Amanda Bustin - Academia.edu (original) (raw)

Papers by Amanda Bustin

Energies

The geochemistry of produced fluids has been investigated in the Triassic Montney Formation in th... more The geochemistry of produced fluids has been investigated in the Triassic Montney Formation in the Western Canadian Sedimentary Basin (WCSB). Understanding the geochemistry of produced fluids is a valuable tool in the exploration and development of a complex petroleum system such as the Montney Formation. The petroleum system changes from in situ unconventional reservoirs in the west to more conventional reservoirs that contain migrated hydrocarbons to the east. The workflow of basin modeling and mapping of isomer ratio calculations for butane and pentane as well as the mapping of excess methane percentage was used to highlight areas of gas compositional changes in the Montney Formation play area. This workflow shows the migration of hydrocarbons from deeper, more mature areas to less mature areas in the east through discrete pathways. Methane has migrated along structural elements such as the Fort St. John Graben as well as areas that have seen changes in higher permeability lithol...

The APPEA Journal

The distribution and origin of hydrogen sulfide (H2S) within gas reservoirs is an important issue... more The distribution and origin of hydrogen sulfide (H2S) within gas reservoirs is an important issue due to its toxicity and ability to corrode metal infrastructure, even at low concentrations (i.e. 50 ppm). H2S gas is regarded as a high priority for health and safety at drilling sites. The distribution of H2S, in some basins, can be inexplicable with a mix of sweet (no H2S) and sour (contains H2S) wells within one multi-well pad. Sour gas is a concern in some gas and coal fields in Australia which include Gippsland, Bowen and Cooper-Eromanga basins as well as in the North West Shelf with typical concentrations below 10 000 ppm. For example, the German Creek Formation (Bowen Basin) contains up to 77 ppm of H2S gas and coal seam gas producers will need to perform a risk assessment while exploring and developing this resource. There are multiple sources of H2S gas sulfur and this includes sulfate minerals, pyrite, organic sulfur or from frack water. This research utilises the isotopic va...

Day 1 Mon, April 25, 2022

Cyclic injection-flowback (huff and puff, HnP) of natural gas or carbon dioxide has been shown to... more Cyclic injection-flowback (huff and puff, HnP) of natural gas or carbon dioxide has been shown to improve the recovery of oil from low permeability, low porosity shale reservoirs. However, natural gas and carbon dioxide are limited in effectiveness and utility; natural gas has a high miscibility pressure and high mobility and hence potential for leak-off and inter-well communication; carbon dioxide is not readily available, is costly, and corrosive. In this study, a novel shale oil HnP EOR process, utilising a liquid solvent comprised of mixtures of propane and butane (C3 and C4), referred to as SuperEORTM (Downey et al, 2021), was evaluated for its efficacy in recovering oil compared to methane and carbon dioxide. The advantages of the propane and butane solvent are its low miscibility pressure with the produced oil, it is injected as a liquid, and is easy to separate and recycle. In this study, an Eagle Ford shale core with produced Eagle Ford oil and a Permian Wolfcamp shale core...

Engineering, 2020

A key unknown limiting assessment of risk posed by inducing anomalous seismicity during hydraulic... more A key unknown limiting assessment of risk posed by inducing anomalous seismicity during hydraulic fracturing is the potential maximum magnitude of an event. To provide insights into the variation in maximum magnitude that can be induced by a hydraulic fracturing stage, worst-case scenarios were simulated in 2D using coupled hydro-geomechanical models. The sensitivity of the magnitude to the hydro-geomechanical properties of the fault and matrix rock were quantitatively compared through parametric analysis. Our base model predicts a maximum event with moment magnitude (M w) 4.31 and M w values range from 3.97 to 4.56 for the series of simulations. The highest magnitude is predicted for the model with a longer fault and the lowest magnitude for the model with a smaller Young's modulus. For our models, the magnitude is most sensitive to changes in the Young's modulus and length of the fault and least sensitive to changes in the initial reservoir pressure (i.e. pore pressure) and the Poisson's ratio.

