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Abstract Continuing from the previous publication (Navaiz et al. 2023) detailing the hydraulic fracturing energy system and energy transfer as fluid and proppant are pumped from the surface into formation. this paper focuses on the validating the importance of effective energy delivered to formation and its correlation to total productivity. Combining extensive in-house pumping data and well-production data available from the public domain, a two-dimensional approach cross-plotting total effective energy injected per unit area against production output shows a highly correlative positive relationship (R2>0.75) across several basins in North America. This strong relationship not only reinforces the value of this energy analysis concept in hydraulic fracturing established by the authors previously. It also validates the conservation of energy principle highlighting the usefulness of relating effective energy injected into formation to a direct increase in reservoir energy potential and therefore a greater potential for total productivity. With the unconventional oil and gas industry highly focused on capital efficiency, the effective energy metric enables near-instantaneous optimization of development costs rather than iterating on 6-month or 1-year production performance. Time and capital can then be invested in technologies and processes that maximize effective energy and resultant productivity or minimize energy losses in the system.
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (36 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- (5 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)
Application of Fracture Injection Test, Rate Transient Analysis, and Pearson Correlation in Niobrara and Codell Formations to Evaluate Reservoir Performance in a Northern DJ Basin
Mindygaliyeva, B. (Colorado School of Mines) | Bekbossinov, N. (Colorado School of Mines) | Kazemi, H. (Colorado School of Mines)
ABSTRACT: This paper presents an assessment of well drilling strategy and the associated hydraulic fracture stimulation for a field in the Northern DJ Basin, Colorado. The paper is rich in data related to well orientation, completion, and production over a ten-year period from an unconventional field. Shale formations have very low permeabilities; however, multistage hydraulic fracturing stimulates the rock matrix by inducing micro- and macro-cracks; thus, improving formation drainage. Subsequently, rate transient analysis (RTA) of production data determines the quality of well stimulation. RTA emanates from single-phase linear-flow theory using rate-normalized-pressure versus (Equation) of the production data; however, RTA also extends to multiphase flow. RTA yields the effective formation permeability (EFP) and, occasionally, hydraulic fracture conductivity (HFC). Additionally, we used an iterative Perkins-Kern-Nordgren (PKN) model to interpret diagnostic fracture injection tests (DFIT) for the unstimulated formation permeability. Finally, we used 21 variables to generate a ‘correlation map’ of various reservoir performance measures: well s pacing, lateral length, number of perforations, total stimulation fluid injected, amount of sand placed, sand mesh size, quantity of p roduced oil, gas, and water. The variables that yielded the strongest positive correlation coefficients were well spacing, produced oil and gas volumes, 20/40 sand, acid additives, EFP, and HFC. 1. INTRODUCTION The Shale formations are denoted as ‘tight’ reservoir plays with low, nano-Darcy, matrix permeabilities where pore-size distribution is in the nanometer higher frequencies (Luo, 2018). Because of low matrix permeability, the maturation of the organic matter takes place in the source rock and the resultant distribution of hydrocarbon components also remains within the source rock with little outward migration. Formations with such characteristics are designated ‘unconventional reservoir’. There is a continued demand for hydrocarbon production due to the global energy demand and population growth. Fortunately, innovations in the technological sector of the oil and gas industry has provided effective means of oil and gas recovery from such tight formations (Kazemi et al., 2015). Contribution of unconventional reservoirs is significant in maintaining the balance in the energy market (Cui, 2015).
- North America > United States > Wyoming (1.00)
- North America > United States > Colorado (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.94)
- North America > United States > Wyoming > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- (11 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (2 more...)
