Significance of Rock Compositional Control on Geomechanical Properties and Hydraulic Fracturing of the Montney Formation, Western Canadian Basin

2019 ◽  
Author(s):  
Noga Vaisblat ◽  
Alireza Rangriz Shokri ◽  
Korhan Ayranci ◽  
Nick Harris ◽  
Rick J. Chalaturnyk
Keyword(s):  
Hydraulic Fracturing ◽  
Geomechanical Properties ◽  
Canadian Basin ◽  
Montney Formation ◽  
Compositional Control

Joint Application of Diagenetic, Petrophysical and Geomechanical Data for Selecting Hydraulic Fracturing Candidate Zone

2021 ◽  
Vol 8 ◽  
pp. 55-79
Author(s):  
E. Bakhshi ◽  
A. Shahrabadi ◽  
N. Golsanami ◽  
Sh. Seyedsajadi ◽  
X. Liu ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Earth Model ◽  
Reservoir Properties ◽  
Stress Regime ◽  
Geomechanical Properties ◽  
Hydrocarbon Reservoir ◽  
Diagenetic Processes ◽  
Mechanical Earth Model ◽  
New Equation

The more comprehensive information on the reservoir properties will help to better plan drilling and design production. Herein, diagenetic processes and geomechanical properties are notable parameters that determine reservoir quality. Recognizing the geomechanical properties of the reservoir as well as building a mechanical earth model play a strong role in the hydrocarbon reservoir life cycle and are key factors in analyzing wellbore instability, drilling operation optimization, and hydraulic fracturing designing operation. Therefore, the present study focuses on selecting the candidate zone for hydraulic fracturing through a novel approach that simultaneously considers the diagenetic, petrophysical, and geomechanical properties. The diagenetic processes were analyzed to determine the porosity types in the reservoir. After that, based on the laboratory test results for estimating reservoir petrophysical parameters, the zones with suitable reservoir properties were selected. Moreover, based on the reservoir geomechanical parameters and the constructed mechanical earth model, the best zones were selected for hydraulic fracturing operation in one of the Iranian fractured carbonate reservoirs. Finally, a new empirical equation for estimating pore pressure in nine zones of the studied well was developed. This equation provides a more precise estimation of stress profiles and thus leads to more accurate decision-making for candidate zone selection. Based on the results, vuggy porosity was the best porosity type, and zones C2, E2 and G2, having suitable values of porosity, permeability, and water saturation, showed good reservoir properties. Therefore, zone E2 and G2 were chosen as the candidate for hydraulic fracturing simulation based on their E (Young’s modulus) and ν (Poisson’s ratio) values. Based on the mechanical earth model and changes in the acoustic data versus depth, a new equation is introduced for calculating the pore pressure in the studied reservoir. According to the new equation, the dominant stress regime in the whole well, especially in the candidate zones, is SigHmax>SigV>Sighmin, while according to the pore pressure equation presented in the literature, the dominant stress regime in the studied well turns out to be SigHmax>Sighmin>SigV.  

Exploring possible causative mechanisms for earthquakes triggered by hydraulic fracturing: examples from the Montney Basin, BC, Canada.

2020 ◽  
Author(s):  
Alessandro Verdecchia ◽  
Bei Wang ◽  
Yajing Liu ◽  
Rebecca Harrington ◽  
Marco Roth ◽  
...  
Keyword(s):  
British Columbia ◽  
Hydraulic Fracturing ◽  
Stress Transfer ◽  
Crystalline Basement ◽  
Hydraulic Stimulation ◽  
Horizontal Drilling ◽  
Wastewater Disposal ◽  
Earthquake Interaction ◽  
Single Well ◽  
Montney Formation

