Montney Formation
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 > Neuquรฉn > 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 Distributed acoustic sensing (DAS) is a technology that enables continuous, real-time measurements along the entire length of a fiber-optic cable. The low-frequency band of DAS can be used to analyze hydraulic fracture geometry and growth. In this study, the low-frequency strain waterfall plots with their corresponding pumping curves were analyzed to obtain information on fracture azimuth, propagation speed, number of fractures created in each stage, and restimulation of preexisting fractures. We also use a simple geomechanical model to predict fracture growth rates while accounting for changes in treatment parameters. As expected, the hydraulic fractures principally propagate perpendicular to the treated well, that is, parallel to the direction of maximum horizontal stress. During many stages, multiple frac hits are visible, indicating that multiple parallel fractures are created and/or reopened. Secondary fractures deviate toward the heel of the well, likely due to the cumulative stress shadow caused by previous and current stages. The presence of heart-shaped tips reveals that some stress and/or material barrier is overcome by the hydraulic fracture. The lobes of the heart are best explained by the shear stresses at 45ยฐ angles from the fracture tip instead of the tensile stresses directly ahead of the tip. Antennas ahead of the fracture hits indicate the reopening of preexisting fractures. Tails in the waterfall plots provide information on the continued opening, closing, and interaction of the hydraulic fractures within the fracture domain and stage domain corridors. The analysis of the low-frequency DAS plots thus provides in-depth insights into the rock deformation and rock-fluid interaction processes occurring close to the observation well.
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation Field > Montney 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 > Greater Peace River High Basin > Pouce Coupe Field (0.99)
- (2 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Hydraulic Fracturing (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)
Distributed Acoustic Sensing (DAS) is a technology that enables continuous, real-time measurements along the entire length of a fiber optic cable. The low-frequency band of DAS can be used to analyze hydraulic fracture geometry and growth. In this study, the low-frequency strain waterfall plots with their corresponding pumping curves were analyzed to obtain information on fracture azimuth, propagation speed, number of fractures created in each stage, and re-stimulation of pre-existing fractures. We also use a simple geomechanical model to predict fracture growth rates while accounting for changes in treatment parameters. As expected, the hydraulic fractures principally propagate perpendicular to the treated well, that is, parallel to the direction of maximum horizontal stress. During many stages, multiple frac hits are visible indicating that multiple parallel fractures are created and/or re-opened. Secondary fractures deviate towards the heel of the well, likely due to the cumulative stress shadow caused by previous and current stages. The presence of heart-shaped tips reveals that some stress and/or material barrier is overcome by the hydraulic fracture. The lobes of the heart are best explained by the shear stresses at 45-degree angles from the fracture tip instead of the tensile stresses directly ahead of the tip. Antennas ahead of the fracture hits indicate the re-opening of pre-existing fractures. Tails in the waterfall plots provide information on the continued opening, closing, and interaction of the hydraulic fractures within the fracture domain and stage domain corridors. Analysis of the low-frequency DAS plots thus provides in-depth insights into the rock deformation and rock-fluid interaction processes occurring close to the observation well.
- North America > Canada > Alberta (1.00)
- North America > United States (0.67)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation Field > Montney 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 > Greater Peace River High Basin > Pouce Coupe Field (0.99)
- (2 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Hydraulic Fracturing (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)
Summary The heterogeneity of tight reservoirs, along with their complex geologic characteristics and the diverse completion practices used, presents challenges in developing accurate models to forecast the productivity for multifractured horizontal wells (MFHWs) completed in these reservoirs. This paper introduces a new early-time diagnostic tool that leverages early-time two-phase flowback data to forecast long-term productivity and evaluate completion efficiency. To achieve this, two novel models were developed. The first model, the water/oil-ratio model (WORM), uses a hybrid analytical and data-driven approach to describe the observed log-linear relationship between water/oil ratio (WOR) and load recovery (amount of fracturing water produced back after hydraulic fracturing operations) as an analogy to the log-linear relationship between the water/oil relative permeability ratio and water saturation. Next, a neural network is used to couple WORM parameters with key petrophysical properties to analyze the impact of fracture and formation properties on WOR performance, predict WOR as a function of load recovery, forecast ultimate load recovery, and estimate effective fracture volume and initial water saturation in fracture. The second model, the cumulative oil production model (COPM), is a data-driven model that predicts oil production as a function of load recovery during the matrix-dominated flow regime. The application of WORM and COPM on Niobrara and Codell formation wells showed that Codell wells generally exhibit better load recovery and larger effective fracture volume compared with Niobrara wells, but both formations exhibit similar oil recovery performance, indicating independent flow regimes within the effective fractures. The effective fracture volume estimated by WORM was validated against the estimated volume from recorded microseismic events. The results also showed that using the same completion practice to achieve a similar effective fracture volume in child wells does not necessarily lead to similar oil productivity. This paper introduces a holistic workflow that links early two-phase flowback data with well productivity and completion efficiency and is anticipated to aid petroleum engineers in optimizing hydraulic fracturing operations.