Paying it Forward: How an Emerging Unconventional Play can Hit the Ground Running
Koperna, George J (Advanced Resources International, Inc.) | Murray, Brett L (Advanced Resources International, Inc.) | Riestenberg, David E (Advanced Resources International, Inc.) | Carpenter, Steven M (Enhanced Oil Recovery Institute)
Abstract While every tight oil play is unique, there are lessons that can be transferred from one play to another to improve the efficiency and pace of production operations and development. These improvements may not fit precisely in every basin or play but generally hold to themes that can be tested against and built upon. Themes such as the quantity of proppant, longer lateral length, or the number of stages can be directly tied to increased productivity. However, there are diminishing returns on these investment activities for which each operator, within a given play, will be required to identify and mitigate against. This is especially true as the industry steps in and begins developing new tight oil plays. In their nascent stages, these plays may have limited well penetrations and, as a result, limited geological and performance data from which to extrapolate. Pulling together an understanding of where the industry currently resides in terms of how to exploit these resources can provide a boost in terms of working towards greatly improved well completions. In 2019, the US EIA estimated that nearly 8 million barrels of oil per day were produced from tight oil reservoirs in the United States (US EIA, 2020). This represents over 60% of the domestic crude production, originating from multiple reservoirs in the Permian Basin (TX) as well as the Bakken (MT, ND), Eagle Ford (TX), Niobrara (CO, WY), and Anadarko Basin (OK) formations, among others. As such, there are 1,000s of wells across these numerous tight oil plays that can relate an informative story. To build this story, the interplay of geology, well spacing, lateral length, and stimulation, all critical to economic success, will be explored. This paper proposes to look back at these mature tight oil (and gas) basins and bring forth an understanding of what lessons can be applied to the emerging Powder River Basin tight oil reservoirs (Mowry and the Turner/Frontier). The authors will delve into the four broad topics of geology, well spacing, lateral length, and stimulation, highlighting case studies to demonstrate those lessons from established tight oil plays that will underpin planned activities at a Field Laboratory Test Site in the southern Powder River Basin.
- North America > United States > Texas (1.00)
- North America > United States > Montana (0.89)
- North America > United States > Wyoming > Niobrara County (0.24)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.32)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Spearhead Ranch Field (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (58 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- (7 more...)
Summary “Fracture hit” was initially coined to refer to the phenomenon of an infill-well fracture interacting with an adjacent well during the hydraulic-fracturing process. However, over time, its use has been extended to any type of well interference or interaction in unconventional reservoirs. In this study, an exhaustive literature survey was performed on fracture hits to identify key factors affecting the fracture hits and suggest different strategies to manage fracture hits. The impact of fracture hits is dictated by a complex interplay of petrophysical properties (high-permeability streaks, mineralogy, matrix permeability, natural fractures), geomechanical properties (near-field and far-field stresses, tensile strength, Young’s modulus, Poisson’s ratio), completion parameters (stage length, cluster spacing, pumping rate, fluid and proppant amount), and development decisions (well spacing, well scheduling, fracture sequencing). It is difficult to predict the impact of fracture hits, and they affect both parent and child wells. The impact on the child wells is predominantly negative, whereas the effect on parent wells can be either positive or negative. The “child wells” in this context refer to the wells drilled with pre-existing active/inactive well(s) around. The “parent well” refers to any well drilled without any pre-existing well around. Overall, fracture hits tend to negatively affect both the production and economics of lease development. The optimal approach rests in identifying the reservoir properties and accordingly making field-development decisions that minimize the negative impact of fracture hits. The different strategies proposed to minimize the negative impact of fracture hits are simultaneous lease development, thus avoiding parent/child wells (i.e., rolling-, tank-, and cube-development methods); repressuring or refracturing parent wells; using far-field diverters and high-permeability plugging agents in the child-well fracturing fluid; and optimizing stage and cluster spacing through modeling studies and field tests. Finally, the study concludes with a recommended approach to manage fracture hits. There is no silver bullet, and the problem of fracture hits in each shale play is unique, but by using the available data and published knowledge to understand how fractures propagate downhole, measures can be taken to minimize or even completely avoid fracture hits.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (1.00)
- Europe (1.00)
- (2 more...)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.48)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Understanding the Role of Well Sequencing in Managing Reservoir Stress Response in the Permian: Implications for Child-Well Completions Using High-Resolution Microseismic Analysis
Chittenden, Hannah (Diamondback Energy) | Cannon, Dave (Diamondback Energy) | Jeziorski, Katie (ESG Solutions) | Bowman-Young, Sheri (ESG Solutions) | Smith-Boughner, Lindsay (ESG Solutions)
