Robert Marc Bustin

Professor

Relevant Degree Programs

 

Graduate Student Supervision

Doctoral Student Supervision (Jan 2008 - May 2019)
New insights into pore structure characterization and permeability measurement of fine-grained sedimentary reservoir rocks in the laboratory at reservoir stress states (2018)

Fine-grained reservoir rocks are economically important because of the vast quantities of hydrocarbons they contain, but remain poorly understood due to how difficult it is to analyze their highly stress-sensitive, anisotropic, nanometer-scale pore systems in the laboratory. In this thesis, techniques for pore structure characterization and permeability measurement of fine-grained reservoir rocks at reservoir stress states are developed and tested.Klinkenberg gas slippage measurements provide accurate measurements of pore size. The gas slippage technique has many valuable characteristics, such as the ability to measure pore size at reservoir stress and to quantify anisotropy of pore geometry. In addition to pore size, matrix permeability is quantified when measuring gas slippage. The gas slippage technique developed in this thesis provides important petrophysical information about fine-grained reservoir rocks that cannot be acquired using other commonly applied pore structure characterization techniques.A technique to semi-quantitatively determine permeability-effective stress law coefficients is developed by analyzing Klinkenberg plots of permeability measurements made at a wide range of confining pressure and pore pressure. This semi-quantitative technique is important because other fully quantitative techniques that are typically applied to coarse-grained reservoir rocks result in erroneous effective stress laws when applied to fine-grained rocks; in the nanometer-scale pores of fine-grained rocks, gas slippage results in significant permeability variation with pore pressure that is independent of changes to pore geometry, and therefore results in erroneous permeability-effective stress laws.A technique for determining the effective permeability of fine-grained reservoir rocks at different fluid saturations is developed by measuring ethane gas permeability at a range of pore pressures up to the saturated vapour pressure of ethane at laboratory temperature. Liquid/semi-liquid ethane saturation increases with increasing pore pressure due to adsorption and capillary condensation, resulting in restricted fluid flow pathways and hence decreased effective permeability to ethane gas. Ethane gas permeability measurements can be made at different stress states to investigate the sensitivity of effective permeability to stress at the range of stress states experienced during production from a fine-grained reservoir.

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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 - 2018)
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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