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The spatiotemporal distribution of hydraulic fracturinginduced microseismicity is complicated and depends on various mechanical and diffusional parameters. Hydraulic fracture modeling can aid in understanding fluid-induced microseismicity. Nevertheless, the interaction of several physical processes occurring within and around the fracture adds complexity in developing tools for microseismic prediction. We apply a physics-based approach relying on diffusivity estimates derived from the microseismic observations and a convolutional neural network (CNN) trained with the engineering curves to forecast the microseismic cloud size in real-time.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Neural Networks (0.69)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Model-Based Reasoning (0.61)
Source mechanisms help understand the fracturing behavior and the evolving stress field in microseismic monitoring. This study presents how to retrieve the source mechanisms of hydraulic-fracturing induced events using a source mechanism screening test based on the S/P amplitude ratio and a full inversion. First, we apply the inversion on synthetic amplitudes and test different input parameters to find the best inversion scheme. Then, we perform the moment-tensor inversion on over 1000 microseismic events in a Montney reservoir, northeastern British Colombia (BC). The inversion results are compared with the results from the source mechanism screening test. The screening test results and the preliminary inversion results show good agreement. We have both tensile and shear faultings, with tensile mechanisms highly likely being dominant in stages towards the heel of the well.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
An Efficient Hydraulic Fracture Geometry Calibration Workflow Using Microseismic Data, Geomechanics, DFN Models, and History Matching
Leines-Artieda, Joseph Alexander (SimTech LLC) | Liu, Chuxi (The University of Texas at Austin) | Yang, Hongzhi (Petrochina Southwest Oil&Gas Field Company) | Wu, Jianfa (Petrochina Southwest Oil&Gas Field Company) | Chang, Cheng (Petrochina Southwest Oil&Gas Field Company) | Yu, Wei (SimTech LLC) | Sepehrnoori, Kamy (The University of Texas at Austin)
Abstract Reliable estimates of hydraulic fracture geometry help reduce the uncertainty associated with estimated ultimate recovery (EUR) forecasts and optimize field developing planning in unconventional reservoirs. For these reasons, operators gather information from different sources with the objective to calibrate their hydraulic fracture models. Microseismic data is commonly acquired by operators to estimate hydraulic fracture geometry and to optimize well completion designs. However, relying solely on estimates derived from microseismic information may lead to inaccurate estimates of hydraulic fracture geometry. The objective of this study is to efficiently calibrate hydraulic fracture geometry by using microseismic data, physics-based fracture propagation models, and the embedded discrete fracture model (EDFM). We first obtain preliminary estimates of fracture geometry based on microseismic events’ spatial location and density with respect to the perforation cluster location. We then tune key completion parameters using an in-house fracture propagation model to provide hydraulic fracture geometries that are constrained by the microseismic cloud. In the history matching process, we included the effect of natural fractures, using the microseismic events location as natural fracture initiation points. Finally, we used cutoff coefficients to further reduce hydraulic fracture geometries to match production data. The results of this work showed a fast and flexible method to estimate fracture half-lengths and fracture heights, resulting in a direct indicator of the completion design. Additionally, hydraulic-natural fracture interactions were assessed. We concluded that the inclusion of cutoff coefficients as history matching parameters allows to derive realistic hydraulic and natural fracture models calibrated with microseismic and production data in unconventional reservoirs.
