An Assessment of the Net Fluid Balance in the Alberta Basin

Samaroo, Mahendra; Chalaturnyk, Rick; Dusseault, Maurice B.; Jackson, Richard H.; Buhlmann, Arndt; Custers, Hans

doi:10.3390/en15031081

Energies

2022

DOI: 10.3390/en15031081

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An Assessment of the Net Fluid Balance in the Alberta Basin

Mahendra Samaroo

Rick Chalaturnyk

Maurice B. Dusseault

et al.

Abstract: Net fluid balance in the Alberta Basin has been negative over the last 60 years because extensive fluid production has consistently exceeded injection during this period. However, future gigaton-scale carbon sequestration, among other activities, can result in future cumulative fluid injection exceeding extraction (i.e., a positive net fluid balance). The in-situ net fluid balance (i.e., total fluids produced minus total fluids injected) in this basin over the period 1960–2020 shows that a liquids deficit of 4… Show more

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Cited by 3 publications

References 81 publications

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Injection Temperature Impacts on Reservoir Response during CO2 Storage

Samaroo,

McClure,

Fowler

et al. 2024

SPE Journal

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Summary Sustained injection of industrial-scale volumes of cold CO2 into warmer subsurface rock will result in extensive cooling which can alter rock mass mechanical behavior and fluid migration characteristics. Advanced simulation tools are available to assess and characterize such phenomena; however, the effective use of these tools requires appropriate injection temperatures and rock thermophysical parameters (in addition to geomechanical and hydraulic properties). The primary objective of this study was to demonstrate the sensitivity of injection-induced tensile fracturing and fault reactivation to injection temperature and reservoir thermophysical properties during CO2 injection operations. This was achieved by (1) compiling and reviewing thermophysical parameter data available for formations in the province of Alberta, Canada, and CO2 injection temperature records for CO2 injection projects in western Canada and (2) using a 3D, physics-based, fully integrated hydraulic fracturing and reservoir simulation numerical model to examine the geomechanical response of several potential CO2 reservoirs in the Alberta Basin as a function of injection temperature, thermal conductivity (TC), and coefficient of linear thermal expansion (CLTE) values. The simulation results indicate that reducing the fluid injection temperature from 15°C (assumed in previous work) to 2°C (conservative value selected based on temperature data reviewed in this work) could trigger extensive vertical (20–130 m high, 100–600 m long) tensile fractures with rapid fracture initiation and full vertical growth within short periods (weeks to months) and continued horizontal length increase. When low values for thermophysical properties are used, the results show that thermally-induced tensile fracturing is unlikely, whereas the use of high values results in extensive tensile fracturing in all simulations. A similar conclusion was reached for the thermally-induced reactivation (unclamping) of proximal, critically-stressed faults. Notably, slip is predicted for all simulations where high thermophysical property values are used. This confirms that accurate determination of minimum fluid injection temperature and thermophysical parameters is important for containment risk assessment for commercial-scale CO2 storage projects. Another significant outcome of this work is the observation that most thermophysical parameters in the available data were measured using experimental conditions and/or temperature paths that are not representative of CO2 injection projects. As such, the development and validation of best practice approaches for accurate assessment of these parameters seem necessary.

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Injection Temperature Impacts on Reservoir Response during CO2 Storage

Samaroo,

McClure,

Fowler

et al. 2024

SPE Journal

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Assessment of the Brittle–Ductile State of Major Injection and Confining Formations in the Alberta Basin

et al. 2022

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Subsurface interaction between critically stressed seismogenic faults and anthropogenic fluid injection activities has caused several earthquakes of concern over the last decade. Proactive detection of the reverse and strike-slip faults inherent in the Alberta Basin is difficult, while identification of faults likely to become seismogenic is even more challenging. We present a conceptual framework to evaluate the seismogenic potential of undetected faults, within the stratigraphic sequence of interest, during the site-selection stage of fluid injection projects. This method uses the geomechanical properties of formations present at sites of interest and their current state of stress to evaluate whether hosted faults are likely to be brittle or ductile since the hazard posed by faults in brittle-state formations is generally significantly higher than that of faults in ductile-state formations. We used data from approximately 3100 multi-stress triaxial tests to calculate the Mogi brittle–ductile state line for 51 major injection and confining formations in the Alberta Basin and in situ stress and pore pressure data from approximately 1200 diagnostic fracture-injection tests to assess the last-known brittle–ductile state of each formation. Analysis of these data shows that the major injection formations assessed in the Alberta Basin were in a ductile state, with some confining (caprock) formations in a brittle state at the time of the stress measurements. Once current site-specific in situ stress data are available, our method enables site-specific assessment of the current brittle–ductile state of geologic formations within the zone of influence of large-volume fluid-injection projects and an evaluation of the associated potential for fault seismogenesis.

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Estimating Sustainable Long-Term Fluid Disposal Rates in the Alberta Basin

2023

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Reliable regional-scale permeability data and minimum sustained injectivity rate estimates are key parameters required to mitigate economic risk in the site selection, design, and development of commercial-scale carbon sequestration projects, but are seldom available. We used extensive publicly available disposal well data from over 4000 disposal wells to assess and history-match regional permeability estimates and provide the frequency distribution for disposal well injection rates in each of 66 disposal formations in the Alberta Basin. We then used core data and laboratory analyses from over 3000 cores to construct 3D geological, geomechanical and petrophysical models for 22 of these disposal formations. We subsequently used these models and the history-matched regional permeability estimates to conduct coupled geomechanical and reservoir simulation modeling (using the ResFrac™, Palo Alto, CA, USA, numerical simulator) to assess: (i) well performance in each formation when injecting carbon dioxide for a 20-year period; (ii) carbon dioxide saturation and reservoir response at the end of the 20-year injection period; (iii) reliability of our simulated rates compared to an actual commercial sequestration project. We found that: (i) the injection rate from our simulations closely matched actual performance of the commercial case; (ii) only 7 of the 22 disposal formations analyzed appeared capable of supporting carbon dioxide injectors operating at greater than 200,000 tons per year/well; (iii) three of these formations could support injectors operating at rates comparable to the successful commercial-scale case; (iv) carbon dioxide presence and a formation pressure increase of at least 25% above pre-injection pressure can be expected at the boundaries of the (12 km × 12 km) model domain at the end of 20 years of injection.

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An Assessment of the Net Fluid Balance in the Alberta Basin

Cited by 3 publications

References 81 publications

Injection Temperature Impacts on Reservoir Response during CO2 Storage

Injection Temperature Impacts on Reservoir Response during CO2 Storage

Assessment of the Brittle–Ductile State of Major Injection and Confining Formations in the Alberta Basin

Estimating Sustainable Long-Term Fluid Disposal Rates in the Alberta Basin

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