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Abstract Multi-stage, multi-well completions cause pore-pressures to increase around each stage treated, compound from earlier offset treatment stages, then dissipate as the injected fluid leaks off into the rock formation. Rock stresses change in a dynamic fashion from virgin reservoir stress to an altered stress influencing subsequently treated stages which can restrict slurry propagation from these injections into regions experiencing excess stress. Stress shadows are time-dependent and dissipate over time and return to the virgin stress state. Microseismic focal mechanisms detected from a high-fold wide azimuth surface array can be used to observe and calculate stress changes in the reservoir and constrain the time it takes for stresses to return to the virgin reservoir state. Operators can take advantage of stress changes and contain fractures close to the stages by building stress wedges around subsequently treated stages. After stress dissipates fluid propagates into previously opened fractures leading to poor fracture containment. In this paper, we review the effects of time-dependent stress shadows on multi-well completions in the Wolfcamp Formation in Southeast New Mexico. Then radioactive tracer data from the Niobrara Formation in the Denver-Julsburg basin is analyzed to provide further verification of the time-dependent process. Increased stresses from previous treatments remain elevated for ∼7 days which push fluid injected on neighboring wells away from the stress shadow. Production of well-specific tracer corroborates the hypothesis that local stress-shadows are elevated for ∼7 days which can push fluid from subsequent neighboring wells. After stresses dissipate through the fractures created during the initial stimulation, new tracer on offset wells was produced as much as 3,000 ft away on a neighboring well. Introduction Microseismic monitoring is a proven technology for observing and mapping reservoir response to hydraulic fracture stimulations. The event radiation pattern of the P-wave first arrival reveals advanced characteristics of the fracture describing deformation at the source location when detected using a high-fold wide azimuth surface array. The full-moment tensor can be generally decomposed into the relative percentages of isotropic, double couple and compensated linear vector dipole components (e.g. Aki and Richards, 1980) which fully describes the failure process in terms of volume change, amount of shearing, and other complexities related to deformation. The local stress field can be calculated using a set of focal mechanisms by minimizing the misfit angle between the modeled stress field and the observed focal mechanism slip vectors (Angelier, 1989) where the local stress field extent is defined by the spatial extent of the observed focal mechanisms. The local stress field orientation and relative magnitude can be resolved for a group of microseismic focal mechanisms by minimizing the misfit angle between the modeled stress field and the observed focal mechanism slip vectors for the subsets using a method described by Vavrycuk, 2014.
- North America > United States > New Mexico (0.55)
- North America > United States > Texas (0.35)
- North America > United States > Wyoming (0.34)
- (3 more...)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (7 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Tracer test analysis (1.00)
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)
Discrete Measurements of the Least Horizontal Principal Stress from Core Data: An Application of Viscoelastic Stress Relaxation
McCormack, Kevin L. (Energy and Geoscience Institute, University of Utah) | McLennan, John D. (Energy and Geoscience Institute, University of Utah) | Jagniecki, Elliot A. (Utah Geological Survey) | McPherson, Brian J. (Energy and Geoscience Institute, University of Utah (Corresponding author))
Summary The emerging Paradox Oil Play in southeastern Utah is among the most significant unconventional plays in the western USA. The mean total undiscovered oil resources within just the Pennsylvanian Cane Creek interval of the Paradox Basin are believed to exceed 215 million barrels. However, to date, less than 5% (~9 million barrels) of the total Cane Creek resource has been produced from fewer than 40 wells, and only approximately one-half of those are horizontal wells. More than 95% of production is from the central Cane Creek Unit (CCU). Natural fractures are a key feature of many production wells, but stimulation by induced hydraulic fractures is not consistently successful. We hypothesize that more effective production in this play will rely on better fundamental characterization, especially on better quantification of the state of stress. Approximately 110 ft of core, well logs, and a diagnostic fracture injection test (DFIT) were acquired from the State 16-2 well within the CCU. With these data, we applied two methods to constrain and clarify the state of stress. The first technique, the Simpson’s coefficient method, provides lower bounds on the two horizontal principal stresses and relies on only limited data. Alternatively, the viscoelastic stress relaxation (VSR) method is used to estimate the least horizontal principal stress, building on observations that principal stresses become more isotropic as the viscous behavior of a rock is more pronounced. Results of these two methods support the hypothesis that the state of stress in the CCU of the Paradox Basin is nearly lithostatic and isotropic. Other factors consistent with this hypothesis include high formation pore pressure, which tends to reduce the possible stress states by changing the frictional failure equilibrium; lack of induced fractures in the core, which should be present in the case of stress anisotropy; and interbedded halite layers, which given their high degree of ductility, probably lead to greater VSR for the entire sedimentary package.
