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He, Youwei (Southwest Petroleum University) | Guo, Jianchun (Southwest Petroleum University) | Tang, Yong (Southwest Petroleum University) | Xu, Jianliang (Geological Exploration and Development Research Institute, CNPC Chuanqing Drilling Engineering Co. Ltd.) | Li, Yanchao (Shale Gas Exploration & Development Project Department, CNPC Chuanqing Drilling Engineering Co. Ltd.) | Wang, Yong (Geological Exploration and Development Research Institute, CNPC Chuanqing Drilling Engineering Co. Ltd.) | Lu, Qianli (Southwest Petroleum University) | Patil, Shirish (King Fahd University of Petroleum & Minerals) | Rui, Zhenhua (Massachusetts Institute of Technology) | Sepehrnoori, Kamy (The University of Texas at Austin)
Severe fracturing interference in multi-well pads has been identified in shale gas reservoirs. The gas production of affected multi-fractured horizontal wells (MFHWs) decrease a lot and is hard to restore for most wells even after fracturing fluid flowback. Currently, well interference caused by fracturing operations has become the most important factor affecting the shale gas production. However, the mechanism of fracturing interference and its quantitative impact on gas production in shale gas reservoir are not clear.
The aim of this work is to assess the mechanism and dominated factors of fracturing interference of multi-well pads in shale gas reservoirs, and evaluate the impact of interwell fracturing interference on shale gas production. Firstly, field data in WY Basin are applied to calculate the ratio of impacted wells to newly fractured wells and understand the influencing degree and recovering degree of gas production. The main controlling factors of fracturing interference are determined and the interwell fracturing interacting types are presented. Furthermore, the production recovering potential for impacted wells are analyzed. Finally, some suggestions for mitigating fracturing interference are provided.
The impact degree and recovering degree of gas production are divided into three categories. The dominated factors of fracturing interference include well spacing, pressure of the affected wells before interference, gas production before interference, and flowback ratio of fracturing fluid. The influencing degree of gas production can be estimated by using the generated equations of impact degree of gas production per well spacing (IDGPs) or impact degree of gas production per flowback ratio (IDGPf) Another novel finding is that 70% of affected parent wells belong to adjacent well pad compared with the newly fractured child well. The interwell fracturing interference is divided into four types, including pressure interference without direct communications between two MFHWs (Type I), fracturing interference through natural fracture/secondary fractures (Type II), fracturing interference through hydraulic fractures (Type III), and direct communication between hydraulic fractures and wellbore of adjacent well (Type IV). Fracturing communication through hydraulic fractures or secondary/natural fractures are more common, and the impact on well safety and production performance increases from Type I to Type IV. Therefore, the fracturing parameters need to be optimized to reduce the fracturing interference. This study can provide reasonable suggestions for infill well optimization, fracturing design, and interwell fracturing interference mitigation to achieve the highest gas recovery of all multi-well pads in shale gas reservoirs.
This one-day training event introduces completion, production, surveillance and reservoir engineers to the design of fiber-optic DTS (distributed temperature sensing) and DAS (distributed acoustic sensing) well installations. A basic understanding of the principles and benefits of DTS, DAS and surveillance monitoring technology, in general, is assumed. This course provides both an overview of water management and an in-depth look at critical issues related to sourcing (acquiring), reusing, recycling, and disposing of water in hydraulic fracturing operations. The course starts with a background of hydraulic fracturing operations and the different plays around North America. Options being used for transport, storage, reuse, and disposal are described for each of the different regions.
