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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)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
ABSTRACT In this article, the Editor of G provides an overview of all technical articles in this issue of the journal.
- North America > United States > Texas (0.28)
- North America > Canada (0.28)
- Geology > Geological Subdiscipline > Geomechanics (0.47)
- Geology > Geological Subdiscipline > Stratigraphy (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- 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)
- (46 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Near-well and vertical seismic profiles (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
- (2 more...)
Lack of knowledge of lateral heterogeneity in unconventional reservoirs commonly imposes negative impacts on drilling, completion efficiency, and production. However, current methods, such as well logging and seismic survey, are limited in characterizing unconventional reservoirs. This study proposes an alternative geophysical approach that utilizes Distributed Acoustic Sensing (DAS) and perforation shot to characterize unconventional reservoirs. In our field dataset, DAS recorded perforation shot shows 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 phase-velocity spatial variations along the horizontal wellbore can be reliably measured by averaging the measurements from multiple close-by perforation shots. We observe a low phase-velocity zone along the study well, which is spatially consistent with well logs and 3-D seismic images. The observed dispersive behavior of P waves is validated via numerical modeling. By comparing the proposed method with modeling results and other measurements, we conclude that the proposed method results in an ideal investigation radius 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 investigate lateral heterogeneity for 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)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
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. 95% 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 its higher brittleness than in the reservoir, 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 since 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 (0.67)
- 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)
- 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)
Abstract Detection and localization of microseismicity is an inevitable task in monitoring fluid injections into subsurface rocks during hydraulic stimulations. Traditionally, downhole geophones placed into boreholes or large surface geophone networks have been used for this, but in recent years, the use of distributed acoustic sensing (DAS) via fiber-optic cables placed into boreholes has become a common technique. However, DAS registrations still have lower signal-to-noise ratios than geophones; i.e., they cannot detect small-magnitude events. In this work, we develop and train a convolutional neural network capable of detecting microseismic events in continuous DAS recordings incorporating arrival-time information from geophones. The network is trained on DAS and geophone data from the Utah FORGE enhanced geothermal system project for which we are able to significantly shift the detection threshold toward smaller magnitude events. Although the number of microseismic events (approximately 150) used for training is small, the tested network performance is high and provides a complete event catalog down to magnitude MW = −1.6, a notable improvement over previous studies. Using a short recording period of several hours for training, such a network might be used for long-term, real-time monitoring of geothermal sites. Although the network is explicitly trained for the geometry of the data set used, the philosophy and network architecture can be adapted for similar case studies where long-term seismic monitoring is required (e.g., CO2 sequestration).
- 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)
This forum compared the different monitoring techniques in order to better understand the interpretability of their results. The recent increase in awareness of the potential of unconventional reservoirs has caused a tremendous growth in hydraulic fracture stimulation operations. Conventionally, the recording of microseismicity has been performed with borehole seismic tools deployed in deep nearby wells but "frac monitoring" is not restricted to such a setting. Elastic waves generated by these micro-earthquakes can also be recorded at the earth's surface and in shallow boreholes. The energy released by microseismic events as a result of hydraulic stimulation is small, and, due to the longer travel paths and higher noise levels, monitoring hydraulic fracture stimulations from surface potentially requires orders of magnitude more sensors than downhole monitoring.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.73)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
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)
First Unconventional Najmah Horizontal Well in Green Jurassic Gas Field Unlocked the Reservoir Potential and Setup Development Strategy Roadmap
