Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Petroleum Engineering, University of Houston, 2. Metarock Laboratories, 3. Department of Earth and Atmospheric Sciences, University of Houston) 16:00-16:30 Break and Walk to Bizzell Museum 16:30-17:30 Tour: History of Science Collections, Bizzell Memorial Library, The University of Oklahoma 17:30-19:00 Networking Reception: Thurman J. White Forum Building
- Research Report > New Finding (0.93)
- Overview (0.68)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral (0.72)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- (2 more...)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.93)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (47 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (20 more...)
- North America > United States > Texas (1.00)
- Europe (0.93)
- Research Report > New Finding (0.93)
- Overview (0.88)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.47)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.93)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (49 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- (20 more...)
On the Path to Least Principal Stress Prediction: Quantifying the Impact of Borehole Logs on the Prediction Model
Dvory, N. Z. (Civil & Environmental Engineering & Energy and Geoscience Institute) | Smith, P. J. (Chemical Engineering) | McCormack, K. L. (Energy and Geoscience Institute) | Esser, R. (Energy and Geoscience Institute) | McPherson, B. J. (Civil & Environmental Engineering & Energy and Geoscience Institute)
ABSTRACT Knowledge of the minimum horizontal principal stress (Shmin) is essential for geo-energy utilization. Shmin direct measurements are costly, involve high-risk operations, and provide only discrete values of the required quantity. Other methods were developed to interpret a continuous stress sequence from sonic logs. These methods usually require some ‘horizontal tectonic stress’ correction for calibration and rarely match sections characterized by stress profiling due to viscoelastic stress relaxation. Recently, several studies have tried to predict the stress profile by an empirical correlation corresponding to an average strain rate through geologic time or by using machine learning technologies. Here, we used the Bayesian Physics-Based Machine Learning framework to identify the relationships among the viscoelastic parameter distributions and to quantify statistical uncertainty. More specifically, we used well logs data and ISIP measurements to quantify the uncertainty of the viscoelastic-dependent stress profile model. Our results show that the linear regression approach suffers from higher uncertainty, and the Gaussian process regression Shmin prediction shows a relatively smaller uncertainty distribution. Extracting the lithology logs from the prediction model improves each method's uncertainty distribution. We show that the density and the porosity logs have a superior correlation to the viscoplastic stress relaxation behavior. INTRODUCTION Comprehensive recognition of the least principal stress is essential for economic multistage hydraulic fracturing stimulation design. It is well established that hydraulic fractures propagate perpendicular to the least principal stress and that the stress profile prominent the hydraulic fractures generation in both the lateral and horizontal direction (Fisher et al., 2012; Hubbert and Willis, 1957; Kohli et al., 2022; Valkó and Economides, 1995; Zoback et al., 2022)c. In other words, the stress layering could act as a ‘frac barrier’ that limits fracture development in discrete directions and promotes progress in different directions (Singh et al., 2019). Detailed knowledge of the least principal stress profile is significant for hydraulic fracture growth assessment, proppants technology optimization, and efficient landing zone detection (Pudugramam et al., 2022). Traditionally, these considerations were aligned with the oil and gas industry. Still, today, they have substantial implications for enhanced geothermal system development, carbon storage integrity, and in a broader sense, a safe path for a carbon neutrality economy.
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- (13 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Recent Advances and New Insights of Fiber Optic Techniques in Fracture Diagnostics Used for Unconventional Reservoirs
Nath, Fatick (School of Engineering, Texas A&M International University, Laredo) | Hoque, S. M. Shamsul (School of Geosciences, University of Louisiana at Lafayette) | Mahmood, Md. Nahin (Petroleum Engineering, University of Louisiana at Lafayette)
Abstract Technological advancements in well completion and stimulation have resulted in record production and considerable growth in global unconventional markets. However, the connection of the wellbore to hydrocarbon resource volumes by effective fracture stimulation is a critical factor in unconventional reservoir completions. Fiber optic (FO) techniques are gaining confidence among researchers for a better understanding of fracture diagnostics, visualization of the created hydraulic fractures, and identifying the proppant placement in the deep formation. Several notable outcomes have been observed recently in this emerging field. This paper investigates the recent advances and future opportunities in FO measurements for evaluating the stimulation performance in unconventional reservoirs. FO technique - Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS) cover the way to overcome the lack of knowledge in fracture diagnosis. Advances in this technique address challenges of fracture diagnostic between new cracks and reactivation of existing cracks, understanding fracture geometry, strain field, accurate inflow profile, and the far-field response of hydraulic fracturing treatment. A comprehensive discussion is made with their application in different shale formations (Eagle Ford, Bakken, Permian Basin, and Marcellus) of the United States. The advantages and limitations of each