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Collaborating Authors
Fort Worth Basin
Numerous surface-felt earthquakes have been spatiotemporally correlated with hydraulic fracturing operations. Because large deformations occur close to hydraulic fractures (HFs), any associated fault reactivation and resulting seismicity must be evaluated within the length scale of the fracture stages and based on precise fault location relative to the simulated rock volumes. To evaluate changes in Coulomb failure stress (CFS) with injection, we conducted fully coupled poroelastic finite-element simulations using a pore-pressure cohesive zone model for the fracture and fault core in combination with a fault-fracture intersection model. The simulations quantify the dependence of CFS and fault reactivation potential on host-rock and fault properties, spacing between fault and HF, and fracturing sequence. We find that fracturing in an anisotropic in-situ stress state does not lead to fault tensile opening but rather dominant shear reactivation through a poroelastic stress disturbance over the fault core ahead of the compressed central stabilized zone. In our simulations, poroelastic stress changes significantly affect fault reactivation in all simulated scenarios of fracturing 50-200 m away from an optimally oriented normal fault. Asymmetric HF growth due to the stress-shadowing effect of adjacent HFs leads to 1.) a larger reactivated fault zone following simultaneous and sequential fracturing of multiple clusters compared to single-cluster fracturing; and 2.) larger unstable area (CFSgt;0.1) over the fault core or higher potential of fault slip following sequential fracturing compared to simultaneous fracturing. The fault reactivation area is further increased for a fault with lower conductivity and with a higher opening-mode fracture toughness of the overlying layer. To reduce the risk of fault reactivation by hydraulic fracturing under reservoir characteristics of the Barnett Shale, the Fort Worth Basin, it is recommended to 1.) conduct simultaneous fracturing instead of sequential; and 2.) to maintain a minimum distance of ~ 200 m for HF operations from known faults.
- North America > Canada (1.00)
- North America > United States > Texas > Travis County > Austin (0.28)
- North America > United States > Texas > Tarrant County > Fort Worth (0.24)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (1.00)
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- (2 more...)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- (51 more...)
ABSTRACT We compare microseismic observations against pumping information, landing heights, and various well logs. The data were acquired during cyclic-steam injection between September 2002 and December 2005. Ninety-five percent of the microseismicity occurred during injection and in the overburden; 70% of the events happened during the first cycle. Microseismicity in the overburden is likely caused by a greater brittleness than in the reservoir and a cluster of microseismic events in regions with a smaller landing height, thereby facilitating dry cracking due to the volumetric expansion of the reservoir. Yet, other areas with equally shallow landing heights displayed little to no microseismicity, pointing to an inhomogeneous steam front. Furthermore, recorded microseismicity is subject to the Kaiser effect in that event rates are low in subsequent cycles until the current injection pressure exceeds the previous maximum, explaining why 70% of the events occurred during the first cycle and possibly why microseismicity during production accounted for only 5%. Microseismicity in brittle formations can be caused by pore-pressure variations (wet cracking) and/or changes in the total stresses (dry cracking). Identification of pore-pressure variations in the overburden is important because it may indicate containment challenges. Analysis of the growth rate of the microseismic cloud combined with the shallow landing height indicated dry cracking to be more likely than wet cracking but analysis of additional data is required to strengthen this conclusion.