Aimed at sharing the unconventional wisdom gained from a hydraulic fracturing monitoring case study in the Montney tight gas play, the work showcases the ability of 4D modeling of collective behaviors of microseismic events to chase the frac fluid and navigate the spatiotemporal fracture evolution. Moreover, microseismicity-derived deformation fields are integrated with volumetric estimates made by rate transient analysis to calibrate spatially-constrained SRV models. Through the case study, we give evidence of fracture containment, evaluate the role of natural fractures and the use of diverting agents, estimate cluster efficiencies, conduct analytical well spacing optimization, model productivity decline induced by communication frac-hits from offsets, and provide contributing fracture dimensions and numerical production forecasts. To support the interpretations, we supplement the work by the results of 3D physics- based analytical modeling and multi-phase numerical simulations, and the findings are then validated using two extensive datasets: production profiles acquired by fiber optic DAS, and reservoir fluid fingerprints extracted from mud logs. Besides describing the evolution of seismicity during the treatment, the applied integrated fracture mapping process gives a more reliable and unique SRV structure that streamlines forward modeling and simulations in unconventional reservoirs as well as contributes to solving inverse problems more mechanistically.
Noël, Vincent (Stanford University / SLAC National Accelerator Laboratory) | Spielman-Sun, Eleanor (SLAC National Accelerator Laboratory) | Druhan, Jennifer L. (Stanford University / University of Illinois) | Fan, Wenjia (SLAC National Accelerator Laboratory) | Jew, Adam D. (SLAC National Accelerator Laboratory) | Kovscek, Anthony R. (Stanford University) | Brown, Gordon E. (Stanford University / SLAC National Accelerator Laboratory) | Bargar, John R. (Stanford University / SLAC National Accelerator Laboratory)
The low efficiency of unconventional oil and natural gas production is linked to a complex array of coupled geochemical and geomechanical processes that impact porosity and permeability, not only within fractures, but also within the shale matrix. Widely used industrial stimulation approaches, often based on injection of acidic hydraulic fracture fluids (HFFs), dissolve shale minerals, initially increasing permeability and porosity. Mineral dissolution adds new chemical components to pore and produced waters, changing physicochemical variables (
Rezaei, Ali (University of Houston) | Siddiqui, Fahd (University of Houston) | Dindoruk, Birol (University of Houston / Shell International Exploration and Production Inc.) | Soliman, M. Y. (University of Houston)
In order to maximize the profitability of a well and minimize the cost, three key questions must be answered before drilling a well: Where to drill the well? What completion design is to be used? Which fluid type will be produced from the reservoir? These questions must be answered under the premise of maximizing profitability. In this study, we combine the recently developed artificial neural network (ANN) model with a global sensitivity analysis method to present a reduced-order model for addressing these questions.
We developed ANN models to predict the oil and gas production of the first year. The input of the model are parameters such as longitude, latitude, true vertical depth, lateral length, fracturing fluid volume, proppant volume, and fracture stages. Next, we use the Sobol global sensitivity analysis to identify the dominant input variables and their interactions on the variation of the oil and gas production. Finally, we develop reduced-order models that can be represented as a simple algebraic expression consisting of simple mathematical functions. These equations can then be used to predict the production in the Eagle Ford shale rapidly by engineers on the field.
The ANN model used in this study predicted the oil and gas production of the first year with reasonable accuracy. Our model suggests increasing the number of fracture stages and proppant volume in the oil-bearing region. The suggestions for the gas bearing cases were opposite to the oil case. The Sobol global sensitivity approach used in this study captures the variation of the output parameters of the ANN model with respect to the changes in the input parameters. Also, it identifies the combined output variation due to the changes of multiple input parameters. After ranking the dominant contributing input parameters, the model was used to present a simple function to predict the oil and gas production of the first year (combined oil and gas). The function has the advantage to be used in a simple excel sheet and can rapidly predict the results. We compared the accuracy of the proposed reduced order model against the developed ANN model, and results showed less than 5% error in predictions.
For the first time, we have combined the data science methods with analysis of variance (ANOVA) based methods. This has resulted in a simple mathematical function to rapidly and directly predict the oil and gas from Eagle Ford shale, based on the input parameters that can be selected before drilling the well. Using the presented methodology, other such functions can be created for other shale plays and will aid engineers and decision-makers for field development to make reliable and quick decisions.