- North America > United States > Texas (0.93)
- North America > United States > Colorado (0.66)
- Research Report > New Finding (0.93)
- Research Report > Experimental Study (0.67)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.41)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Codell Formation (0.99)
- North America > United States > Texas > Anadarko Basin (0.99)
- North America > United States > Kansas > Anadarko Basin (0.99)
- (10 more...)
Abstract A quantitative interpretation (QI) study was conducted to characterize four formations located in Alberta, Canada. The Montney formation is targeted for gas production, while the Cadomin, Baldonnel, and Belloy formations are intended for CO2 sequestration. In this occasion, a thorough discussion of the results and their applicability is presented, focusing on the rock physics inversion and its direct link with drilling operations and interpretation. The study is currently being extended to estimate pore pressure and effective stress in the Montney formation, along with the application of a direct probabilistic inversion to identify facies. These two workflows will further optimize drilling targets and enhance completion operations. Introduction This paper builds upon a previous study that focused on reservoir characterization of four geological formations in Northwestern Alberta, Canada, specifically targeting gas production in the Montney formation and CO2 sequestration in the Cadomin, Baldonnel, and Belloy formations. Our objectives include presenting a comprehensive discussion of results, with a particular emphasis on the rock physics inversion's direct implications for drilling operations and interpretation. Close collaboration has played a pivotal role in obtaining valuable results, which are integral to the interpretation process. The study is being extended to estimate pore pressure and effective stress in the Montney formation. Additionally, a direct probabilistic inversion will be tested for facies identification, aiming to optimize drilling targets and enhance completion operations. Methods In this study, the methodology involved a comprehensive conditioning of seismic gathers, crucial for the Amplitude versus Offset (AVO) inversion workflow. This process included azimuthal seismic residual move-out alignment, amplitude balancing, and bandpass filtering, with a focus on improving inversion results. The gathers underwent a detailed QC, and a seismic Amplitude versus Azimuth (AVAZ) alignment ensured correct data alignment for seismic events across all incidence and azimuth angles. The aligned azimuthal angle stacks were then re-stacked into angle stacks ranging from 0-52ยฐ, with subsequent bandpass filtering to remove noise. Amplitude balancing was also performed to correct for geological transmission shadowing.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (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)
- (6 more...)
Abstract The Early Triassic Montney Formation in western Canada hosts a world-class unconventional petroleum accumulation with a complex history of hydrocarbon charging from both external and internal source rocks. This study focuses on self-sourced hydrocarbons and their intraformational migration within the siltstone-dominated Montney Formation. A review of recent geochemical studies highlights evidence of three main widespread episodes of intraformational hydrocarbon migration. The first episode was characterized by the migration of early-generated oil from internal Montney organic-rich source rocks during rapid burial. The second episode consisted of gas-condensate migration during deep burial and over-pressuring. The final episode involved methane-rich gas migration, mainly during basin uplift and depressurization. Spatial and temporal relationships of these three migration episodes fit a dynamic model of hydrocarbon generation, hydrocarbon migration and pressure evolution tied to basin subsidence and uplift history. Intraformational migration of gas and condensate has direct economic impacts on Montney well performance, such as higher gas-oil ratios and lower hydrocarbon liquid contents than expected from routine thermal maturity proxies. The Montney Formation has abundant publicly available subsurface data and thus provides a well-documented analogue for evaluating intraformational hydrocarbon migration in other unconventional petroleum accumulations. Introduction Intraformational migration of hydrocarbons driven by the changing pressure, volume and temperature (PVT) conditions that accompany basin subsidence and uplift is gaining increased recognition as a common phenomenon in unconventional low-permeability petroleum accumulations (Han et al., 2015, 2019; Wood and Sanei, 2016; Zumberge et al., 2016; Ducros et al., 2017; Euzen et al., 2018, 2019, 2020, 2021; Wood et al., 2021a, 2022). Recognizing significant hydrocarbon migration episodes is important for assessing unconventional oil and gas plays because it provides a basis for understanding intricate geographic distributions of gas-oil ratio (GOR) or condensate-gas ratio (CGR) in terms of first-order thermal maturity trends and second-order migration trends (Wood and Sanei, 2016; Wood and Sanei, 2017; Wood et al., 2021a). Sound delineation of intraformational migration and consequent mixing of hydrocarbon fluids directly impacts play economics by enhancing the ability to target liquid-rich versus drier gas zones, depending on changing commodity prices or corporate resource-development strategy.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.51)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- (39 more...)