- North America > Canada > Alberta (1.00)
- Europe (0.93)
- North America > Canada > British Columbia (0.68)
- Geology > Sedimentary Geology (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.46)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Greater Peace River High Basin > Debolt Formation (0.99)
- North America > Canada > British Columbia > Peace River Field (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
Quantitative characterization of organic and inorganic pores in shale based on deep learning
Yan, Bohong (China University of Petroleum) | Sun, Langqiu (China University of Petroleum) | Zhao, Jianguo (China University of Petroleum) | Cao, Zixiong (Object Research Systems (ORS) Company) | Li, Mingxuan (China University of Petroleum) | Shiba, K. C. (China University of Petroleum) | Liu, Xinze (Yumen Oil Field Branch of China National Petroleum Corporation (CNPC) Exploration and Development Research Institute) | Li, Chuang (China National Petroleum Corporation (CNPC))
ABSTRACT Organic matter (OM) maturity is closely related to organic pores in shales. Quantitative characterization of organic and inorganic pores in shale is crucial for rock-physics modeling and reservoir porosity and permeability evaluation. Focused ion beam-scanning electron microscopy (FIB-SEM) can capture high-precision three-dimensional (3D) images and directly describe the types, shapes, and spatial distribution of pores in shale gas reservoirs. However, due to the high scanning cost, wide 3D view field, and complex microstructure of FIB-SEM, more efficient segmentation for the FIB-SEM images is required. For this purpose, a multiphase segmentation workflow in conjunction with a U-net is developed to segment pores from the matrix and distinguish organic pores from inorganic pores simultaneously in the entire 3D image stack. The workflow is repeated for FIB-SEM data sets of 17 organic-rich shales with various characteristics. The analysis focuses on improving the efficiency and relevance of the workflow, that is, quantifying the minimum number of training slices while ensuring accuracy and further combining the fractal dimension (FD) and lacunarity to study a simple and objective method of selection. Meanwhile, the computational efficiency, accuracy, and robustness to noise of the 2D U-net model are discussed. The intersection over the union of automatic segmentation can amount to 80%–95% in all data sets with manual labels as ground truth. In addition, calculated by the FIB-SEM multiphase segmentation, the organic porosity is used to quantitatively evaluate the OM decomposition level. Deep-learning-based segmentation shows great potential for characterizing shale pore structures and quantifying OM maturity.
- Asia > China (1.00)
- North America > United States > Texas (0.68)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Neural networks (1.00)
Research on focal mechanism of microseismic events and the regional stress during hydraulic fracturing at a shale play site in southwest China
Chen, Xin-Xing (Chengdu University of Technology) | Meng, Xiao-Bo (Chengdu University of Technology) | Chen, Hai-Chao (China University of Petroleum) | Chen, Xin-Yu (Chengdu University of Technology) | Li, Qiu-Yu (Optical Science and Technology (Chengdu) Ltd.) | Guo, Ming-Yu (Chengdu University of Technology)
ABSTRACT We develop a waveform-matching inversion method to determine the focal mechanism of microseismic events recorded by a single-well observation system. Our method uses the crosscorrelation technique to mitigate the influence of anisotropy on the S wave. Then, by conducting a grid search for strike, dip, and rake, we match the observed waveforms of P and S wave with the corresponding theoretical waveforms. A synthetic test demonstrates the robustness and accuracy of our method in resolving the focal mechanism of microseismic events under a single-well observation system. By applying our method to the events that have been categorized into two clusters based on spatial and temporal evolution recorded during the hydraulic fracturing operation in the Weiyuan shale reservoir, we observe that the two clusters have distinct focal mechanism and stress characteristics. The events in the remote cluster (cluster A) exhibit consistent focal mechanisms, with a concentrated distribution of P-axis orientations. The inverted maximum principal stress direction of cluster A aligns with the local maximum principal stress direction (). This implies that events in cluster A occur in a uniform stress condition. In contrast, the other cluster (cluster B) near the injection well exhibits significant variation in focal mechanisms, with a scattered distribution of P-axis orientations. The inverted maximum principal stress direction deviates from local maximum principal stress direction (), indicating that events in cluster B occur in a more complicated stress condition.
- North America > Canada > Alberta (0.47)
- North America > United States > Texas (0.47)
- Asia > China > Sichuan Province (0.29)
- Geology > Geological Subdiscipline > Geomechanics (0.94)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.50)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > West Pembina Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Pembina Field > Viking Formation (0.99)
- (2 more...)