- North America > United States > Utah (1.00)
- North America > United States > Colorado (1.00)
- Phanerozoic > Paleozoic > Carboniferous > Pennsylvanian (1.00)
- Phanerozoic > Mesozoic (0.93)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.93)
- (3 more...)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (0.66)
- 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)
- (23 more...)
- Well Drilling > Drilling Operations (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- (2 more...)
Summary Evaluating hydraulic fracturing completion is critical for low porosity, low permeability unconventional reservoir development. In this study, we use low-frequency distributed acoustic sensing (LF-DAS) measurements to monitor the hydraulic fracturing in the Chalk Bluff field in the Denver-Julesburg (DJ) Basin, Colorado. Interpreting fracture-hits from crosswell LF-DAS data yields insights into the fracture geometry and propagation across and within two targeted formations: Niobrara and Codell. We observe significant differences in hydraulic fracture propagation between the two formations; the half length of hydraulic fractures in the Codell formation is much longer than that in the Niobrara. In addition, hydraulic fracture propagates significantly faster in Codell than in Niobrara under the same pumping rate. The differences could be explained by higher natural fracture density and potentially lower stress anisotropy in the Niobrara formation. We also observed different fracture orientations between the two formations and inconsistent fracture orientations within Niobrara. Hydraulic fractures observed in Codell oriented at 100 degree consistently, while two group of fracture azimuths (110 and 240 degrees) can be observed in Niobrara. The difference in fracture orientations in Niobrara and Codell indicates stress regime changes between the formations. The inconsistency of fracture azimuth in Niobrara may be caused by the zipper fracturing sequence. Strong cross-formation fracture connections between the two formations can also be observed, with different up-going and down-going fracture propagation velocities. These observations help us better understand the complex fracture geometry in the DJ Basin and provide critical constraints on the optimization of the unconventional reservoir development.
- North America > United States > Wyoming (1.00)
- North America > United States > Colorado (1.00)
- 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)
- (33 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
ABSTRACT: In this study, a special focus was dedicated to the effect of elastic anisotropy of shales on the in-situ stress contrast between different layers and its implications on the vertical containment of hydraulic fractures (HF) and how they relate to the widely observed fracture driven interaction (FDI) phenomena and undesirable HF height growth. The reported elastic and mechanical properties of the main members of the Bakken petroleum system in the Williston Basin (i.e. Upper and Lower Bakken Shale, Middle Bakken, and Three Forks) were used to estimate the in-situ stresses based on anisotropic rock properties and use the minimum horizontal stress profile for HF modeling. The estimated stress profile appeared to be very different from the one calculated based on the isotropic formation assumption. The anisotropic stress model, as reported by other researchers, is more realistic in transversely isotropic rocks and rocks with a high volume of clay and TOC and generated more reliable results that conform better with other indicators and observations from other types of data associated with HF geometry. 1. INTRODUCTION Accurate estimation of the minimum principal in-situ stress is a milestone in the successful design of hydraulic fracturing (HF) jobs (Ganpule et al., 2015). The role of accurate stress variations with depth becomes more pronounced where HF is performed in different horizons to explore what is called stacked pay. Estimation of in-situ horizontal stresses is mainly attributed to the inherently simplistic assumptions of the commonly used stress models (Zoback, 2007). However, the revolution in the oil and gas industry due to production from Shale plays indicated the necessity of using anisotropic, or what is so-called as transverse isotropic (TI) assumption for the different geological layers for improved estimation of the horizontal stresses. In this study, we showcased the importance of laboratory characterization of the elastic and mechanical properties for accurate prediction of stress profiles and how they can change our designs and improve the profitability of our investments by generating more reliable stress models that are coherent with what is indicated by other types of data. This can serve as a strong base for improved planning. This is proved through our case study performed using data from the Bakken petroleum system in the Williston Basin. It was found that the HF geometries predicted from simulation using a well-calibrated anisotropic stress model strongly agreed with HF geometries observations from microseismic data reported in many other studies such as McKimmy et al. (2022) and Lorwongngam et al. (2018).