Minerals, 2019

A sediment core was retrieved from an area adjacent to a Pulp and Paper Mill in Howe Sound, Briti... more A sediment core was retrieved from an area adjacent to a Pulp and Paper Mill in Howe Sound, British Columbia, in order to examine the accumulation dioxins (PCDDs) and furans (PCDFs). Downcore distribution of TOC in the bulk samples is relatively uniform (0.5–1.7 wt. %). Bulk PCDD/F concentration shows selective enrichment and depletion at specific sediment horizons, and a low to moderate correlation with surface area (r2 = 0.23–0.54). TOC in size fractionated sediments ranges from 0.3–11 wt. % and shows a moderate correlation with surface area (r2 = 0.51). The relationship between PCDD/Fs and surface area is congener specific, ranging from no significant correlation (TCDD; r2 = 0.05), to a good correlation (i.e., OCDF; r2 = 0.74). Results indicate that both dioxin and furan concentrations are related to organic matter concentration, molecular chlorination and sediment surface area.

Engineering, 2018

The modelling results from numerical simulations of the Early Cretaceous, Mannville coal measures... more The modelling results from numerical simulations of the Early Cretaceous, Mannville coal measures with anisotropic permeability provide insights into development strategies not readily visualized or otherwise intuitive. The complex relationships between water and gas production, the contribution from multiple coal seams as well as from organic rich shales, and the impact of well interference combined with anisotropic fracture permeability are investigated through a series of numerical simulations of four well-pads (on the corners of a square mile of land with decreasing well spacing from 1, 3, to 4 laterals per pad). After 25 years of production, the two pads with optimally-oriented laterals with respect to the fracture permeability anisotropy produce 61% of the recovered gas for the 1 lateral/pad model, 52% for the 3 laterals/pad model, and 50% for the 4 laterals/pad model. Downspacing has a greater impact on increasing the gas production from pads with the poorly-oriented main laterals than from the pads with the optimally-oriented main laterals. The cumulative gas production at the end of the 25 year history is 4.2% higher for an optimally-oriented pad (pad1) and 1.1× higher for a poorly-oriented pad (pad3) for a model with 4 laterals/pad than 3 laterals/pad and an optimally-oriented pad is 1.1% higher for an optimally-oriented pad and 1.5× higher for a poorly-oriented pad for a model with 3 laterals/pad than 1 lateral/pad. Although downspacing from 3 to 4 laterals/pad has a greater impact on increasing the cumulative gas production from optimally-oriented pads than downspacing from 1 to 3 laterals/pad, the lower impact on poorly-oriented pads results in a lower total increase the cumulative gas production from the four pads.

International Journal of Geosciences, 2019

The contribution to production of the gas stored within the coal and shale beds adjacent to the m... more The contribution to production of the gas stored within the coal and shale beds adjacent to the main coal seam in the Mannville Group, in which a lateral is drilled, was investigated through a series of numerical simulations. The results indicate that the added gas from the minor coal seams, with interbedded shales with no gas, results in 1.4 times (×) more produced gas and 3.0× more produced water after 25 years of production than when only the main Mannville coal seam is considered. Including gas in the shales results in 1.7× more produced gas and 2.5× more produced water after 25 years of production than when only the main coal seam is considered. The produced gas recovered from the shales exceeds the produced gas recovered from the coals after ~8.5 years, resulting in 2.1× more produced shale gas than coal gas after 25 years of production. Over half (56%) of the produced coal gas after 25 years of production is recovered from the main coal seam while a quarter (22%) is recovered from the L1 seam, which is the thickest and nearest minor coal seam to the horizontal wellbore located in the main seam. The results from the numerical simulations provide insights that are not intuitive or otherwise predictable in developing complex reservoirs. Although the results are specifically for the Mannville producing fairway, undoubtedly the production from minor coal seams and interbedded gas shales should be considered in other producing and potential coal gas reservoirs to identify higher producible reserves and optimize drilling and completions strategies.

Engineering, 2017

Numerical simulations are used to investigate the impact of intrinsic and extrinsic reservoir pro... more Numerical simulations are used to investigate the impact of intrinsic and extrinsic reservoir properties on the production from coal and organic rich lithologies in the Lower Cretaceous Mannville coal measures of the Western Canadian Sedimentary Basin. The coal measures are complex reservoirs in which production is from horizontal wells drilled and completed in the thickest coal seam in the succession (1 m versus 3 m), which has production and pressure support from thinner coals in the adjacent stratigraphy and from organic-rich shales interbedded and over and underlying the coal seams. Numerical models provide insight as to the relative importance of the myriad of parameters that may impact production that are not self-evident or intuitive in complex coal measures.