Generating 3D lithology probability volumes using poststack inversion, probabilistic neural networks, and Bayesian classification — A case study from the mixed carbonate and siliciclastic deposits of the Cisco Group of the Eastern Shelf of the Permian Basin, north-central Texas
Karakaya, Sarp (The University of Texas at Austin, The University of Texas at Austin) | Ogiesoba, Osareni C. (The University of Texas at Austin) | Olariu, Cornel (The University of Texas at Austin, Research National Institute of Marine Geology and Geo-ecology (GeoEcoMar)) | Bhattacharya, Shuvajit (The University of Texas at Austin)
ABSTRACT The deposition and mixing of carbonates and siliciclastics in the Cisco Group of the Eastern Shelf of the Permian Basin are complicated by the temporal overlap between icehouse eustatic sea-level oscillations and fluctuations in sediment influx due to the rejuvenation of the Ouachita fold belt. Previous investigators have used well-log correlation as the primary tool in their interpretations of the area’s reciprocal depositional model, but well-log correlation alone cannot explain the full range of spatial lithology variations in the system. To better understand the lithology variation in the area, we use an integrated technique that combines wireline log information from 17 wells with 625 km 3D seismic data through poststack seismic inversion, probabilistic neural networks (PNNs), and Bayesian classification. We use deterministic matrix inversion to derive lithology classes from well logs. Crossplot analyses reveal that the acoustic impedance and neutron porosity log pair can be used to differentiate lithologies. We perform model-based poststack inversion to generate a P-impedance volume and use PNNs to generate a neutron porosity volume. We combine these volumes through supervised Bayesian classification to generate lithology probability volumes for each lithology and a most probable lithology volume throughout the seismic data. The lithology volumes highlight the dominant lithologies (carbonate, shale, sand, and mixed) that allowed the interpretation of major carbonate platforms, sand-to-shale ratio variations, carbonate buildups between wells, and channel fill lithologies. Our semiautomated lithology detection workflow applies to regional studies and is also valid for reservoir-scale studies to determine variations in lithologies.
- Phanerozoic > Paleozoic > Permian (1.00)
- Phanerozoic > Paleozoic > Carboniferous > Pennsylvanian (0.48)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.69)
- Geophysics > Seismic Surveying > Seismic Processing > Seismic Migration (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- Geophysics > Borehole Geophysics (1.00)
- North America > United States > Wyoming > Uinta Basin (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)
- (45 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (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)
ABSTRACT The lack of knowledge of lateral heterogeneity in unconventional reservoirs commonly has negative impacts on drilling, completion efficiency, and production. However, current methods, such as well logging and seismic surveying, are limited in their ability to characterize unconventional reservoirs. We develop an alternative geophysical approach that uses distributed acoustic sensing (DAS) and perforation shots to characterize unconventional reservoirs. In our field data set, DAS-recorded perforation shots show strong P-wave signals. The recorded P-wave waveforms from the study area exhibit dispersive behavior, which can be clearly identified after signal processing. The spatial variations in phase velocity along the horizontal wellbore can be reliably measured by averaging the measurements from multiple closely situated perforation shots. We observe a low phase-velocity zone along the study well, which is spatially consistent with the well logs and root mean square amplitude extracted from the 3D seismic volume. The observed dispersive behavior of P waves is validated through numerical modeling. By comparing the results from the proposed method with those from modeling results and other measurements, we conclude that the proposed method results in a reasonable radius of investigation for unconventional reservoir characterization. The method also has the potential to infer hydraulic fracturing effectiveness by comparing the phase-velocity difference before and after stimulation. The data acquisition of the proposed workflow can be combined with perforation shot operations, which provides a cost-effective and suitable approach to investigating lateral heterogeneity in unconventional reservoirs.
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying > Vertical Seismic Profile (VSP) (0.68)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Codell Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- (4 more...)
