Robert Marc Bustin

Storage of carbon dioxide in depleted shale reservoirs represents a great opportunity to mitigate climate change events by offsetting part of the CO₂ emissions from the energy sector. The Montney Formation is a widely developed, low porosity and permeability unconventional shale oil and gas reservoir in northeastern British Columbia and western Alberta. Due to existing midstream infrastructure, it is an ideal candidate for CO₂ sequestration, which can potentially be coupled with CO₂-enhanced hydrocarbon recovery (EHR). This thesis investigates the potential to store carbon dioxide within representative Montney shale oil and gas pools, and coupling CO₂ sequestration with EHR.The Montney Formation is primarily composed of quartz and dolomite, although their relative abundances are spatially and stratigraphically variable. Clay content ( 20 wt.%) is comprised of exclusively non-swelling clays, and organic matter is found in trace amounts ( 5 wt.%). Exposure to supercritical CO₂-rich water has a negligible impact on mineral abundances, with only notable changes in calcite and dolomite wt.%. Apparent supercritical CO₂ matrix permeability, ranging between 3.45×10⁻⁴ to 4.07×10⁻² mD, is greater than the apparent gas and liquid CO₂ permeabilities. The higher apparent matrix permeability to supercritical CO₂ compared to the gas or liquid phase is attributed to the properties of the supercritical phase and the higher molecular kinetic energy, which promotes slip flow on the pore walls. The low permeability of the Montney Formation, coupled with the high capillary entry pressure, ensures that the injected CO₂ will be contained within the formation with insignificant leakage risks. Carbon dioxide storage capacities vary among investigated Montney pools. The Northern Montney pool has a significant storage capacity but exhibits poor reservoir properties for CO₂ storage compared to the Kakwa and Waskahigan Montney pools. Exploiting CO₂ injection for enhanced hydrocarbon recovery provides an opportunity to support more carbon-neutral hydrocarbon production with subsequent CO₂ storage. Supercritical CO₂ and a propane/butane (C₃/C₄) hydrocarbon mixture prove effective in recovering liquid hydrocarbons, with the C₃/C₄ mixture outperforming CO₂ at early Huff and Puff cycles and at heavy hydrocarbon mobilization. Supercritical CO₂ remains a viable recovery agent, recovering between 70 and 90% of the hydrocarbons in place.

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Unconventional shale reservoirs are commonly exploited by drilling horizontal wellbores up to several kilometers in length. Hydraulic fracture completions of a wellbore are designed, in part, based on the geomechanical properties of the reservoir. The completion program is executed in a series of stages, typically spaced at regular intervals along the length of the lateral, without consideration of variable lithology and geomechanical properties that may exist along the length of the borehole. Assessing the geomechanical properties and stress conditions along the lateral has proven difficult due to the cost and challenge of obtaining core samples for analyses. Drill cuttings derived during drilling provide an opportunity to characterize the reservoir geomechanical properties, including the elastic moduli. If such small samples can be tested reliably and be shown to be scalable to the reservoir, the geomechanical variability along a wellbore can be measured and exploited with planned hydraulic fracture completions at geomechanical sweet spots. In this thesis, the utility of instrumented indentation for characterizing geomechanical variation in shale core chips and drill cuttings is evaluated. Indentation testing on mineral and shale samples assesses the effects of indentation and sample parameters on indentation results, suggesting that samples of size 841 µm, tested at 50 – 200 mN load, with at least 83 standard indentations are likely to provide repeatable and representative mean indentation results. Indentation can characterize geomechanical variability between shale core chips and drill cuttings samples with centimeter differences in sample depth. Repeatable indentation results are compared for indentation tests, as well as unoriented and oriented subsamples; oriented subsamples showed 2 – 18 % greater mean indentation modulus in samples with bedding oriented parallel to the direction of indentation, compared to bedding perpendicular, indicating the effects of mechanical anisotropy on indentation results. Moderate correlations are presented between mean indentation modulus and static (R² = 0.53) and dynamic (R² = 0.45) Young’s moduli, for Montney Formation shales. Geomechanical correlations with mineralogy suggest mean indentation results are controlled by dominant, stiff components of shale, with minimal influence from clay composition. Variability in indentation results can be applied as an index through geomechanical depth profiles.

