Robert Marc Bustin


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Graduate Student Supervision

Doctoral Student Supervision (Jan 2008 - April 2022)
Petroleum system analysis of the Triassic Doig Formation, Western Canada Sedimentary Basin (2021)

The potential of the Doig Formation as an unconventional petroleum system was investigated inthis study. The Triassic Doig Formation of the Western Canada Sedimentary Basin extendscontinuously across northeast British Columbia and central western Alberta, and it is known as asource-rock for conventional reservoirs in the basin. This investigation encompasses the mappingof source-rock properties, characterization of reservoir properties related to hydrocarbons storagecapacity and producibility, lithogeochemistry and sedimentology of the basal phosphatic informalsubunit, and a 3D basin model for reconstructing and determining the timing of thermogenicgeneration of hydrocarbons, as well as their expulsion and migration. The Doig Formation contains kerogen of Type II and III and has fair to good source rock potential. Most of the Doig subcrop area is in the early oil window, grading to overmature dry gas towards the southwest. The Doig Formation is subdivided into the basal more organic-rich Doig Phosphate Zone (DPZ), with a median of 2.7% total organic carbon (TOC), and the upper Doig, with a median of 1.3%. Porosity ranges from 0.3 to 14.6% and matrix permeability ranges from 8×10⁻⁶ to 14 mD. Matrix permeability is controlled primarily by pore throat size. Total gas in-place ranges from 6.2to 9.7 trillion m³. Mineralogy is primarily composed of detrital quartz, diagenetic dolomite and calcite, in highly variable proportions. Clay content is low, with a median of 4.9% by weight, and apatite occurs as intraclasts and coated grains in phosphorite beds in the DPZ, which are interpreted to be a result of various phases of phosphatization, exhumation, and reburial. Mineralogy and TOC distributions reflect the fore-arc basin configuration with a southwestern paleo-high, and a connection to open marine environment to the north. Burial history reconstruction suggests subsidence rates of up to 390 m/Ma towards the Late Cretaceous, and removal of several kilometers of sediments during the Cenozoic. The Doig entered the oil window in the Albian, and generated a total mass of 69,000 million metric tons of petroleum. Approximately 50% of the gas generated may have been retained in the source-rock or migrated into tight and conventional Doig reservoirs.

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Reservoir Characterization of the Duvernay Formation, Alberta: A Pore-to-Basin-Scale Investigation (2015)

The reservoir properties of the Duvernay Formation mudrock gas and oil (“shale gas”) reservoir in Alberta were investigated. The investigation included an assessment of current methodologies utilized to study mudrocks, development of new methodologies, pore- to basin-scale characterization and integration of core data with wireline logs. The Duvernay exists over multiple thermal maturity boundaries and provides a laboratory to investigate numerous pertinent research questions. Deposition of organic-rich Duvernay mudrocks was controlled by the spatial relationship to Leduc reef complexes. Greater thicknesses (> 70 m) of Duvernay mudrocks are found within embayments where oxygenated water circulation was most restricted. The Duvernay progressively thins (
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Numerical simulation of hydraulic fracture, stress shadow effects and induced seismicity in jointed rock (2013)

Hydraulic fracturing provides a means to optimize shale gas completions by enhancing the permeability of what is otherwise very tight rock. However, the coupled nature of the processes involved (e.g., thermo-hydro-mechanical-chemical), interlinked with geological variability and uncertainty, makes it extremely difficult to fully predict the spatial and temporal evolution of the hydrofrac and surrounding invaded zone. Numerical design tools have been developed to contend with this complexity, but these have largely focused on the mechanics of brittle fracture propagation at the expense of making simplifying assumptions of the host geology within which the hydraulic fracture is propagating, namely treating it as a linear elastic continuum. In contrast, the reservoir rock conditions are much more complex. Present are natural discontinuities, including bedding planes, joints, shears and faults superimposed by the in-situ stress field. The natural discontinuities under the applied in-situ stress have the potential to either enhance or diminish the effectiveness of the hydraulic fracturing treatment and subsequent hydrocarbon production. Improved understanding of the interactions between the hydraulic fracture and natural fractures under the stress field would allow designers and operators to achieve more effective hydraulic fracturing stimulation treatments in unconventional reservoirs. To better account for the presence of natural discontinuities in shale gas reservoirs, this thesis investigates the use of the 2-D commercial distinct-element code UDECTM (Itasca Consulting Group, 1999) to simulate the response of a jointed rock mass subjected to static loading and hydraulic injection. The numerical models are developed to illustrate some important concepts of hydraulic fracturing such as the effect of natural fractures in fracture connectivity, effects of stress shadowing in multiple horizontal well completion, and the effect of fluid injection in induced seismicity, so they can be used to qualitatively evaluate the effects of the in-situ environment on the design and the consequences of the design on the in-situ environment.

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Master's Student Supervision (2010 - 2021)
Utility of instrumented indentation for the optimization of horizontal wellbore completions with examples from the Montney Formation of Alberta and British Columbia (2021)

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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Unconventional petroleum systems analysis of upper Devonian organic-rich shales in the Horn River and Liard Basins, and adjacent Western Canadian Sedimentary Basin (2020)

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
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An investigation into the controls and variability of the flowback water inorganic geochemistry of the Montney Formation, Northeastern British Columbia and Northwestern Alberta, Canada (2018)

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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Stratigraphic, depositional and diagenetic controls on reservoir development, Upper Devonian Big Valley Formation, southern Alberta (2014)

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 (
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Effects of Coal Composition and Fabric on Porosity, Sorption Capacity and Gas Flow Properties in Western Canada Sedimentary Basin Coals (2011)

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
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