- North America > United States > Texas (0.47)
- North America > Canada (0.46)
- 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)
- Information Technology > Communications > Networks (0.47)
- Information Technology > Artificial Intelligence (0.34)
Automatic seismic phase picking based on unsupervised machine-learning classification and content information analysis
Cano, Eduardo Valero (King Abdullah University of Science and Technology (KAUST)) | Akram, Jubran (KAUST) | Peter, Daniel B. (King Abdullah University of Science and Technology (KAUST))
ABSTRACT Accurate identification and picking of P- and S-wave arrivals is important in earthquake and exploration seismology. Often, existing algorithms are lacking in automation, multiphase classification and picking, as well as performance accuracy. We have developed a new fully automated four-step workflow for efficient classification and picking of P- and S-wave arrival times on microseismic data sets. First, time intervals with possible arrivals on waveform recordings are identified using the fuzzy c-means clustering algorithm. Second, these intervals are classified as corresponding to P-, S-, or unidentified waves using the polarization attributes of the waveforms contained within. Third, the P-, S-, and unidentified-waves arrival times are picked using the Akaike information criterion picker on the corresponding intervals. Fourth, unidentified waves are classified as P or S based on the arrivals moveouts. The application of the workflow on synthetic and real microseismic data sets indicates that it yields accurate arrival picks for high and low signal-to-noise ratio waveforms.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Information Technology > Information Management (1.00)
- Information Technology > Artificial Intelligence > Representation & Reasoning (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Neural Networks (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Clustering (0.48)
ABSTRACT: A geomechanical study was performed for a fault activation sequence in Western Canada to assess how various operational changes hydraulic fracture design impacts seismicity. A discrete-element code with coupled hydraulic-mechanical-seismic capability was calibrated to field microseismic observations, and then used to simulate fault slip and total seismic moment associated with changes to hydraulic fracturing operations design. The model was used to investigate changes in hydraulic fracture stage volumes, rates and viscosities along with operational pauses and variations in well orientation relative to the fault. The study enabled ranking of operational changes in terms of efficacy to mitigate seismicity as well as fracturing effectiveness based on volumetric diversion of the fracturing fluid from stimulating the reservoir towards a fault thief zone. The simulation results are generally consistent with traditional concepts of key controlling factors including injection volume and time for pressure to dissipate or leak-off, although the model also indicates that seismicity is only driven by the proportion of the injected volume that flows into the slipping fault. These learnings also provide a framework to consider the influence of other operational factors such as ‘zippering’ stages between different wells. The study provides unique insights and relative quantification of operational factors to help mitigate induced seismicity. 1. Introduction Injection induced seismicity is known to occur from a variety of industrial activities, including wastewater disposal by subsurface injection and hydraulic fracturing operations (e.g., Ellsworth, 2013). In relation to the widespread use of hydraulic fracture stimulations as part of unconventional reservoir development, seismicity induced by hydraulic fracturing has been associated with a small proportion of wells completed in only a few specific reservoirs (e.g., Schultz et al., 2020). To mitigate the risk of anomalous seismicity, local regulations have been introduced which utilize traffic light systems based on seismic magnitudes of seismicity near active fracturing operations. Such systems have been implemented in British Columbia, Alberta, Oklahoma, Ohio and the United Kingdom. While details of the regulations vary and particularly the magnitude thresholds that trigger operational changes, the general logic is to reduce activation of pre-existing, critically stressed faults if anomalous seismicity is detected.
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.34)
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
ABSTRACT: Hydraulic fracture height is one of the most difficult parameters to measure yet understanding height growth is becoming increasingly salient in the economic success of unconventional wells in multi-layer structures, particularly for projects with increased well density development. Downhole tiltmeter fracture mapping by passive monitoring of elasto-static microdeformation offers high sensitivity to fracture height. This work aims at presenting a workflow to integrate advanced microseismic analysis and tiltmeter fracture mapping to resolve dimensions of fracture with a non-uniform opening. The algorithms are implemented in a real-time fracture monitoring program which selects the best fit and superposes final-state and transient models on measured micro-deformation. We apply the presented technique to synthetic and field case studies and, for the first time, present transient tilt characteristics using heatmap visualization of slow deformation (tilt waterfall). Our motivation for the present study is to take advantage of the newly developed downhole instruments that convey a combined array of geophones and tiltmeters and can be installed at greater depth and temperature to monitor and evaluate fracture to as hot as 177°C (>12000ft). 1. Introduction Hydraulic fracturing in unconventional reservoirs is a complex process controlled by the pumping parameters, rock mechanical properties, in-situ stress state, and multi-scale discontinuities (e.g., layering and interfaces, faults, natural fractures). Thereby it is poorly characterized by standard models unless discrepancies are resolved by introducing fudge factors (Warpinski et al. 1994). Downhole Tiltmeter Fracture Mapping (DTFM) is a unique technique that measures induced microdeformation near the fracture face and unravels the evolution of the volumetric distribution of fluid-driven fracture during treatment as well as after pumping stops. Fracture height, dip, volume, azimuth, opening, horizontal components, and complexity are among the parameters that impact the tilt response and can be potentially determined by DTFM if enough tiltmeters are located optimally. As depicted in Fig.1, the field deployment of DTFM to monitor the underground operation entails placement of at least one vertical, linear and wireline-conveyed array of tiltmeters in an offset well (Wright et al. 1998b). The array of tiltmeters is conveyed to the same depth range targeted by the treatment well. It is carefully deployed to ensure that enough data can be recorded from above and below the fracture depth. The acquisition unit samples tilt sequentially in time at each tiltmeter normally with a sampling rate of < 5 HZ.