- North America > United States > South Dakota (1.00)
- North America > United States > North Dakota (1.00)
- North America > United States > Montana (1.00)
- (2 more...)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.59)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Oil Play (0.37)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Three Forks Group Formation (0.99)
- (12 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
A case study of vertical hydraulic fracture growth, stress variations with depth and shear stimulation in the Niobrara Shale and Codell Sand, Denver-Julesburg Basin, Colorado
McCormack, Kevin L. (University of Utah) | Zoback, Mark D. (Stanford University) | Kuang, Wenhuan (Southern University of Science and Technology)
Abstract We have carried out a geomechanical study of three wells, one each in the Niobrara A, Niobrara C, and Codell Sandstone to investigate how the state of stress and stress variations with depth affect vertical hydraulic fracture growth and shear stimulation of preexisting fractures. We determine that the higher magnitudes of measured least principal stress values in the Niobrara A and C shales are the result of viscoplastic stress relaxation. Using a density log and a vertical transverse isotropy velocity model developed to accurately locate the microseismic events, we theoretically calculated a continuous profile of the magnitude of the least principal stress with depth. This stress profile explains the apparent vertical hydraulic fracture growth as inferred from the well-constrained depths of the associated microseismic events. Finally, we determine that because of the upward propagation of hydraulic fractures from the Niobrara C to the Niobrara A, the latter formation experienced considerably more shear stimulation, which may contribute to the greater production of oil and gas from that formation.
- 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 (0.73)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Nebraska > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- (10 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
ABSTRACT: We carried out a geomechanical study of three, co-located wells in the DJ Basin of Colorado, one each in the Niobrara A, Niobrara C and Codell sandstone, to investigate how stress variations of the least principal stress with depth affect vertical hydraulic fracture growth and shear stimulation of pre-existing fractures. We demonstrate that the change in stratigraphic depth along the lateral portion of the Niobrara A well causes it to traverse regions of both high and low values of the least principal stress. As a result of this, the implications of microseismic data for hydraulic fracture growth near the heel and toe of the well are noticeably different. Specifically, upward hydraulic fracture growth from stages near the heel of the well (where the least principal stress is higher) is more pronounced than those near the toe. In addition, in the Codell sandstone, which is in a state for normal faulting frictional equilibrium, injection-related shear events start sooner than in the Niobrara A and C, which require higher pore pressure to stimulate shear slip. 1. Introduction In this paper we report a geomechanical study principally related to understanding hydraulic fracture containment and vertical growth in the Niobrara A, Niobrara C and Codell sandstone formations in the Denver-Julesburg (DJ) Basin. There were two principal components of the study. First, we utilized microseismic data to examine hydraulic fracture containment and vertical containment growth in terms of five DFIT stress measurements made at the toe of horizontal wells