Hill, A. D. (Texas A&M University) | Laprea-Bigott, M. (Texas A&M University) | Zhu, D. (Texas A&M University) | Moridis, G. (Texas A&M University) | Schechter, D. S. (Texas A&M University) | Datta-Gupta, A. (Texas A&M University) | Abedi, S. (Texas A&M University) | Correa, J. (Lawrence Berkeley National Laboratory) | Birkholzer, J. (Lawrence Berkeley National Laboratory) | Friefeld, B. M. (Class VI Solutions, Inc.) | Zoback, M. D. (Stanford University) | Rasouli, F. (Stanford University) | Cheng, F. (Rice University) | Ajo-Franklin, J. (Rice University / Lawrence Berkeley National Laboratory) | Renk, J. (Department of Energy) | Ogunsola, O. (Department of Energy) | Selvan, K. (INPEX Eagle Ford LLC)
The Eagle Ford Shale Laboratory is a DOE and industry-sponsored multi-disciplinary field experiment aimed at applying advanced diagnostic methods to map hydraulic fractures, proppant distribution, and the stimulated reservoir volume. The field site is an Inpex Eagle Ford, LLC lease in LaSalle county, Texas that has a legacy Eagle Ford producing well and that will be developed with 5 new producers. Utilizing newly-developed monitoring technologies, the project team will deliver unprecedented comprehensive high-quality field data to improve scientific knowledge of three important processes in unconventional oil production from shales: (1) a re-fracturing treatment in which the previously fractured legacy well will be re-stimulated for improved production, (2) a new stimulation stage where the most advanced hydraulic fracturing and geosteering technology will be applied during zipper-fracturing of 3 new producers, and (3) a Gas-Injection Enhanced Oil Recovery (EOR) Phase where one of the wells will be later tested for the efficiency of Huff and Puff gas injection as an EOR method. Field monitoring is being complemented with laboratory testing on cores and drill cuttings, and coupled modeling for design, prediction, calibration, optimization, and code validation. The multi-disciplinary team consists of researchers from Texas A&M University, Lawrence Berkeley National Laboratory, Stanford University, Rice University, and Inpex Eagle Ford, LLC.
The ultimate objective of the Eagle Ford Shale Laboratory Project is to help improve the effectiveness of shale oil production by providing new scientific knowledge and new monitoring technology for both initial stimulation/production as well as enhanced recovery via re-fracturing and EOR. The main scientific/technical objectives of the project are:
Build and test active seismic monitoring with fiber optics in an observation well to conduct: (1) real-time monitoring of fracture propagation and stimulated volume, and (2) 4D seismic monitoring of reservoir changes during initial production and during an EOR pilot.
Test distributed temperature sensing (DTS), distributed acoustic sensing (DAS) and distributed strain sensing (DSS) with fiber optic technology and develop protocols for field application.
Assess spatially and temporally resolved production characteristics and explore relationships with stimulated fracture characteristics by open hole logging, cased hole logging, production logging, and tracer technology.
Understand rock mechanical properties and reservoir fluid properties and their effect of stimulation efficiency through coring and core analysis.
Evaluate suitability of re-fracturing to achieve dramatic improvements in stimulated volume and per well resource recovery.
Develop understanding of gas-based EOR Huff and Puff methods to increase per well resource recovery by lab tests and field test.
