracture simulations served as a constraining parameter for the hydraulic fracture footprint in these wells. Sensitivity to the DFN is realized by parametric variations of DFN properties to achieve a calibrated fracture geometry. Reservoir simulation and history matching the well production data confirmed the subsurface production response to the hydraulic fractures. Well spacing sensitivity was done to reveal the optimum distance that the wells need to be spaced to maximize recovery and number of wells per section.
Hydraulic fracture geometry was found to be a result of the calibration parameters, such as horizontal stress anisotropy, fracturing fluid leakoff, and the DFN. The availability of microseismic data and production history matching through integrated numerical simulation are therefore critical elements to bring unique representation of the subsurface reaction to the injected fracturing fluid. This approach can therefore be consistently applied to evaluate well spacing and interference in time for the subsequent wells completed in the Marcellus. With the current completion design and pumping treatments, the optimal well spacing of 990 ft was determined between the wells in this study. However, wells to be completed in the future needs to be modeled due to the heterogeneity in the reservoir properties to ensure that wells are not either underspaced to cause well production interference or overspaced to create upswept hydrocarbon reserves in the formation.
By adopting the key learnings and approach followed in this paper, operators can maximize subsurface understanding and will be able to place their wellbore in a nongeometric pattern based on reservoir heterogeneity to optimize well spacing and improve recovery.
From Wellbore to Seismic: An Integrated Approach for Geomechanical Characterizaiton of Naturally Fractured Reservoirs
Authors: Zhang Wenyu , Zhu Ding , Kim Jihoon 
Published: October 2018

Abstract
In unconventional plays, the performance of fractured wells is closely related to in-situ stress state and natural fracture distributions. The anisotropic geomechanical behavior of naturally fractured rock makes it difficult to appropriately evaluate the stress and geomechanical properties of the field. In this study, we present a wellbore-based, integrated geomechanics-seismic model that aims to improve the current stress field prediction and characterization of naturally fractured reservoirs, and ultimately, to optimize reservoir development.
The integrated model, starting from borehole-scale, uses a borehole stability model that considers the elastic anisotropy to provide the local stresses. Image log and other logging data are used to characterize natural fractures under local stress condition. A finite element based geomechanical model, which adopts anisotropic non-linear elasticity to best capture the physical behavior of fractured rock, is developed to estimate the current stress field at reservoir-scale, with wellbore stresses as constraints. The apertures of natural fractures in the reservoir are updated during the simulation. Seismic anisotropy caused by open fractures is then calculated and serves as another calibration method to improve identifying open natural fractures.
In this paper, a case study is presented. Given the estimated fracture spacing and aperture, the wellbore-based, integrated geomechanics-seismic model estimates a more homogenous maximum and minimum horizontal stress magnitude variations throughout the field comparing to an isotropic linear elastic geomechanics model. This also results in a narrower range for the horizontal stress ratio. The different results in the magnitudes of horizontal stresses will also cause difference in predicted fracture apertures, which results in changes in fracture permeability and porosity in coupled flow-geomechanics reservoir simulation. Eventually, for this case study, the seismic velocity anisotropy is predicted based on the simulated current stress condition.
Comparing to the conventional method for characterizing naturally fractured reservoirs, this integrated approach utilizing a wellbore-based, geomechanics-seismic model can estimate the stress field and fracture properties more rigorously. The improved results can be beneficial in aspects of well planning, hydraulic fracture design, and coupled reservoir simulation in unconventional plays.
Numerical Simulations of the Flow Past Crescent Cylinders for Flow Metering Purposes
Authors: Ahmed Yusuf , Ahmad Talha , Noui-Mehidi Mohamed Nabil 
Published: October 2018

Abstract
The present study is devoted to the flow peoperties of a vortex shedding system behind a bluff body that has a crescent cross-section, facing downstream of the flow. The investigation is conducted numerically using a lattice Boltzmann method. As a benchmark validation, the studied system was compared to the system of vortices formed behind the classical case of a circular cylinder for the same flow configuration and dynamic conditions, while varying the Reynolds number. The flow simulations have revealed that the crescent body affected substantially the shedding mechanism with remarkable differences when compared to the classical cylindrical case. There was a clear decrease in the shedding frequency with the crescent body that is beneficial when using this system as a metering tool.