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Vast resources of unconventional gas and, potentially natural gas liquids occur in shales in north-eastern British Columbia (NEBC) in Devonian mudrocks. The reservoir properties and present-day petroleum systems of these Devonian mudrocks in NEBC (Liard Basin, Horn River Basin and Cordova Embayment) and Western Alberta have been investigated in this research. In the study area, perspective gas and oil shale reservoirs include the Horn River and Muskwa formations and equivalent horizons within the Besa River Formation of the Liard Basin. The Muskwa and Horn River formations are largely over mature with respect to the oil window within NEBC with maturity decreasing from west to east. Quartz (mainly biogenic in origin) is the dominant mineral, particularly within the Muskwa Formation where quartz content has an average of 71 wt%. The Horn River Formation contains more carbonate and clay minerals than the Muskwa Formation with an average quartz content of only 43 wt%. TOC content ranges from 1 % to 12%, with an average of 2.9%. TOC is highest within the Muskwa Formation and Evie Member of the Horn River Formation. Quartz and TOC exhibit similar trends on a regional scale with the highest quartz and TOC found within the central and northern portions of the Horn River Basin. Porosity values range from 1 to 9% with an average of 5% in the Muskwa Formation and 3.5% in the Horn River Formation. One dimensional basin models constructed at 24 well locations across the study area demonstrate the impact of different geological events on the depth of burial and present day thermal maturity of the basin. In all of the models, peak burial (and peak maturity) occurred during foreland subsidence. The timing of hydrocarbon generation varies greatly across the study area due to varying amounts of subsidence during the Paleozoic, differing heat flow regimes, and the depth of maximum burial during foreland subsidence with the onset of generation ranging from the Carboniferous in the Liard Basin to the Late Cretaceous in Western Alberta. The results of the basin models can help identify potential areas of condensate production within NEBC.

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The Montney Formation is the principal unconventional hydrocarbon reservoir currently being developed in Canada. The flowback water from 31 wells located on 9 well pads was sampled over time and analyzed for major ions, key minor ions, and δ¹⁸O and δ²H isotopes. The injected hydraulic fracturing fluids and produced waters, if available, were analyzed for the same parameters. The results of the study are used to compare the flowback water chemistry between wells and investigate the variables that have a significant influence on the chemistry. When comparing the flowback water chemistry between multiple wells, consideration must be given to the length of the flowback period, as the major ion concentrations typically increase over time. The dominant influence on the increasing concentrations is mixing between hydraulic fracturing fluid and formation water. Cl and stable water isotopes were used as conservative tracers to calculate the increasing proportions of formation water. These proportions were used with geochemical models to determine that mixing explains the Na and K concentrations, while mixing with ion exchange is influencing Ca, Mg, and Sr concentrations. Sulfate concentrations are influenced by pyrite oxidation and sulfate reduction. The rate of increase of the major ions varies between wells, although it is often, but not always, similar between wells completed at the same site, due to similarities in reservoir properties and well completion. The inconsistency is due to the many variables that may impact the flowback water chemistry. A multiple regression analysis identified shut-in time as an important variable, with longer shut-in correlating to higher concentrations. The chemistry of hydraulic fracturing fluids and formation waters were found to be important variables for some ions. The minor ions included in the study are Ba, B, and Li. Ba concentrations are likely related to barite dissolution/precipitation and are highest where sulfate concentrations are low. B and Li concentrations are both dominantly influenced by mixing and may vary due to differences in formation water chemistry. Overall, the results are expected to contribute to the growing knowledge on flowback water chemistry and its use in investigating the processes occurring in the reservoir during hydraulic fracturing.