ABSTRACT We compare microseismic observations against pumping information, landing heights, and various well logs. The data were acquired during cyclic-steam injection between September 2002 and December 2005. Ninety-five percent of the microseismicity occurred during injection and in the overburden; 70% of the events happened during the first cycle. Microseismicity in the overburden is likely caused by a greater brittleness than in the reservoir and a cluster of microseismic events in regions with a smaller landing height, thereby facilitating dry cracking due to the volumetric expansion of the reservoir. Yet, other areas with equally shallow landing heights displayed little to no microseismicity, pointing to an inhomogeneous steam front. Furthermore, recorded microseismicity is subject to the Kaiser effect in that event rates are low in subsequent cycles until the current injection pressure exceeds the previous maximum, explaining why 70% of the events occurred during the first cycle and possibly why microseismicity during production accounted for only 5%. Microseismicity in brittle formations can be caused by pore-pressure variations (wet cracking) and/or changes in the total stresses (dry cracking). Identification of pore-pressure variations in the overburden is important because it may indicate containment challenges. Analysis of the growth rate of the microseismic cloud combined with the shallow landing height indicated dry cracking to be more likely than wet cracking but analysis of additional data is required to strengthen this conclusion.
- North America > Canada > Alberta (1.00)
- Europe (0.93)
- North America > Canada > British Columbia (0.68)
- Geology > Sedimentary Geology (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.46)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Greater Peace River High Basin > Debolt Formation (0.99)
- North America > Canada > British Columbia > Peace River Field (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
The Drake Well is a 69.5-foot-deep (21.2 m) oil well in Cherrytree Township, Venango County in the U.S. state of Pennsylvania, the success of which sparked the first oil boom in the United States. The well is the centerpiece of the Drake Well Museum located 3 miles (5 km) south of Titusville.[1] Drilled by Edwin Drake in 1859, along the banks of Oil Creek, it is the first commercial oil well in the United States. Drake Well was listed on National Register of Historic Places and designated a National Historic Landmark in 1966. It was designated a Historic Mechanical Engineering Landmark in 1979.
- North America > United States > Texas > Fort Worth Basin > Brewer Field (0.89)
- North America > United States > Louisiana > Watson Field (0.89)
- North America > United States > California > Oil Creek Field (0.89)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
In-Basin Sand Performance in the Permian Basin and the Case for Northern White Sand
Malone, M. R. (New Auburn Energy Management, LLC., Houston, TX, United States of America) | Bazan, L. W. (Bazan Consulting, Inc., Houston, TX, United States of America) | Eckart, M. J. (Bazan Consulting, Inc., Houston, TX, United States of America)
Abstract Proppant selection, and the resulting dimensionless fracture conductivity, impacts well performance. Proppant quality standards were developed to quantify proppant performance using dimensionless fracture conductivity, correlating the flow potential of the propped fracture relative to the formation. Since 2018, there has been a near complete switch to in-basin sand (IBS) for completing oil and gas wells in the Permian Basin. The switch to IBS has primarily been based on the idea that overall well and field economics are improved because: 1) capital costs are lowered by sourcing sand locally reducing costs and logistics, and 2) well results using IBS were "good enough" in terms of well performance justifying the use of inferior proppants. Little regard is given to the long-term production impacts, field development value and cumulative free cash flow over a five-to-ten-year horizon. Rystad Energy (2022) evaluated 850 wells from seven operators in both the Midland and Delaware basins and provided clear evidence that the perceived benefits of using IBS to complete Wolfcamp A (WCA) wells in the Permian is not accurate. The Rystad Energy studies will be reviewed in detail. This manuscript presents extensive hydraulic fracture modeling and production simulations of the WCA formation for both the Delaware and Midland basins using 100- and 40/70-mesh to identify the conductivity difference between IBS and NWS to provide an engineering basis for the Rystad Energy results. Conductivity differences for each mesh and sand type ultimately allowed a comparison of well production and net cash flow for P50 wells. The WCA production forecast cases were calibrated to the published Rystad Energy data, where possible, and EUR values. The payout, cumulative production differences and net cash flow are presented comparing IBS and NWS materials. Comparing results between NWS and IBS provides an engineering basis that NWS characteristics drive superior well performance in the Permian basin. As fracture conductivity increases, either from using NWS material or larger mesh sizes, the well production also increases over time. This is also the general conclusion from the Rystad study. This work demonstrates that NWS, while more expensive upfront, performs better throughout the well life, and is almost always the better economic choice and shows a long-term benefit using NWS. Utilizing IBS in the Permian basin results in suboptimal cashflow and reduced long-term profitability. The well performance using IBS is expected to progressively worsen over time. This work demonstrates fractures in the Permian basin are conductivity limited and using IBS negatively affects cash flow and long term well deliverability. NWS is a superior product to IBS and generates enhanced fracture conductivity and production in the Delaware and Midland basins.