Abstract In this case study, three sequential well pads were designed, stimulated and monitored to evaluate 1. Treatment order of stacked wells across multiple benches, 2. Completions optimization in proximity to a parent well and 3. The efficacy of treatment sequence in proximity to parent wells. Microseismic data were evaluated in conjunction with tracer and pressure data to provide a more detailed understanding of reservoir deformation and well connectivity using statistical approaches that consider the collective behavior of seismicity. High-resolution microseismic involves analyzing spatio-temporal trends in seismicity rather than reliance on microseismic event clouds to provide more meaningful assessment of hydraulically-linked seismicity vs. stress-driven seismicity. The findings of the first two case studies were applied to the stimulation of the third well pad to demonstrate the role of well sequencing in proximity to depleted zones and the impacts of completions design in managing well communication. Here we discuss the benefit of high-resolution microseismic in assessing perceived well interference by delineating the difference between hydraulically-linked and stress-driven seismicity recorded during multi-well hydraulic fracturing programs. In applying knowledge of reservoir deformation processes to customize stimulation programs, operators have additional tools to help manage reservoir stress, limit unwanted well communication and optimize production.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (31 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
Successful cement placement in horizontal wellbores requires solutions for several technical challenges. Zonal isolation provided by cement is considered an important factor for efficient stimulation. A cement system was designed and recently introduced in unconventional developments to mitigate hydraulic isolation challenges encountered when cementing horizontal wellbores. Herein, we disclose recent results that show the efficiency of the interactive cementing system (ICS) in both laboratory and field case studies. Specifically, decreased communication between stages and improved production compared to offsets. At the 2018 SPE Annual Technical Conference, Kolchanov et al. described the ICS improving zonal isolation in wells that would otherwise contain mud channels symptomatic of the cleaning methods used in unconventional developments (SPE-191561-MS). The scaled performance tests disclosed in that publication are further evaluated to build on the relationship between the laboratory test and realistic downhole scenarios. Literature data indicate that >30% of stages have communications with previously treated zones. The ICS was shown to eliminate interstage communication during stimulation operations when compared to conventional cement systems. To investigate the effect of the ICS on completion quality, five wells cemented with the ICS and stimulated by multistage hydraulic fracturing were compared with numerous offset wells drilled, cemented, and stimulated during the last 2 years in the same producing zone within a 10-mile radius. The early normalized production data have been analyzed, and they indicate a statistically significant increase of production for the ICS-treated wells. This shows the importance of an integrated approach in well construction process, especially for challenging horizontal wells.
- North America > United States > Texas (1.00)
- Asia > Middle East (0.68)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- 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)
- (33 more...)
Dimensionless Section-Level Cumulative Oil Vs. Pumped Fluid Normalization Plot in Unconventional Development
Rosenhagen, Nicolas M. (Colorado School of Mines) | Nash, Steven D. (Anadarko Petroleum Corporation) | Dobbs, Walter C. (Anadarko Petroleum Corporation) | Tanner, Kevin V. (Anadarko Petroleum Corporation)
Abstract The volume of stimulation fluid injected during hydraulic fracturing is a key performance driver in the horizontal development of the Niobrara formation in the Denver-Julesburg (DJ) Basin, Colorado. Oil production per well generally increases with stimulation fluid volume. Often, operators normalize both production and fluid volume based on stimulated lateral length and investigate relationships using "per-ft" variables. However, data from well-based approaches commonly display such wide distributions that no useful relationships can be inferred. To improve data correlations, multivariate analysis normalizes for parameters such as thermal maturity, depth, depletion, proppant intensity, drawdown, geology and completion design. Although advancements in computing power have decreased cycle times for multivariate analysis, preparing a clean dataset for thousands of wells remains challenging. A proposed analytical method using publicly available data allows interpreters to see through the noise and find informative correlations. Using a data set of over 5000 wells, we aggregate cumulative oil production and stimulation fluid volumes to a per-section basis then normalize by hydrocarbon pore volume (HCPV) per section. Dimensionless section-level Cumulative Oil versus Stimulation Fluid Plots ("Normalization" or "N-Plot") present data distributions sufficiently well-defined to provide an interpretation and design basis of well spacing and stimulation fluid volumes for multi-well development. When coupled with geologic characterization, the trends guide further refinement of development optimization and well performance predictions. Two example applications using the N-Plot are introduced. The first involves construction of predictive production models and associated evaluation of alternative development scenarios with different combinations of well spacing and completion fluid intensity. The second involves "just-in-time" modification of fluid intensity for drilled but uncompleted wells (DUC's) to optimize cost-forward project economics in an evolving commodity price environment.
- North America > United States > Wyoming (1.00)
- North America > United States > Colorado (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Geology > Geological Subdiscipline > Stratigraphy (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- North America > United States > Wyoming > Niobrara Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- (48 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Management > Energy Economics > Unconventional resource economics (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (0.94)
- (2 more...)