Estimating Recovery by Quantifying Mobile Oil and Geochemically Allocating Production in Source Rock Reservoirs
Adams, Jennifer (Stratum Reservoir, Houston) | Flannery, Matt (Stratum Reservoir, Houston) | Ruble, Tim (Stratum Reservoir, Houston) | McCaffrey, Mark A. (Stratum Reservoir, Houston) | Krukowski, Elizabeth (Stratum Reservoir, Houston) | Kolodziejczyk, Daniel (GeoLab Sur S.A., Buenos Aires, Argentina) | Villar, Hรฉctor (GeoLab Sur S.A., Buenos Aires, Argentina)
Abstract Due to highly variable well performance, unconventional reservoir (UR) field development relies heavily on production monitoring to predict total recovery, assess well interference, delineate drained rock volume, and diagnose mechanical issues. Completion design and well spacing decisions depend on accurate recovery estimates from reservoir models, and these can be limited by non-uniqueness in the history matching. Geochemical production allocation can greatly improve operatorsโ understanding of well performance when integrated with reservoir characterization and in-reservoir P/T monitoring. There are several long-standing challenges in the characterization of UR fluid flow: (i) collecting reservoir samples representative of mobile oil, (ii) accounting for production fractionation over the life of a well, and (iii) determining recoverable original oil in place (OOIP) from contributing zones. Although many metrics and correlations are commonly used, ultimate recovery requires accurate quantification of the provenance of produced fluids and proportion of total OOIP. We have developed a rapid method for quantifying mobile and total oil saturations from water-based mud (WBM) collected, tight cuttings and sidewall core samples using low temperature hydrous pyrolysis (EZ-LTHP). These mobile oils commonly include even the gasoline range compounds, which are the dominant compounds of produced liquids in most mid-continent UR fields, making EZ-LTHP-derived oils representative end-members for geochemical production allocation studies. EUR estimates and production forecasts by zone, are more accurate when calibrated to the mobile oil fraction, rather than to total oil saturation. EZ-LTHP provides this step-change by quantifying the mobile oil fraction in WBM cuttings and, when paired with reservoir volumetrics, allows for better reservoir model calibration and field management. Other industry techniques, such as solvent extraction and vaporization, suffer from the same limitations as log-derived values which are known to overestimate mobile oil in kerogen-rich intervals by incorrectly including kerogen-bound immobile oil. In this paper, we present quantified mobile oil recovery estimates based on integrated geochemical allocation studies from the Vaca Muerta, Neuquรฉn basin, and the Niobrara, Denver basin. In the Vaca Muerta play (Argentina), the organic-rich Cocina and Organico intervals in the Vaca Muerta expelled liquid into intervening good quality reservoir lithologies. However, liquids dominantly are produced from the most organic-rich zones, with evidence of a larger drained rock volume (DRV) during early production. Gas and oil allocations show different DRVs explained by fluid mobility. The Montney play (Canada) shows contribution of liquid from non-target zones. Interbedded zones of indigenous Montney oil mixed with migrated more mature fluid - and major discontinuities in mud gas isotopes - document minimal vertical mixing. Horizontal wells produce gas and oil dominantly from better-quality reservoirs regardless of landing zone, with natural gas bypassing low permeability zones. Accurate estimations of out-of-zone contributions therefore require cuttings/core-based geochemical allocation. A subset of these wells requires additional consideration of production fractionation.
- North America > United States > Texas (1.00)
- North America > United States > Colorado (1.00)
- North America > Canada > British Columbia (1.00)
- (3 more...)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.35)
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- (59 more...)