Abdel-Basset, M. (SLB, Kuwait) | Al-Otaibi, Y. (Kuwait Oil Company, Kuwait) | Al-Ajmi, S. (Kuwait Oil Company, Kuwait) | Al-Mulla, S. (Kuwait Oil Company, Kuwait) | Bloushi, T. (Kuwait Oil Company, Kuwait) | Al-Mutawa, M. (Kuwait Oil Company, Kuwait) | Al-Ajmi, M. (Kuwait Oil Company, Kuwait) | Hadi, A. (Packers Plus Energy Services, Kuwait)
Abstract The journey of appraising unconventional reservoirs of North Kuwait Jurassic Gas (NKJG) fields achieved a significant milestone through the successful test in the first horizontal well completed in Najma Limestone (NJ-LS) reservoir in Bahra field. This accomplishment becomes even more remarkable given that none of the previous vertical wells’ tests were successful. This paper will demonstrate the challenges faced in the well placement, completion and stimulation, as well as the implementation of new technologies to achieve Kuwait’s highest ever initial gas production rate. This outstanding success in appraisal well has unlocked the potential of the NJ-LS reservoir and prompted a step-change in its development strategy. NJ-LS is a tight gas-condensate reservoir with typical porosity ranging from 2 to 9% and very low matrix permeability (~0.01mD) with primary production through natural fractures. To increase the chances of success in encountering fracture corridors, long drain-hole horizontal wells were deemed necessary. To overcome well planning and placement challenges, detailed seismic attribute mapping and integration of available core and log data were undertaken to place the well in the best sweet spot. Extensive screening of seismic data helped avoid possible seismically mappable hazards and optimize the trajectory to encounter areas with high fracture corridor. The well was drilled as 6in lateral length of approximately 2900ft and successfully landed as planned. State-of-the-art drilling and real-time geosteering technologies aided in precisely placing the wellbore in the target zone of NJ-LS. The integrated completion design included eight stages of Multi-Stage Completion, as first-time achievement in NKJG fields. The targeting of shorter stages aimed to accommodate better the reservoir heterogeneity (matrix, fractures, losses, etc) to improve acid stimulation efficiency. Many operational challenges were faced and overcame by multidisciplinary team during the multi-stage stimulation and flow back (e.g high surface pressure ~12,000 psia and presence of H2S). All eight stages were individually stimulated with high-rate matrix acidizing. Commingle activation, flow back and testing activities were executed in continuous back-to-back operations to fast track well delivery to production. Double degradable balls were used for the first time to open the corresponding FracPORT seat and isolate lower open stages. Two green burners used for the first time in Kuwait, accommodated the high returns during flow back and initial testing. Continued advancements throughout the full well cycle, from well placement to stimulation, culminated in achieving Kuwait’s highest ever gas production rate on the initial test, with low Water-cut at different choke sizes and high Wellhead pressure (+/- 6500 psia) Such outstanding results have encouraged the NKJG asset to fast track the extension of this success to other sweet spots as step-change in unconventional reservoirs, supporting the roadmap towards achieving and sustaining the asset’s production target.
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Bahrah Field > Marrat Formation (0.99)
First Unconventional Najmah Horizontal Well in Green Jurassic Gas Field Unlocked the Reservoir Potential and Setup Development Strategy Roadmap
Abdel-Basset, M. (SLB, Kuwait) | Al-Otaibi, Y. (Kuwait Oil Company, Kuwait) | Al-Ajmi, S. (Kuwait Oil Company, Kuwait) | Al-Mulla, S. (Kuwait Oil Company, Kuwait) | Bloushi, T. (Kuwait Oil Company, Kuwait) | Al-Mutawa, M. (Kuwait Oil Company, Kuwait) | Al-Ajmi, M. (Kuwait Oil Company, Kuwait) | Hadi, A. (Packers Plus, Kuwait)
Abstract The journey of appraising unconventional reservoirs of North Kuwait Jurassic Gas (NKJG) fields achieved a significant milestone through the successful test in the first horizontal well completed in Najma Limestone (NJ-LS) reservoir in Bahra field. This accomplishment becomes even more remarkable given that none of the previous vertical wells’ tests were successful. This paper will demonstrate the challenges faced in the well placement, completion and stimulation, as well as the implementation of new technologies to achieve Kuwait’s highest ever initial gas production rate. This outstanding success in appraisal well has unlocked the potential of the NJ-LS reservoir and prompted a step-change in its development strategy. NJ-LS is a tight gas-condensate reservoir with typical porosity ranging from 2 to 9% and very low matrix permeability (~0.01mD) with primary production through natural fractures. To increase the chances of success in encountering fracture corridors, long drain-hole horizontal wells were deemed necessary. To overcome well planning and placement challenges, detailed seismic attribute mapping and integration