Case Study of a Landing Location Optimization within a Depleted Stacked Reservoir in the Midland Basin
Defeu, Cyrille (Schlumberger) | Williams, Ryan (Schlumberger) | Shan, Dan (Schlumberger) | Martin, Joel (Diamondback Energy) | Cannon, Dave (Diamondback Energy) | Clifton, Kyle (Diamondback Energy) | Lollar, Chad (Diamondback Energy)
Abstract Unconventional plays across the US are often made of stacked pays, typically ranging from a few hundred to thousands of feet thick. These stacked pay intervals are generally segregated into different formations as dictated by differences in geology, mineralogy, rock fabric, and fluid type. This proves to be a challenge because many stacked/staggered horizontal wells are required to provide effective coverage of the reservoir. Selecting the right landing location can become even more challenging in an environment with existing producing wells in adjacent formations because pressure depletion and its associated effects on fracture propagation necessitate consideration of vertical spacing and time. In this study, we outline an integrated approach that addresses a four-dimensional horizontal well placement challenge in the Midland basin's Wolfcamp A formation using advanced hydraulic fracture modeling to calibrate hydraulic fracture geometries and history match five producing wells in both Lower Spraberry and Wolfcamp B. The optimal landing location within the Wolfcamp A was determined based on an assessment of reservoir quality, rock mechanics, unique structural features, and depletion effects. These data were then combined to form a 4D geomodel that enabled a completion optimization study via modeling of the resulting complex hydraulic fracture geometry and subsequent hydrocarbon production. This integrated workflow, using a wide array of high-quality datasets and the input of experts from multiple disciplines, yielded a comprehensive assessment and clear recommendations for this challenging partially depleted stacked pay interval. Although this study is specific to the Midland basin's Lower Spraberry and Wolfcamp A and B formations, many sections of the workflow apply to other basins and their unique strata.
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.31)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- (4 more...)
Abstract Unconventional completions in North America have seen a paradigm shift in volumes of proppant pumped since 2014. There is a clear noticeable trend in both oil prices and proppant volumes – thanks to low product and service costs that accompanied the oil price crash in early 2015. As the industry continues to recover, operators are reevaluating completion designs to understand if these proppant volumes are beyond what is optimal. This paper analyzes trends in completion sizes and types across all major unconventional oil and gas plays in the US since 2011 and tracks their impact on well productivity. Completion and production data since 2011 from more than 70,000 horizontal wells in seven major basins (Gulf Coast, Permian, Appalachian, Anadarko, Haynesville, Williston and Denver Julesburg basins) and 11 major oil/gas producing formations were analyzed to examine developments in proppant and fluid volumes. Average concentration of proppant per gallon of fluid pumped was used to understand transitional trends in fracturing fluid types with time. Production performance indicators such as First month, Best 3 or Best 12 months of oil and gas production were mapped against completion volumes to evaluate if there are added economic advantages to pumping larger designs. In general, all major basins have seen progressive improvements in average well performance since 2011, with the Permian Basin showing the highest improvement, increasing from an average first-six-months oil production of 25,000 bbl in 2011 to 75,000 bbl in 2017. The Gulf Coast basin, where the Eagle Ford formation is located, has seen a 6-fold increase in proppant volumes pumped per foot of lateral since 2011 while the Permian and Appalachian basins hit peak proppant volumes in 2015 and 2016 respectively. In Permian and Eagleford wells, higher proppant volumes in general have resulted in better production up to a certain concentration. In Williston and Denver basins, most operators are moving away from gelled fluids, and reduced average proppant concentration per fluid volume pumped shows inclination toward hybrid or slickwater designs. While some of these observations are tied to reservoir quality, proppant volumes have begun to peak as operators have either reached an optimal point or are in the process of reducing volumes. Demand for proppant is expected to nearly double by 2020. As oil prices continue to recover, well AFEs continue to increase, despite multiple efforts to improve capital efficiency. The need for enhanced fracture conductivity and extended half-lengths on EURs are been discussed by combining actual observed production data and sensitivities using calibrated production models. The industry is moving toward large-volume slickwater fracturing operations using smaller proppants, but he operating landscape is expected to see a correction when such designs become less economical.
- North America > United States > Texas (1.00)
- North America > United States > Oklahoma (1.00)
- North America > United States > North Dakota (1.00)
- (4 more...)
- Phanerozoic > Paleozoic > Permian (1.00)
- Phanerozoic > Paleozoic > Devonian (0.93)
- Phanerozoic > Paleozoic > Carboniferous > Mississippian (0.69)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.94)
- Geology > Structural Geology > Tectonics (0.69)
- (2 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Wyoming > Niobrara Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (97 more...)