Evaluation of Flow Units and Capillary Pressures of the Giant Chicontepec Tight Oil Paleochannel in Mexico and a Fresh Look at Drilling and Completions
Gutierrez Oseguera, Alejandra (Schulich School of Engineering, University of Calgary / Now with Kyera Corporation) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary (Corresponding author))
Summary The Chicontepec Paleochannel in Mexico is a giant shaly sandstone reservoir with volumes of original oil in place (OOIP) ranging between 137 and 59 billion STB (Guzmรกn 2022). However, the oil recoveries are very small, ranging between 0.32% and 0.75% of the OOIP. Under these conditions, consistent interpretation of flow units and mercury injection capillary pressures up to 55,000 psi provide useful information that helps in deciphering the rock quality and pore sizes at levels that might not be reached by thin-section petrography. This is important because the Chicontepec Paleochannel (Misantla-Tampico Basin) has been recently equated to the Permian Basin in the United States and has been termed by Guzman (2022) โa premier super basin in waiting.โ The current cumulative oil production of Chicontepec is 440 million STB. Although it is a significant volume, it represents a very small percentage of recovery from the reservoir (0.32โ0.75% of the OOIP). To help improve recovery, a method is developed for characterizing the tight Chicontepec Paleochannel using flow units and capillary pressures. Like in the case of many tight unconventional reservoirs, the capillary pressures can go to very high values, reaching 55,000 psi in the Chicontepec case. Therefore, a special procedure is developed to generate a consistent interpretation of all the available capillary pressure curves for the entire range of pressures. The results highlight the important oil recovery potential. The assessment is supported by quantitative formation evaluation work performed by Gutierrez Oseguera and Aguilera (2023). Although natural fractures are present, most wells must be hydraulically fractured to achieve commercial success. Process or delivery speed (the ratio of permeability and porosity) for the Chicontepec samples used in the capillary pressure experimental work range between 159.1 md and 0.17 md (porosity in the denominator is a fraction). Flow units show pore throat radii (rp35) range from less than 0.1 ยตm to about 4.5 ยตm. These values and flow units compare well with data available for prolific unconventional reservoirs such as the Cardium sandstone in Canada and the giant Permian Basin in the United States. The radius rp35 refers to the pore throat radius at 35% cumulative pore volume (PV) of injected mercury. This is different from rp also discussed in this paper, which is the pore throat radius at any water saturation (for example, at 40% water saturation). Thus, in the case where water saturation is 65%, rp is equal to rp35. The novelty of this study is the development of a consistent procedure for interpreting the entire range of pressures measured during mercury injection capillary pressures. Such pressures go up to 55,000 psi for the core samples considered in this study. The integration with flow units and formation evaluation suggests that the potential of the Chicontepec unconventional reservoirs can rival successful results obtained in the Cardium sandstone and the Permian Basin. The key ideas discussed in this paper for improving Chicontepec oil recovery include specialized petrophysical evaluation, determination of flow units and capillary pressures, improved drilling and completion methods, and geological support.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (1.00)
- Phanerozoic > Paleozoic > Permian (1.00)
- Phanerozoic > Cenozoic > Paleogene > Paleocene (0.46)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.96)
- 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)
- (58 more...)
ABSTRACT Hydraulic fracturing is crucial for enhancing hydrocarbon production from unconventional reservoirs. The characterization of fracture geometry and propagation has significant value in understanding reservoir response and designing more efficient completions. Distributed acoustic sensing (DAS) is a rapidly developing technology that can be used for this purpose because it provides wide-aperture observations of microseismic wavefields that contain direct P and S arrivals as well as converted and reflected waves. In addition to traditional approaches for microseismic event location and source mechanism analysis, the high spatial resolution of DAS microseismic recordings allows the imaging of induced fractures with reflected waves. Reflections are generated by waves radiated from microseismic events that impinge on hydraulic fractures created during prior treatment stages. We use a straightforward method based on f-k filtering and ray tracing to map reflected S waves from the time domain to reflectivity in the space domain. A case study of fracture imaging indicates that inferred fracture development, based on reflection imaging, is consistent with fracture-driven interactions observed using low-frequency DAS (LF-DAS) data. In addition, this study reveals reflection images of apparent distal fractures that do not reach the fiber and thus are not directly observed by LF-DAS. Fracture images obtained from several microseismic events during the same stage provide the opportunity to observe snapshots of dynamic fracture evolution processes.
- 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)
Abstract Serial-sectioned images were three-dimensionally reconstructed to visualize the fracture network within an outcropped cube, sourced from the Montney Formation, the largest unconventional natural gas resource in Canada, that was hydraulically fractured in the lab under conditions similar to real field operations. Following the experiment, the fractured cube was saturated with fluorescent materials to distinguish the fracture network from the rock matrix and provide common spatial references for a modified serial-sectioning and photographing method using ultraviolet light. The obtained serial-sectioned images underwent image processing, distortion removal calibration, and image registration for three-dimensional visualization, including reconstruction and segmentation. The results highlighted the significant influence of bedding planes and rock anisotropy on the generated fracture network geometry. These observations have important implications on the evaluation of the stimulated rock volume, as well as on completion strategies, as preferential opening of bedding planes might result in horizontal intra-well connectivity and increase parent-child interactions.
- North America > Canada > Alberta (0.67)
- North America > Canada > British Columbia (0.50)
- North America > Canada > Ontario > Toronto (0.15)
- 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)
- (3 more...)