- North America > United States > Texas (1.00)
- North America > United States > Colorado (0.69)
- North America > Canada (0.68)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.68)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.46)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Codell Formation (0.99)
- (32 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Information Technology > Artificial Intelligence (0.93)
- Information Technology > Data Science (0.68)
Comprehensive Characterization and Mitigation of Hydraulic Fracturing-Induced Seismicity in Fox Creek, Alberta
Hui, Gang (University of Calgary) | Chen, Shengnan (University of Calgary (Corresponding author) | Chen, Zhangxin (email: snchen@ucalgary.ca)) | Gu, Fei (University of Calgary) | Ghoroori, Mathab (Research Institute of Petroleum Exploration and Development) | Mirza, Mohammad Ali (University of Calgary)
Summary The relationships among formation properties, fracturing operations, and induced earthquakes nucleated at distinctive moments and positions remain unclear. In this study, a complete data set on formations, seismicity, and fracturing treatments is collected in Fox Creek, Alberta, Canada. The data set is then used to characterize the induced seismicity and evaluate its susceptibility toward fracturing stimulations via integration of geology, geomechanics, and hydrology. In addition, an integrated geological index (IGI) and a combined geomechanical index (CGI) are first proposed to indicate seismicity susceptibility, which is consistent with the spatial distribution of induced earthquakes. Finally, mitigation strategy results suggest that enlarging a hydraulic fracture-fault distance and decreasing a fracturing job size can reduce the risk of potential seismic activities. Introduction Recent surging-induced seismicity events have been attributed to anthropogenic resource exploration and production activities, such as hydraulic fracturing (HF), wastewater disposal, and geothermal stimulation (Wetmiller 1986; Gaucher et al. 2015; Schultz et al. 2014, 2020; Grigoli et al. 2017). Several earthquakes with large magnitudes have been reported in North America, Southern China, United Kingdom, and Switzerland, which are spatiotemporally correlated with HF operations in unconventional resources (Bao and Eaton 2016; Lei et al. 2017; Eyre et al. 2019; Schultz et al. 2020). During HF operations, tens of thousands of cubic meters of fluids are injected under high pressure to create the tensile failure of low-permeability reservoir rocks and generate fracture networks. Thus, a comprehensive study is required to understand the triggering mechanisms and mitigate potential seismicity risks. Two major hypotheses have been proposed to understand the fundamental mechanisms of HF-induced seismicity, including pore pressure diffusion and poroelastic stress perturbation, which can decrease the fault strength and thus cause faults to slip (Healy et al. 1968; Ellsworth 2013; King and Deves 2015; Galloway et al. 2018).
- North America > Canada > Alberta (1.00)
- Europe (1.00)
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.66)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (5 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)
Unlocking Unconventional Reservoir for Optimum Production Through Integrated Multi-Disciplinary Approach - A Case Study
M. Faskhoodi, Majid (Schlumberger) | Damani, Akash (Schlumberger) | Kanneganti, Kousic (Schlumberger) | Zaluski, Wade (Schlumberger) | Ibelegbu, Charles (Schlumberger) | Qiuguo, Li (Schlumberger) | Xu, Cindy (Schlumberger) | Mukisa, Herman (Schlumberger) | Ali Lahmar, Hakima (Schlumberger) | Andjelkovic, Dragan (Schlumberger) | Perez Michi, Oscar (Schlumberger) | Zhmodik, Alexey (Schlumberger) | Rivero, Jose A. (Schlumberger) | Ameuri, Raouf (Schlumberger)
Abstract To unlock unconventional reservoirs for optimum production, maximum contact with the reservoir is required; however, excessively dense well placement and hydraulic fractures interconnection is a source of well-to-well interaction which impairs production significantly. The first step to have successful and effective well completion is to understand the characteristics of the hydraulic fractures and how they propagate in reservoir. This paper demonstrates an integrated approach with a field example in the Montney formation for how modern modeling techniques were used to understand and optimize hydraulic fracture parameters in unconventional reservoir. Advanced logs from vertical wells and 3D-seismic were used to build an integrated geological model. Lamination index analysis was performed, using borehole imagery data to account for interaction of hydraulic fracture with vertically segregated rock fabric and to provide additional control on hydraulic fracture height growth during modeling process. A non-uniform Discrete-Fracture-Network (DFN) model was constructed. 3D-geo-mechanical model was built and initialized, using sonic log and seismic data. Fluid friction and leak-off was calibrated, using treatment pressure and DFIT data. Hydraulic fracture modeling was done for pad consists of 6 horizontal wells with multi-stage fracturing treatments, by utilizing actual pumped schedules and calibrating it against microseismic data. High-stress anisotropy led to planar hydraulic fractures despite presence of natural fractures in area. Fracturing sequence, i.e., effect of stress shadow, is seen to have major impact on hydraulic fracture geometry and propped surface area. Heatmaps were generated to estimate average stimulated and propped rock volume in section. It was also observed that rock fabrics, i.e., natural fracture and lamination has considerable impact on propagation of hydraulic fracture. Multiple realizations of natural fracture and lamination distribution were generated and used as an input in modeling process. High resolution unstructured simulation grids were generated to capture fracture dimensions and conductivities, as well as track propped and unpropped regions in stimulation network. Dynamic model was constructed and calibrated against historical production data. History matched model was then used as predictive tool for pad development optimization and to evaluate parent-child interaction in depleted environment.