<p>The Dawson-Septimus area near the towns of Dawson Creek and Fort St. John, British Columbia, Canada has experienced a drastic increase in seismicity in the last ~ 6 years, from no earthquakes reported by Natural Resources Canada (NRCan) prior to 2013 to a total of ~ 200 cataloged events in 2013 – 2019. The increase follows the extensive horizontal drilling and multistage hydraulic fracturing activity that started to extract shale gas from the unconventional siltstone resource of the Montney Formation. In addition to hydraulic fracturing, ongoing wastewater disposal in the permeable sandstones and carbonates located stratigraphically above and below the Montney formation may also be contributing to elevated seismicity in the region. Earthquakes occur in close spatial and temporal proximity to hydraulic fracturing wells, at distances up to ~ 10 km. The expected diffusion time scales in the low-diffusivity siltstone rock units and the temporal and spatial scale of seismic activity beg questions about the possible processes controlling the location and timing of earthquakes.</p><p> </p><p>Here, we investigate the causative mechanisms for two of the largest events in the Montney Basin, British Columbia: the August 2015 M4.6 earthquake near Fort St. John, and the November 2018 M4.5 earthquake near Dawson Creek. Both events are thought to have occurred within the crystalline basement, ~2 km below the injected shale units (Montney formation).  We use a finite-element 3D poroelastic model to calculate the coupled evolution of elastic stress and pore pressure due to injection at several hydraulic fracturing stages. Initially, we consider a simple layered model with differing hydraulic parameters based on lithology. Subsequently, also considering the seismicity distribution for each sequence, we introduce hypothetic hydraulic conduits connecting the injection intervals with the crystalline basement, where the respective mainshock occurred. We test a range of permeability values (10<sup>-15</sup> m<sup>2</sup>– 10<sup>-12</sup> m<sup>2</sup>) commonly implemented for fault zones.</p><p> </p><p>Our results show that, for both cases, the poroelastic stress perturbation may be not sufficient to trigger events in the basement. Instead, a scenario with a high-permeability (10<sup>-13</sup> m<sup>2</sup>– 10<sup>-12</sup> m<sup>2</sup>) conduits connecting the Montney formation to the fault responsible for the mainshock could better explain the relationship between the hydraulic stimulation and the timing of the two M > 4 earthquakes. For the 2018 M4.5 event, aftershock distribution can be mainly attributed to earthquake-earthquake interaction via static Coulomb stress transfer from the mainshock slip. In addition to the modeling of single well/event sequences, future work will include the long-term poroelastic effect due to multiple disposal wells located in the region.</p>

Machine learning for geophysical characterization of brittleness: Tuscaloosa Marine Shale case study

2020 ◽  
Vol 8 (3) ◽  
pp. T589-T597 ◽  
Author(s):  
Mark Mlella ◽  
Ming Ma ◽  
Rui Zhang ◽  
Mehdi Mokhtari
Keyword(s):  
Machine Learning ◽  
Hydraulic Fracturing ◽  
Rock Physics ◽  
Physical Models ◽  
Data Sets ◽  
Reservoir Properties ◽  
Data Set ◽  
Geomechanical Properties ◽  
Marine Shale ◽  
Exploration And Production

Brittleness is one of the most important reservoir properties for unconventional reservoir exploration and production. Better knowledge about the brittleness distribution can help to optimize the hydraulic fracturing operation and lower costs. However, there are very few reliable and effective physical models to predict the spatial distribution of brittleness. We have developed a machine learning-based method to predict subsurface brittleness by using multidiscipline data sets, such as seismic attributes, rock physics, and petrophysics information, which allows us to implement the prediction without using a physical model. The method is applied on a data set from Tuscaloosa Marine Shale, and the predicted rock physics template is close to the calculated value from conventional inverted elastic parameters. Therefore, the proposed method helps determine areas of the reservoir that have optimal geomechanical properties for successful hydraulic fracturing.

High-Resolution Imaging of Hydraulic-Fracturing-Induced Earthquake Clusters in the Dawson-Septimus Area, Northeast British Columbia, Canada

2020 ◽  
Vol 91 (5) ◽  
pp. 2744-2756 ◽  
Author(s):  
Marco P. Roth ◽  
Alessandro Verdecchia ◽  
Rebecca M. Harrington ◽  
Yajing Liu
Keyword(s):  
British Columbia ◽  
Hydraulic Fracturing ◽  
Regional Scale ◽  
Double Difference ◽  
Multiple Fractures ◽  
Waveform Data ◽  
Regional Stress ◽  
Western Canada Sedimentary Basin ◽  
Well Stimulation ◽  
Montney Formation

Abstract The number of earthquakes in the western Canada sedimentary basin (WCSB) has increased drastically in the last decade related to unconventional energy production. The majority of reported earthquakes are correlated spatially and temporally with hydraulic fracturing (HF) well stimulation. In this study, we use waveform data from a new deployment of 15 broadband seismic stations in a spatial area of roughly 60×70km2, covering parts of the Montney Formation, to study the relationship between earthquakes and HF operations in the Dawson-Septimus area, British Columbia, Canada, where the two largest HF-related earthquakes in WCSB to date, an Mw 4.6 on 17 August 2015 and an ML 4.5 on 30 November 2018, have occurred. We use an automated short-term average/long-term average algorithm and the SeisComP3-software to detect and locate 5757 local earthquakes between 1 July 2017 and 30 April 2019. Using two clustering techniques and double-difference relocations of the initial catalog, we define event families that are spatially associated with specific wells, and exhibit temporal migration along a horizontal well bore and/or multiple fractures close to wells. Relocated clusters align in two dominant orientations: one roughly perpendicular to the maximum horizontal regional stress direction (SH) and several conjugate structures at low angles to SH. Comparing the two predominant seismicity lineations to regional earthquake focal mechanisms suggests that deformation occurs via thrust faulting with fault strike oriented perpendicular to SH and via strike-slip faulting with strike azimuth at low angles to SH. Local scale seismicity patterns exhibit clustering around individual HF wells, whereas regional scale patterns form lineations consistent with deformation on faults optimally oriented in the regional stress field.