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Geology > Mineral (0.46)
- North America > United States > Texas > Permian Basin > Midland Basin > Wolfcamp A Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.94)
- (26 more...)
A Comprehensive Review of Casing Deformation During Multi-Stage Hydraulic Fracturing in Unconventional Plays: Characterization, Diagnosis, Controlling Factors, Mitigation and Recovery Strategies
Uribe-Patino, J. A. (University of Alberta) | Casero, A. (bp) | Dall'Acqua, D. (Noetic Engineering) | Davis, E. (ConocoPhillips) | King, G. E. (GEK Engineering) | Singh, H. (CNPC USA) | Rylance, M. (IXL Oilfield Consulting) | Chalaturnyk, R. (University of Alberta) | Zambrano-Narvaez, G. (University of Alberta)
Abstract The objective of this paper is to provide a review of casing deformations that are related to the placement of Multi-Stage Hydraulic Fracturing (MSHF) in unconventional plays. This work aims to identify practical mitigation and management strategies to reduce the overall impact of such events on the economic outcome of any development. The methodology incorporates a comprehensive literature review and leverages insights from the authors’ extensive field experience. This approach aims to explore the current state of knowledge regarding casing deformations associated with MSHF in unconventional reservoirs across key global basins. This paper encompasses the identification, diagnostics, surveillance, and monitoring of such deformations as they manifest and progress, along with the implementation of mitigation and management strategies prior to and during the well-completion process. The authors recognize the disparity between the number of publications available and the actual incidence of casing deformation in specific basins and are conscious that obtaining an exact estimate may often be elusive. The technical aspects of the review rely on the examination of numerous case studies from various unconventional basins. This is achieved by establishing a comprehensive understanding of the potential causes and mechanisms of casing deformations, including their occurrence, detection, and identification. Subsequently, an analysis is performed that presents the inherent characteristics of the different types of casing deformation, encompassing their nature, severity, distribution, and frequency across the basins considered, their lateral locations, event occurrence, specific nature and other pertinent factors. Additionally, the review addresses the geological, geo-mechanical, engineering and operational control factors that are likely to contribute to such deformations. Furthermore, it identifies a range of potential mitigation strategies aimed at minimizing the occurrence and ultimately the economic effects of casing deformation occurrence. This review builds upon various ongoing industry technical initiatives undertaken by the SPE Well Integrity Technical Section - Casing Deformation Work Group. The study findings can potentially provide practical measures to manage and mitigate casing deformation in unconventional basins within horizontal wells, thus minimizing the associated economic impact. Remaining knowledge gaps that require consideration should be addressed by actively sharing best practices and case histories within the industry on a global scale. This collaborative review paper, involving operating companies and other experts, serves as an initial step in that direction, aiming to catalyse further discussion among professionals working in this sector. It is intended as a rallying cry to encourage broader participation, deeper and shared consideration of the considerable effects of casing deformation occurrence.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (1.00)
- Asia > Middle East (1.00)
- (5 more...)
- Geology > Structural Geology (1.00)
- 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 (0.50)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- Oceania > Australia > Northern Territory > McArthur Basin > Beetaloo Basin (0.99)
- North America > United States > Wyoming > Powder River Basin (0.99)
- (71 more...)
- Information Technology > Knowledge Management (0.46)
- Information Technology > Communications (0.46)