- North America > United States (1.00)
- North America > Canada > Alberta (1.00)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Wolfcamp Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- (5 more...)
- Information Technology > Modeling & Simulation (1.00)
- Information Technology > Artificial Intelligence > Machine Learning (0.46)
Abstract Historically the evaluation of unconventional reservoirs dominantly relied on analytical methods like Decline Curve Analysis (DCA) and Rate Transient Analysis (RTA). Although they are effective and convenient, the lack of fundamental understanding such as fracture geometry leads to high uncertainties in analysis and consequently challenges in improving the accuracy of forecast or explaining the production mechanism. A geomechanical integrated reservoir modeling approach is developed to precisely tackle this limitation. Because of the extremely low permeability and widely utilized horizontal drilling with multiple hydraulic fracture design, a conventional modeling approach could not be adopted directly without the critical addition of geomechanical workflow. The complete approach includes 1) Geomodelling 2) RTA and hydraulic fracture modeling 3) graphic processing unit (GPU) based reservoir simulations and 4) Poro-elastic impacts on stress modeling. The change of each portion will impact the whole, therefore a workflow with fewer tools and iterations greatly benefits the efficiency of the methodology. A single tool including fracture modeling and dual-porosity simulation were deployed and successfully demonstrated the power of this process in business operation. A few field examples are used to demonstrate this approach. They include the history matching (HM), optimization of completion and spacing strategy for 1) a dry gas field 2) a black oil field and 3) a workflow for new entry field with almost no data. The lack of lab measurements (such as SCAL, k, sigma) are common and the assumptions used are elaborated. It is important to recognize simulation uncertainties, So the hypothesis has tested by utilizing modeling design from pilot wells. Although almost everyone in the industry recognizes the importance of integrated modeling, practical application has been very challenging. The coupling of geomechanics and reservoir simulation typically not only requires extremely long cycle times to deliver, but also relies on significant computational power. Therefore, analysis of different realizations is generally not feasible, and appropriate uncertainties are not captured. The presented approach illustrated as an integrated method using one tool which successfully reduced the cycle time of pad level modeling to weeks, therefore improved the efficiency of reservoir engineers significantly.
- North America > Canada > Alberta (0.48)
- North America > United States > North Dakota > Burke County (0.24)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (8 more...)
On 30 November 2018, a felt (ML 4.5) seismic event occurred ~16 km from Fort St. John, British Columbia, that has been attributed to ongoing hydraulic fracturing operations in the area. The mainshock was followed by two felt aftershocks (>ML 3.4) in the following hour. All of the events were tightly clustered, both spatially and in depth, and appear to be related to a southern boundary fault of the Fort St. John Graben complex. Stress inversion of a number of focal mechanisms suggests that the maximum principal stress is well constrained and almost horizontal, however the intermediate- and minimum-principal stresses are poorly constrained between the vertical and minimum horizontal stress. This results in a variety of focal mechanisms from the detected seismicity, and indicates a high complexity in the local stress regime. Hypocenters appear to locate at the confluence between a large-scale reverse faulting style regime (to the north-west, probably due to the influence of the Rocky Mountain fold and thrust belt) and an oblique strike slip faulting regime (to the south-east, probably due to influence of the Fort St. John Graben complex). Presentation Date: Monday, October 12, 2020 Session Start Time: 1:50 PM Presentation Time: 1:50 PM Location: 360A Presentation Type: Oral
- North America > Canada > Alberta (1.00)
- North America > Canada > British Columbia > Peace River Regional District > Fort St. John (0.66)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (1.00)
- Geology > Structural Geology > Fault > Dip-Slip Fault (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Earthquake Seismology (0.68)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.51)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (2 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)