technique were highlighted. Finally, the paper evaluates what are the completion evaluation strategies to employ in unconventional moving forward. The result illustrates the observations obtained from the deployment of FO techniques in the Bakken, Eagle Ford, Marcellus, and Permian shale formations. The comparative outcomes of those methods have been analyzed to develop a pragmatic guideline for factors impacting fracture diagnostics. The review finds that modeling and interpreting DAS strain rate responses can help quantitatively to map fracture propagation and stimulated reservoir volume. The relationship between injection rate and strain rate responses is investigated to show the potential of using DAS measurements to diagnose multistage fracturing. FO diagnostics indicate that interactions between the well, the fracture, and the rock are complex, hence the need to integrate the results with other diagnostics and reservoir information. Rapidly growing FO implementation in fracture diagnostics needs direction based on recent developments made in this field. This work discusses and summarizes important outcomes that will benefit future researchers to integrate ideas and generate breakthroughs in FO implementation for fracture evaluation and monitoring. Extensive insight is a need for the industry given that there are growing developments and opportunities in unconventional plays, as operators are finding more economic ways to enhance production through stimulation. However, a critical review of FO implementation by analyzing the public domain has not been done before with the breadth and depth that this paper provides.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.96)
- Geology > Petroleum Play Type > Unconventional Play (0.89)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- (41 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Lithologically-Controlled Variations of the Least Principal Stress with Depth and Resultant Frac Fingerprints During Multi-Stage Hydraulic Fracturing
Zoback, Mark (Stanford University) | Ruths, Troy (Petro.ai) | McClure, Mark (ResFrac) | Singh, Ankush (ResFrac) | Kohli, Arjun (Stanford University) | Hall, Brendon (Petro.ai) | Irvin, Rohan (ResFrac) | Kintzing, Malcolm (Henry Resources)
Abstract We present observational data and modeling results which support the hypothesis that the degree of vertical to horizontal hydraulic fracture propagation during multi-stage hydraulic fracturing is largely controlled by variations of the least principal stress with depth. It is obvious that monotonic variations of the least principal stress with depth imply either upward or downward hydraulic fracture growth. More interestingly, we present several case studies in which direct measurements show layer-to-layer stress variations of the least principal stress as large as ~10 MPa (~1500 psi) which are lithologically controlled. Using two different types of analysis approaches, we investigate complex patterns of vertical and horizontal hydraulic fracture growth from the Midland Basin. In each case, we show that pattern of hydraulic fracture propagation (and resultant drainage volumes) are largely governed by the detailed variation of the magnitude of the least horizontal stress with depth and exact position of a given stage. In gun barrel view, this complex pattern we refer to as a frac fingerprint for convenience. The frac fingerprint depends on the exact vertical position of a frac stage with respect to the variations of the least principal stress in the layers both above and below the stage depth. We show how frac fingerprints can vary along the length of a well because of the way its trajectory encounters lithofacies along its length. We briefly discuss the implication of these concepts for choosing optimal well spacings and landing depths and the relationships between hydraulic fracture geometry and drainage volumes. Introduction It was established 65 years ago that hydraulic fractures should propagate perpendicular to the minimum horizontal principal stress, Shmin (Hubbert and Willis, 1957). While there have been abundant observations consistent with this concept, recent experiments in the Eagleford Formation (Raterman et al., 2017) and the Permian Basin at HFTS-1 and HFTS-2 (Gale et al., 2018: 2021) have added appreciable new data confirming this concept. Hubbert and Willis (1957) also argued that the magnitude of the least principal stress governs the pressure required for propagation of hydraulic fractures. In most areas, of interest to development of unconventional oil and gas reservoirs, the least principal stress is the least principal horizontal stress, Shmin (see recent review by Lund Snee and Zoback (2022) of stress orientations and magnitudes in unconventional sedimentary basins in North America). Thus, knowledge of Shmin and its variations with depth is especially important in unconventional oil and gas reservoirs exploited with multi-stage hydraulic fracturing in horizontal wells. Of specific interest in this paper is the variation of Shmin with depth. The least principal stress governs the degree to which hydraulic fractures propagate vertically, either upward or downward, depending on Shmin magnitudes above, within and below the horizontal section of well commonly referred to as the lateral. Significant vertical propagation can limit successful exploitation of the targeted formation and defines the number of laterals required to exploit productive zones at multiple depth intervals or stacked pay. Hence, optimizing the depths and number of laterals needed to exploit stacked pay as well as the optimal well spacing at different depths will be closely related to how the magnitude of Shmin varies with depth.
- North America > United States > Texas (1.00)
- North America > United States > Gulf of Mexico > Central GOM (0.25)
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.68)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (45 more...)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (3 more...)