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The Upper Devonian Big Valley Formation in southern Alberta is a 10-m thick carbonate succession, unconformably overlain by organic-rich source rocks of the Exshaw Formation. The Exshaw Formation is part of a global continuum of mudrocks deposited under anoxic conditions, representing a distinct interval in Earth’s climatic, terrestrial and marine evolution, and the generation of prolific hydrocarbon source rocks worldwide.This thesis summarizes the stratigraphic, depositional and diagenetic controls on reservoir development of the Big Valley Formation and its relationship to the Exshaw Formation. Data analyses involved stratigraphic top picks and regional correlations in an 84 well-log database, core study, seismic interpretation, petrographic and carbon isotope analyses and petrophysical measurements.The availability of more core and wireline data as a result of recent exploration led to refining of the stratigraphic framework in the study area. The Big Valley Formation is redefined in this study to consist of two informal units: upper (open-marine) and lower hydrocarbon-bearing (peritidal) units. Based on lithofacies analyses, the peritidal unit more appropriately fits with the Big Valley Formation, rather than its current assignment to the underlying Stettler Formation. The peritidal unit consists of four lithofacies: subtidal shoal peloidal packstone-grainstone, mid-to-high intertidal microbial laminite and laminated dolomudstone and a local intraclastic breccia-laminite related to tidal drainage channels. Each lithofacies is laterally discontinuous, variably dolomitized and ranges from 0.5-to-2.0-m thick.iiiIn some areas the Big Valley Formation is up to 25-m thick, with >4-m of shoal deposits that have excellent reservoir properties. Thickened Big Valley areas are underlain by thinned evaporite beds, and have a similar orientation as an underlying NNW/SSE structural lineament. This relationship suggests basement-controlled high-angle block faulting and/or salt dissolution and collapse of underlying Devonian evaporite beds during Big Valley deposition.The complex interplay between deposition and diagenesis has influenced reservoir quality. Dolomitized peloidal packstone-grainstones have high intercrystalline porosity (>5%) and permeability values (>0.20 md). Reservoir potential of the microbial laminites is dependent on dolomitization and lack of anhydrite cement. Non-reservoir lithofacies show low petrophysical properties (0.00001-0.002 md) as the result of a lack of dolomitization and/or extensive cementation.

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Porosity, methane sorption capacity, diffusivity and permeability of a suite of vitrinite-rich coals from the Horseshoe Canyon and Mannville formations of the Western Canada Sedimentary Basin were investigated. Coal rank ranges from subbituminous to medium volatile bituminous, equilibrium moisture is between 2.32%-23.75%, and ash is up to 72% although 20% on average. Total coal porosity estimated using mercury porosimetry and helium pycnometry is between 4.4% and 18%. Helium pycnometry porosity is higher than mercury porosimetry porosity because the smaller molecular diameter of helium allows it to access coal pores which are inaccessible to mercury at test pressures. Greater vitrinite content is generally correlated with higher coal total pore area due to the abundant microporosity in vitrinite.Coal methane sorption capacity is up to 23.5 cc/g on a moisture equilibrated basis and is up to 40.4 cc/g for dry coals. Moisture equilibrated and dry coals sorb differently due to competition for adsorption sites in coal between methane and moisture. No relationship is observed between sorption capacity and coal rank or between maceral content and sorption capacity because of the narrow rank and maceral composition of the samples studied.Permeability was investigated on crushed coals and plugs with crushed permeability not exceeding 1.79∙10⁻² md while plug permeability is up to 0.9 md. Average diffusivity is estimated to be around 10⁻¹¹ to 10⁻¹² m²/s.Coal matrix properties influence crushed permeability. Inertinite-rich coals have higher matrix permeability and diffusivity because of the greater macro- and meso- porosity of inertinite. Plug permeability is dependent on coal matrix properties and the presence of fractures on tested plugs. Coals with better developed fractures are more permeable than coals with poorly developed fractures at the same effective stresses. Probe gas type influences plug permeability. Helium permeability measurements are higher than permeability measured with methane or nitrogen. Permeability difference with probe gas is attributed to a combination of different probe gas molecule size, relative swelling effects of probe gas on coal and associated changes at in-situ stress during tests. Understanding the reasons for permeability variations in coals will help in more focused coal bed methane exploration and development.

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