Mudstone (“shale”) depositional and diagenetic processes: Implications for seismic analyses of source-rock reservoirs

2013 ◽  
Vol 1 (1) ◽  
pp. B7-B26 ◽  
Author(s):  
Bruce S. Hart ◽  
Joe H. S. Macquaker ◽  
Kevin G. Taylor
Keyword(s):  
Hydraulic Fracturing ◽  
Clay Minerals ◽  
Elastic Properties ◽  
Source Rock ◽  
Conceptual Models ◽  
Source Rocks ◽  
Geomechanical Properties ◽  
Fine Grained ◽  
Diagenetic Processes ◽  
Seismic Methods

Source-rock reservoirs are fine-grained petroleum source rocks (“shales” or “mudstones”) having geomechanical properties that allow those rocks to produce hydrocarbons at economic rates after stimulation by hydraulic fracturing. Many of the assumptions commonly adopted by geophysicists to characterize shales cannot be applied to source-rock reservoirs. For example, the mineralogies of many source-rock reservoirs are not dominated by clay minerals and so mathematical and/or conceptual models developed for clay-dominated mudstones are not appropriate and cannot be applied to them. Instead, mudstones of shale plays are generally dominated by biogenic calcite and/or quartz. We use terminology of sedimentary geology to show that anisotropy is scale-dependent in source-rock reservoirs, and we discuss the depositional and diagenetic processes that control these and other geophysical properties of interest. The mudstones of source-rock reservoirs may or may not be anisotropic at the lamination scale (i.e., millimeters), the scale commonly used to measure anisotropic parameters via core plugs, but they are nearly always anisotropic at the bedset (centimeters to several meters) and member (tens of meters) scales. Because of the anisotropic nature of mudstones, elastic properties are not scalars at the length/thickness scales that can be defined using seismic methods. Properties of interest are likely to be different parallel to bedding compared to perpendicular to bedding. Because of the subseismic scale of much of this variability, thin-bed effects are likely to influence the AVO behavior of source-rock reservoirs.

Latent seismicity driven by aseismic creep and enhanced pore-fluid pressure in NE British Columbia

2021 ◽  
Author(s):  
Rebecca O. Salvage ◽  
David W. Eaton
Keyword(s):  
British Columbia ◽  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Fluid Pressure ◽  
Fluid Injection ◽  
Maximum Magnitude ◽  
Dynamic Triggering ◽  
Global Pandemic ◽  
Pressure Diffusion ◽  
Montney Formation

<p>The global pandemic of COVID-19 furnished an opportunity to study seismicity in the Kiskatinaw area of British Columbia, noted for hydraulic-fracturing induced seismicity, during a period of anthropogenic quiescence. A total of 389 events were detected from April to August 2020, encompassing a period with no hydraulic-fracturing operations during a government-imposed lockdown. During this time period, observed seismicity had a maximum magnitude of M<sub>L</sub> 1.2 and lacked temporal clustering that is often characteristic of hydraulic-fracturing induced sequences. Instead, seismicity was persistent over the lockdown period, similar to swarm-like seismicity with no apparent foreshock-aftershock type sequences. Hypocenters occurred within a corridor orientated NW-SE, just as seismicity had done in previous years in the area, with focal depths near the target Montney formation or shallower (<2.5 km). Based on the Gutenberg-Richter relationship, we estimate that a maximum of 21% of the detected events during lockdown may be attributable to natural seismicity, with a further 8% possibly due to dynamic triggering of seismicity from teleseismic events. The remaining ~70% cannot be attributed to direct pore pressure increases induced by fluid injection, and therefore is inferred to represent latent seismicity i.e. seismicity that occurs after an unusually long delay following primary activation processes, with no obvious triggering mechanism. We can exclude pore-pressure diffusion from the most recent fluid injection, as is there is no clear pattern of temporal or spatial seismicity migration. If elevated pore pressure from previous injections became trapped in the subsurface, this could explain the localization of seismicity within an operational corridor, but it does not explain the latency of seismicity on a timescale of months. However, aseismic creep on weak surfaces such as faults, in response to tectonic stresses, in addition to trapped elevation pore-pressure could play a role in stress re-loading to sustain the observed pattern of seismicity.</p>

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