in each of the three formations of interest. Second, we analyzed the horizontal variations in the stresses due to the lateral well traversing lithostratigraphic facies. We have successfully shown that the hydraulic fractures in the heel of the well were initiated in a region of high least principal stress while in the toe of the well, the least principal stress was as much as 6 MPa lower. The evidence for this assertion is the timing of the events and the distance of the events from the centers of the stages. This study illustrates how important knowledge of the stress state is for understanding the characteristics of hydraulic fractures.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.97)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- North America > United States > Oklahoma > Anadarko Basin > Cana Woodford Shale Formation (0.99)
- (10 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Optimization of In-Stage Diversion To Promote Uniform Planar Multifracture Propagation: A Numerical Study
Chen, Ming (China University of Petroleum, China) | Zhang, Shicheng (China University of Petroleum, China) | Zhou, Tong (Research Institute of Petroleum Exploration and Development, Sinopec) | Ma, Xinfang (China University of Petroleum, China) | Zou, Yushi (China University of Petroleum, China)
Summary Creating uniform multiple fractures is a challenging task due to reservoir heterogeneity and stress shadow. Limited‐entry perforation and in‐stage diversion are commonly used to improve multifracture treatments. Many studies have investigated the mechanism of limited‐entry perforation for multifracture treatments, but relatively few have focused on the in‐stage diversion process. The design of in‐stage diversion is usually through trial and error because of the lack of a simulator. In this study, we present a fully coupled planar 2D multifracture model for simulating the in‐stage diversion process. The objective is to evaluate flux redistribution after diversion and optimize the dosage of diverters and diversion timing under different in‐stage in‐situ stress difference. Our model considers ball sealer allocation and solves flux redistribution after diversion through a fully coupled multifracture model. A supertimestepping explicit algorithm is adopted to solve the solid/fluid coupling equations efficiently. Multifracture fronts are captured by using tip asymptotes and an adaptive time‐marching approach. The modeling results are validated against analytical solutions for a plane-strain Khristianovic-Geertsma de Klerk (KGD) model. A series of numerical simulations are conducted to investigate the multifracture growth under different in‐stage diversion operations. Parametric studies reveal that the in‐stage in‐situ stress difference is a critical parameter for diversion designs. When the in‐situ stress difference is larger than 2 MPa, the fracture in the high‐stress zone can hardly be initiated before diversion for a general fracturing design. More ball sealers are required for the formations with higher in‐stage in‐situ stress difference. The diverting time should be earlier for formations with high in‐stage stress differences as well. Adding more perforation holes in the zone with higher in‐situ stress is recommended to achieve even flux distribution. The results of this study can help understand the multifracture growth mechanism during in‐stage diversion and optimize the diversion design timely.
- Asia (0.93)
- North America > United States > Texas (0.69)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Nebraska > Laramie Basin > Niobrara Formation (0.99)
- (5 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- (2 more...)