of available core and log data were undertaken to place the well in the best sweet spot. Extensive screening of seismic data helped avoid possible seismically mappable hazards and optimize the trajectory to encounter areas with high fracture corridor. The well was drilled as 6in lateral length of approximately 2900ft and successfully landed as planned. State-of-the-art drilling and real-time geosteering technologies aided in precisely placing the wellbore in the target zone of NJ-LS. The integrated completion design included eight stages of Multi-Stage Completion, as first-time achievement in NKJG fields. The targeting of shorter stages aimed to accommodate better the reservoir heterogeneity (matrix, fractures, losses, etc) to improve acid stimulation efficiency. Many operational challenges were faced and overcame by multidisciplinary team during the multi-stage stimulation and flow back (e.g high surface pressure ~12,000 psia and presence of H2S). All eight stages were individually stimulated with high-rate matrix acidizing. Commingle activation, flow back and testing activities were executed in continuous back-to-back operations to fast track well delivery to production. Double degradable balls were used for the first time to open the corresponding FracPORT seat and isolate lower open stages. Two green burners used for the first time in Kuwait, accommodated the high returns during flow back and initial testing. Continued advancements throughout the full well cycle, from well placement to stimulation, culminated in achieving Kuwait’s highest ever gas production rate on the initial test, with low Water-cut at different choke sizes and high Wellhead pressure (+/- 6500 psia) Such outstanding results have encouraged the NKJG asset to fast track the extension of this success to other sweet spots as step-change in unconventional reservoirs, supporting the roadmap towards achieving and sustaining the asset’s production target.
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Bahrah Field > Marrat Formation (0.99)
Hydro-Geomechanical Observations During Multistage Hydraulic Stimulation at the Bedretto Underground Laboratory, Switzerland
Bröker, K. (ETH Zurich, Institute of Geophysics) | Ma, X. (ETH Zurich, Institute of Geophysics) | Gholizadeh Doonechaly, N. (ETH Zurich, Institute of Geophysics) | Hertrich, M. (ETH Zurich, Institute of Geophysics) | Hansruedi, M. (ETH Zurich, Institute of Geophysics) | Giardini, D. (ETH Zurich, Institute of Geophysics) | _, _ (Bedretto Lab Team) | Rinaldi, A. P. (Swiss Seismological Service) | Clasen Repollés, V. (Swiss Seismological Service) | Obermann, A. (Swiss Seismological Service) | Wiemer, S. (Swiss Seismological Service)
ABSTRACT A series of hydraulic stimulation experiments were performed in the Bedretto Underground Laboratory for Geosciences and Geoenergies in Switzerland to answer questions about the creation of an engineered geothermal reservoir in crystalline rocks. A 400 m long stimulation borehole was divided into 15 intervals by a multi-packer system. In this work, we present preliminary results of interval 8 in which two injection phases were performed with a 3.5 months gap in between. The two phases differ in the injected volume and injection protocol (pressure vs. flow rate controlled). Within the interval, we mapped a cluster of sub-parallel pre-existing open fractures that are reasonably well oriented for reactivation in the estimated stress field. The interval pressure and flow rate data from the injections reveal a reactivation of the pre-existing fractures, associated with a large increase in injectivity. A comparison of the expected stress field around the stimulation interval with the observed reactivation pressure indicates that the fractures were likely reactivated by hydraulic shearing. The reactivation is also supported by other data sets from the extensive monitoring network, e.g. distributed temperature and strain sensing. INTRODUCTION Engineered geothermal systems (EGS) have received increasing interest in recent years because they are considered a low emission, renewable energy source (Lu, 2018; Aghahosseini and Breyer, 2020). An EGS aims to extract geothermal energy from crystalline basement rocks with low permeability. The permeability is enhanced either by hydraulic shearing of natural fractures or shear zones, or by hydraulic fracturing of intact rock, or by a mixture of both (McClure and Horne, 2014). This permeability enhancement is often linked to induced seismicity, which can reach damaging levels if large fault zones are reactivated (e.g. Deichmann and Giardini, 2009; Evans et al., 2012; Ellsworth et al., 2019). To address this challenge, several scaled-down in situ hydraulic stimulation experiments have been conducted in underground research laboratories in representative crystalline rock types (e.g. Amann et al., 2018; Zimmermann et al., 2019; Schoenball et al., 2020; Fu et al., 2021).
- Europe > Switzerland (1.00)
- North America > United States (0.95)
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.68)
- 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 > Seismic processing and interpretation (1.00)
- (2 more...)