Sanguinito, Sean (National Energy Technology Laboratory / Leidos Research Support Team) | Cvetic, Patricia (National Energy Technology Laboratory / Leidos Research Support Team) | Kutchko, Barbara (National Energy Technology Laboratory) | Natesakhawat, Sittichai (National Energy Technology Laboratory / Leidos Research Support Team) | Goodman, Angela (National Energy Technology Laboratory)
With a high demand for an economic energy source but also a concern for increasing greenhouse gas emissions, there is growing consideration in shale production for processes including 1) enhancing hydrocarbon recovery via CO2 flooding, 2) using CO2 as a fracturing agent to reduce water usage, and 3) storing CO2 in shale formations to manage the environmental impact of emissions. To increase fundamental understanding of the reactions that will occur between CO2, shale, and water/fracturing fluid, we use in situ Fourier Transform infrared spectroscopy, (FTIR), feature relocation scanning electron microscopy (SEM), and surface area and pore size analysis using volumetric gas sorption. Samples from the Eagle Ford and Barnett Shales are analyzed with these techniques with exposure to dry CO2, CO2 and water, and CO2 and a synthetic fracturing fluid. These analyses indicate geochemical reactions are directly related to the mineralogical composition of the shale formation, especially carbonate rich shales. Shales targeted for CO2-EOR or CO2 storage will experience two waves of chemical reactivity from fracturing fluid (pH of ∼2) as well as carbonic acid (pH of ∼5.6). This dual reactivity mechanism drives dissolution and precipitation processes, which alter petrophysical properties of the shale, and lead to a significant impact on flow pathways. Barite formation occurs on nucleation sites such as dissolved calcite but is absent on more resistant minerals such as apatite. Sulfur, most likely sourced from kerogen, is readily available for reaction and forms gypsum when shale samples are exposed to carbonated water and forms barite when shale samples are exposed to fracturing fluid. The abundant reactivity observed in these samples impacts the fracture and matrix interface and altering potential flow pathways in the shale.
The increasing need to mitigate greenhouse gas emissions while still requiring energy sources has pushed research efforts to study shale formations for storage of carbon dioxide (CO2) as well as enhanced hydrocarbon recovery (Orr, F.M., 2009a.; Orr, F.M., 2009b; Romanov et al., 2015; Levine et al., 2016, Bacon et al., 2015). Whether storing CO2 in shale formations, or using it in enhanced hydrocarbon recovery techniques, it is necessary to understand the geochemical reactions that will occur between CO2 and shale (DePaolo and Cole, 2013). While several studies have examined the interaction between CO2, shale, and water (Jun, Y et al., 2013; Sanguinito et al., 2018; Goodman et al., 2019; Kutchko et al., 2020) there is limited research focused on the effect fracturing fluid has on shale and CO2 interactions (Dieterich et al., 2016).
Numerous distressed rural communities view oil and gas extraction as economically crucial, but the cyclical nature of the business creates significant challenges for economic development efforts. This research examines hydraulic fracturing from an economic development perspective by bringing together the findings of two technical reports prepared by the author. The focus is supply chain targeting for the Tuscaloosa Marine Shale (TMS) region of Louisiana and Mississippi with benchmarking to more developed shale plays. The findings provide lessons and techniques for rural communities engaged with a shale economy to improve their socio-economic outcomes. To fully leverage the economic benefits of increased hydraulic fracturing in the region, diversified firms for the oil and gas supply chain need to be attracted and developed. The specific industries targeted for attraction and development for the TMS are cement, heavy construction, water transportation, and energy-intensive manufacturing. Workforce programs need to be scalable and stress skills transferability particularly to diversified supply chain target industries.
The TMS region of southwest Mississippi and Louisiana is economically distressed with a declining population, low earnings, and high unemployment. The population in the counties and parishes where hydraulic fracturing is occurring has declined by 1.9% since 2014 and is expected to decrease by 1.4% between 2019 and 2024 (EMSI 2020). Average earnings are $19,700 below national averages. Before the pandemic unemployment was up to 9.1%. The distressed region needs to find ways to increase jobs and wealth.
When considering the specific TMS region and surrounding localities, the oil and gas industry and its supply chain currently support over 5,000 well-paying jobs so it is important for the region's economy. This includes 1,916 direct industry jobs from 131 businesses. These jobs have average earnings of $96,706 which is double average earnings. The oil and gas industry is important to the region and community leaders interviewed viewed the industry favorably.
This study uses a machine learning framework to systematically analyze field production and completion data to understand the impact of frac-hits on parent and child wells and predict well spacing and completions design. Frac hits are one of the most pressing reservoir management issue that can enhance or compromise production over either the short-term or have sustained impacts over longer times. The extent of the impact is dictated by a complex interplay of petrophysical properties (high-perm streaks, mineralogy, etc.), geomechanical properties (near-field and far-field stresses, brittleness, etc.), completion parameters (stage length, cluster spacing, pumping rate, fluid and proppant amount, etc.) and development decisions (well spacing, well scheduling, etc.). As a result, the impact of frac-hits is not straightforward and difficult to predict.