Linking Flowback Recovery to Completion Efficiency: Niobrara-DJ Basin Case Study
Moussa, Tamer (University of Alberta) | Barhaug, Jessica (Great Western Operating Company LLC.) | Witt, Darby (Cordax Evaluation Technologies INC.) | Hawkes, Robert (Cordax Evaluation Technologies INC.) | Dehghanpour, Hassan (University of Alberta)
Abstract Near wellbore complexity is a current topic of discussion among geoscience and engineering disciplines across North America. Asset teams are constantly investing money and resources into the variety of near- and far-field wellbore diagnostic techniques to ascertain completion efficiency. These range from high-cost microseismic for far-field fracture placement to higher risk technologies such as fiber optics, cameras, and production logging tools. These techniques are generally used for parameter constraints for rate-transient-analysis (RTA) that requires months (and sometimes years) of production after post-frac flowback. Therefore, in this study we utilize flowback water-oil-ratio (WOR) as a diagnostic tool to provide early-time feedback for completion-efficiency evaluation. We analyze flowback, post-flowback and completion-design data of 19 multi-fractured horizontal wells (MFHWs) completed in Niobrara and Codell formations that are classified into parent and child groups. Child wells are then sub-clustered into Zipper-1 and -2 completed with more and less intense completion strategy, respectively. First, we analyze the flowback rate and pressure profiles of the 19 wells to estimate initial pressure in the stimulated area around wellbore and validate it against the outcomes of diagnostic fracture injection test (DFIT). Second, we apply rate-normalized-pressure (RNP) diagnostic analysis to a) investigate flow regimes during flowback and post-flowback periods; and b) assess interference between parent and child wells. Third, we use WOR diagnostic plots to estimate ultimate load recovery (ULR) and calculate initial effective fracture volume as two indicators for completion efficiency. We also cross-check the estimated effective fracture volume with microseismic dimensions. Finally, we apply rate-decline analysis on oil production data to predict ultimate oil recovery (UQo), assuming a critical oil rate of 1 stbd, and use it as a third performance indicator to evaluate the completion-design efficiency of each group. Child wells show 32% more load recovery compared with the parent wells. However, the parent wells show 38% and 50% more 9-months cumulative oil production (Qo) and UQo, respectively. For both the parent and child wells, more than 50% of the predicted ULR is produced back within the first three months of production. Although the intense completion-design strategy for Zipper-1 wells led to 35% larger effective fracture volume compared to Zipper-2 wells, both groups show similar oil recovery performance. Generally, Niobrara wells show less load recovery and effective fracture volume compared to Codell wells in each completion group.
- North America > United States > Colorado (1.00)
- North America > United States > Texas (0.93)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Codell Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (42 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Production forecasting (1.00)
- (3 more...)
Abstract Parent-child wells are horizontal wells drilled in close proximity to each other in unconventional basins. Simulation work in the technical literature demonstrates how depletion and fracture communication between parent and child wells can lead to child well underperformance. High-level, basin-wide data analysis of unconventional basins confirms this effect. However, as completion designs evolve and more state-of-the-art horizontal wells are completed in these basins, it is necessary to revisit this analysis and make adjustments and additions to the previous body of work. Specifically, initial production differences between parent and child wells need to be correlated to cumulative production differences, and more analysis regarding the effect of timing and spacing are needed. In this study, parent-child well pairs for wells completed within the last seven years in nine different unconventional basins are identified using a Python code applied to Enverus public data obtained in November 2020. These basins include the Bakken, Delaware, Eagle Ford, Haynesville, Marcellus/Utica, Midland, Niobrara, Powder River, and Scoop/Stack Basins. Our Python code also performs calculations to create the necessary comparative metrics for analysis. Four cumulative production proxies are created and First 12 Months BOE (barrel of oil equivalent) is chosen as the appropriate metric for analysis. Basin-to-basin comparisons are conducted, and the effects of well spacing and infill timing are investigated. The study finds that as stated in the technical literature, child well performance increases with spacing and decreases with infill timing. We show that parent cumulative production (BOE) at child well completion is a better indicator of child well performance. Overall, these assessments can help operators manage child well underperformance and can help them understand the effects of differing well spacing and infill timing on child well performance in different US unconventional basins.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.94)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.94)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.94)
- (19 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- (6 more...)