Validation of Fracture Height and Density from Rapid Time-Lapse DAS VSP for use in Calculating Stimulated Rock Volume: A Case Study from Hereford Field, Colorado
Inks, T. L. (IS Interpretation Services, Inc.) | Zhao, X. (Halliburton) | Willis, M. E. (Halliburton) | Jenner, E. (Land Seismic Noise Specialists) | Burke, B. (HighPoint Resources)
Abstract Distributed acoustic sensing (DAS) inter-stage vertical seismic profiling (VSP) data were acquired during the stimulation of two horizontal shale wells in the Denver-Julesburg (DJ) Basin’s Hereford field. These data were analyzed to obtain induced fracture heights and fracture densities for use in fracture modeling and Stimulated Rock Volume (SRV) calculations. Inverted inter-stage VSP (also referred to as rapid time-lapse DAS VSP) data, transformed to an anisotropic seismic velocity model via rock physics relationships, were used to estimate stage-by-stage fracture height and density. Comparison of fracture height from multiple sources confirm the validity of fracture height calculations for the Niobrara fiber well, and the deeper Codell fiber well. When combined with other independent diagnostics such as microseismic, tilt (microdeformation), seismic rock properties, pressure, and distributed acoustic/temperature sensing (DAS/DTS) data, these estimates are validated for use in developing an optimized completion plan, as well as for use in calculating stage-by-stage stimulated rock volumes. Introduction The Hereford field is located in the northern DJ Basin, Colorado, just south of the Wyoming state line. Similar to the giant Wattenburg field to the south, Hereford produces from the unconventional reservoirs of the Upper Cretaceous Niobrara Formation and the Codell Member of the Carlile Shale (Figure 1). Early in the life of the Hereford field, it was understood that the "complexity of the fracture system" would require significant analysis in order to understand and realize the reserve potential of the field (Anderson et. al., 2015). Early wells in the field, drilled between 2010 and 2012, were completed with relatively small completions and primarily accessed oil in the natural fracture systems. The very tight 0.5 to 3.0 mD permeability in the Niobrara B Chalk requires larger completion rates and volumes to access the matrix oil. The Hereford Field contains pervasively naturally fractured zones as well as more matrix dominated areas. A production optimization project was initiated by HighPoint Resources in 2019 to understand the best practices for maximizing production from both the pervasively natural fractured parts of the field, as well as the more matrix dominated portions of the field, while performing completions in 23 wells on four pads within the field. This project was designed to shorten the cycle-time needed to optimize completions. Rather than execute well-by-well parameter variations that can take years to evaluate, this project was designed to test numerous completion scenarios with a variety of diagnostic tools in a short period of time. Evaluation of these completion parameter changes give the best chance of success. In addition to distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) on fiber optic cables cemented behind casing, numerous other techniques were utilized to evaluate these wells including surface microseismic, tilt (microdeformation), pressure gauges, micro-imaging, and a pilot well with a quad combo and dipole sonic. Additionally, the 2009-vintage seismic data were reprocessed and merged with adjacent surveys in 2019 including a new pre-stack inversion. (Raw data courtesy of Seitel).
- North America > United States > Colorado (1.00)
- North America > United States > Texas > Jim Hogg County (0.40)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.55)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- (8 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- (2 more...)
Abstract Multi-stage hydraulic fracturing has gained popularity all over the world as more tight geologic formations are developed economically for hydrocarbon resources. However, due to the stages' operating complexity, different kinds of disruptions in fracturing operations may occur and even result in great economic loss. Screenout is one of the issues caused by the blockage of proppant inside the fractures. This paper presents a screenout classification system based on Gaussian Hidden Markov Models (GHMMs), trained on simulated data, that predicts screenouts and provides early warning by learning pre-screenout patterns in the simulated surface pressure signals. The simulated data are generated in a hydraulic fracturing software using a horizontal well with three fracturing stages landing in the Niobrara B shale, Denver-Julesburg (DJ) Basin. During the 270 simulations, various synthetic fracturing treatment data are forward modeled for both screenout and non-screenout scenarios. The classification system consists of two Gaussian Hidden Markov Models (screenout and non-screenout), each of which is fitted and optimized by its respective training set. Both Hidden Markov Models are assigned with two 1D Gaussian probability density functions to represent the distribution of their associated simulated surface pressure signals. During the classification process, once a new surface pressure sequence is observed, the maximum log likelihood is calculated under both fitted models and the model with a greater likelihood will be predicted as the class of this new observation. The classification system is validated with a hold-out testing data set from the simulations and the statistics of the performance is visualized in a confusion matrix. The results indicate the classification system achieves an overall classification accuracy of 81% and an accuracy of 86% for successfully predicting screenout events around 8.5 minutes prior to screenout occurring in the simulation. The described methodology is demonstrated to be a useful tool for early screenout detection and shows its promising feasibility of other fracturing time-series data analysis.
- Geology > Geological Subdiscipline > Geomechanics (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.35)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- 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)
- (11 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)