The study uses data from the Meramec, Woodford and Wolfcamp formations. We develop an automated machine-learning based frac-hit detection algorithm that also quantifies the impact on the parent and child wells using matched decline curve models. We analyze about 500 parent and over 1100 child wells in the three formations. Our results show that the key factors governing the extent of the impact are the extent of depletion and producing oil rate of the parent well before frac hit, completion design parameters (fluid and proppant amount) and well spacing. Our machine learning analysis generates regression models to predict the impact of frac hits. These regression models are coupled with economic analysis to determine optimum spacing for any given completion design or optimum completion design for any given spacing.
The parent wells in all three formations had both positive and negative impact of the frac hits. Around 60–67% parent wells were negatively impacted while 33–40% wells were positively impacted. For the child wells, 71–85% wells were negatively impacted and 15–29% of the wells were positively impacted. Combining the impact on parent and child wells, the impact is dominated by the child wells as 69 to 82% of the parent-child pairs were negatively impacted and only 18–31% of the pairs were positively impacted. Considering percent loss in cumulative oil volumes in the next 5-years, in the Meramec, parent wells on average show a 16% reduction while child wells show a 39% reduction due to frac hits. The corresponding numbers for the Woodford formation are 19% and 37% and Wolfcamp formation are 20% and 22%, respectively. This translates to a parent well losing on average 40–50 thousand bbls in next five years and a child well losing on average 130–150 thousand bbls in the same period.
This study systematically analyzes available data to understand the impact of frac hits and formulates a machine learning-based well spacing-well completions matrix workflow that can easily be extended to other formations by integrating commonly available production and completions data.
Yang, Ruiyue (China University of Petroleum) | Chunyang, Hong (China University of Petroleum) | Huang, Zhongwei (China University of Petroleum) | Wen, Haitao (China University of Petroleum) | Li, Xiaojiang (Sinopec Research Institute of Petroleum Engineering) | Huang, Pengpeng (China University of Petroleum) | Liu, Wei (China University of Petroleum) | Chen, Jianxiang (China University of Petroleum)
Summary Multistage hydraulic fracturing is widely used in developing tight reservoirs. However, the economic and environmental burden of freshwater souring, transportation, treatment, and disposal in hydraulic fracturing operations has been a topic of great importance to the energy industry and public alike. Waterless fracturing is one possible method of solving these water-related issues. Liquid nitrogen (LN 2) is considered a promising alternate fracturing fluid that can create fractures by coupled hydraulic/thermal loadings and, more importantly, pose no threats to the environment. However, there are few laboratory experiments that use LN 2 directly as a fracturing fluid. In this work, we examine the performance of LN 2 fracturing based on a newly developed cryogenic-fracturing system under truetriaxial loadings. The breakdown pressure and fracture morphologies are compared with water fracturing. Moreover, fracture-initiation behavior under cryogenic in-situ conditions revealed by cryo-scanning electron microscopy (cryo-SEM) is presented, and the role of thermal stress is quantified by a coupled thermoporoelastic-damage numerical simulation. Finally, the potential application considerations of LN 2 fracturing in the field site are discussed. The results demonstrate that LN 2 fracturing can lower fracture initiation and propagation pressure and generate higher conductive fractures with numerous thermally induced cracks in the vicinity of the wellbore. Thermal gradient could generate enormously high-tensile hoop stress and bring about extensive rock damage. Fracture-propagation direction is inclined to be influenced by the thermal stress. Furthermore, phase transition during the fracturing process and low fluid viscosity of LN 2 can also facilitate the fracture propagation and network generation. The key findings obtained in this work are expected to provide a viable alternative for the sustainable development of tight-reservoir resources in an efficient and environmentally acceptable way. Introduction The commercial development of shale gas/oil, tight gas/oil, coalbed methane (CBM), and other low-permeability reservoirs relies on multistage fracturing in horizontal wells. However, massive hydraulic fracturing using water-based fluid has caused economic and environmental burdens.