- Information Technology > Software > Programming Languages (0.54)
- Information Technology > Data Science > Data Quality (0.46)
Pressure Decline Analysis in Fractured Horizontal Wells: Comparison between Diagnostic Fracture Injection Test, Flowback, and Main Stage Falloff
Wang, HanYi (University of Texas at Austin (Corresponding author) | Elliott, Brendan (email: wanghanyi@areafrac.com) | Sharma, Mukul (now with AreaFrac Technology LLC))
Summary The pressure decline data after the end of a hydraulic fracture stage are sometimes monitored for an extended period of time. However, to the best of our knowledge, these data are not analyzed and are often ignored or underappreciated because of a lack of suitable models for the closure of propped fractures. In this study, we present a new approach to model and analyze pressure decline data that are available in unconventional horizontal wells with multistage, transverse hydraulic fracturing. The methods presented in this study allow us to quantify closure stress and average pore pressure inside the stimulated reservoir volume (SRV) and to infer the uniformity of proppant distribution without additional data acquisition costs. For the first time, field data of diagnostic fracture injection test (DFIT), flowback, and pressure decline of main fracturing stages from the same well are compared and analyzed. We found that the early-time main fracturing stage pressure decline trend is controlled by fracture tip extension, followed by progressive hydraulic fracture closure on the proppant pack, whereas late-time pressure decline reflects linear flow. When DFIT data are not available, pressure decline analysis of a main hydraulic fracturing stage can be a substitution if it can be monitored for an extended period to allow fracture closure on proppants and asperities.
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > Oklahoma > Anadarko Basin > Cana Woodford Shale Formation (0.99)
- (4 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Years in the making, the recent steady rise in drilling in the Powder River Basin of northeast Wyoming is generating excitement reminiscent of the early days of currently more-established US onshore oil plays. The upturn in activity is resulting in double-digit production growth. Wells are bubbling over with oil, and operators are bubbling over with enthusiasm. This has been most evident in recent industry presentations, where decision makers from the basin's exclusive club of operators have gushed over what is becoming a core asset in their portfolios. Given the basin's oil richness, multiple stacked horizons, and well performance and economics, "we think it's comparable and competitive with the big-name basins--whether it's the Permian, SCOOP, or STACK," Joseph DeDominic, president and chief operating officer of Anschutz Exploration, said at a recent SPE Gulf Coast Section meeting on the basin.
- North America > United States > Wyoming > Powder River Basin > Sussex Formation (0.99)
- North America > United States > Wyoming > Powder River Basin > Shannon Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.99)
- (20 more...)
- Well Drilling > Drilling Operations (1.00)
- Management > Energy Economics (0.95)
- Well Completion > Hydraulic Fracturing (0.95)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (0.70)
The Influence of Development Target Depletion on Stress Evolution and Well Completion of Upside Target in the Permian Basin
Pei, Yanli (The University of Texas at Austin) | Yu, Wei (The University of Texas at Austin / Sim Tech LLC) | Sepehrnoori, Kamy (The University of Texas at Austin) | Gong, Yiwen (Sim Tech LLC / The Ohio State University) | Xie, Hongbin (Sim Tech LLC) | Wu, Kan (Texas A&M University)
Abstract The extensive depletion of the development target has triggered the demand for infill drilling in the upside target of multilayer unconventional reservoirs. To optimize the hydraulic fracturing design of newly drilled wells, we need to investigate the stress changes in the upside target induced by parent-well production. In this work, an integrated parent-child workflow is presented to model the spatial-temporal stress evolution and propose the optimal development strategy for the upside target using a data set from the Permian Basin. The stress dependence of matrix permeability and fracture conductivity is determined based on available experimental data and incorporated in our reservoir simulation with the aid of an embedded discrete fracture model (EDFM). With calibrated reservoir properties from history matching of an actual well in the development target (i.e., 3 BS Sand), we run the finite element method (FEM) based geomechanics simulator to predict the 3D spatial-temporal evolution of the local principal stresses. A displacement discontinuity method (DDM) hydraulic fracture model is then applied to simulate the multi-cluster fracture propagation in the upside target (i.e., L2BSSh) with the updated heterogeneous stress field. Numerical results indicate that stress field redistribution associated with parent-well production not only occurs within the development target but also vertically propagates to the upside target. A smaller parent-child horizontal offset induces a severer deviation of child-fractures towards the parent wellbore, resulting in more substantial well interference and less desirable oil and gas production. The parent-child fracture overlapping ratio in our study is in 0.6 ~ 0.8 for the 400 ft horizontal offset and 0.2 ~ 0.5 for the 600 ft horizontal offset. Varying the parent-child vertical offset gives the same trend as we change the horizontal offset. But with a delayed infill time, placing child-well in different layers causes more significant variation in the ultimate recovery. Moreover, infill operations at an earlier time are less affected by parent-well depletion because of the more homogeneous stress state. The candidate locations to implement infill-wells are suggested in the end for different infill timing by co-simulation of the parent-child production. With the reservoir-geomechanics-fracture model, this work provides a general workflow to optimize the child-well completion in multilayer unconventional reservoirs. The conclusions drawn from this study are of guiding significance to the subsequent development in the Permian Basin.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- South America > Argentina > Neuquén Province > Neuquén (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.94)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (41 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- (4 more...)