International Journal of Coal Geology, 2016

Abstract A nitrogen flood, ECBM micro pilot was carried out in a deep, low permeability Cameo coa... more Abstract A nitrogen flood, ECBM micro pilot was carried out in a deep, low permeability Cameo coal zone of the Mesavede Group in the Piceance Basin. The pilot project entailed the injection of about 28 mmcf (7.9E5 m 3 ) of nitrogen over a period of 15 days at pressures about 650 psig (4482 kPa) above the initial reservoir pressure, followed by a soak period of 15 days, and subsequently 11 days of flow back. The nitrogen flood was a failure inasmuch as there was no pressure change nor nitrogen or methane breakthrough in three closely adjacent monitoring wells, which were considered necessary to meet the metrics required for a field scale economic ECBM project. The results of the pilot test, in conjunction with subsequent laboratory field simulation tests and numerical modeling, are consistent in that they show injection of nitrogen, of necessity above reservoir pressure, neither displaced methane nor promoted methane desorption from the low permeability Cameo coal. The results suggest the injection of nitrogen above reservoir pressure increases the total adsorbed gas resulting in swelling of the coal, which increases the effective stress and hence decreases permeability, the reverse of what is intended. The field, laboratory, and numerical results indicate that for a nitrogen ECBM flood to initiate, in coal such as studied here, the in situ permeability must be high enough that nitrogen can displace, and thus reduce the partial pressure for methane. The results thus indicate that ECBM production by nitrogen flooding will only work in coals where the pre-existing permeability is high enough that conventional coalbed methane production is possible or has already been carried out. Results of our studies provide learnings relevant to carbon dioxide sequestration and ECBM for coals of similar properties to those of this study. An initial high permeability is critical, particularly for carbon dioxide injection, due to its higher volumetric strain coefficient and greater adsorption affinity than methane or nitrogen. Such high in situ permeability exists mainly in shallow coals, which also have the potential of being exploited in the future as a resource and hence may not be viable sites for long term carbon dioxide sequestration.

International Journal of Coal Geology, 2016

The Lower Cretaceous Mannville coal measures in south central Alberta host one of the most succes... more The Lower Cretaceous Mannville coal measures in south central Alberta host one of the most successful horizontal coal methane developments, yet the contribution of thin coal seams and other organic rich strata to total gasin-place and producible gas remains unaccounted. In this study, well log, core, fluid, and gas analyses in the Mannville coal measures are evaluated in order to quantify and characterise the total gas-in-place resource that may be accessed by a horizontal well completed in the main coal seam which is the usual practise. Regionally, the estimated gas capacity and content of the coals increases from northeast to southwest in parallel with the depth of burial and the level of organic maturation (rank), although local variations exist. The isotopic composition of the methane of coals currently at depths greater than 1500 m have a strong thermogenic signature, shallower coals have a mixed biogenic-thermogenic signature, and the shallowest coals have a strong biogenic signature. The trend in gas composition is less well defined with the highest carbon dioxide contents occurring in the area of the lowest and highest ranks. Generally, the percentage of heavier gases (C 2-C 5) increases with maturity/depth of burial, but some low rank coals (Ro% ≈ 0.30) in eastern Alberta and Saskatchewan contain significant C 2-C 5 hydrocarbons. The origin of the heavier gases in the low rank coals is unclear; migration from a deeper source is the most likely explanation. The gas adsorption capacity of the coals varies regionally with depth of burial (pressure), coal rank, and ash content. The highest adsorption capacity at reservoir pressure and temperature, approaches 400 1 scf/t, but most coals have values between 260 and 320 scf/t. The gas content of the coals, as measured by desorption, ranges from 230 to 350 scf/t and averages 310 scf/t. Most of the coals are saturated with gas within the accuracy of the analyses. Notable exceptions occur adjacent to the Saskatchewan border where the lower rank coals may be markedly under saturated. The amount of methane in solution (calculated) at a reservoir pressure of ≈1000 psig (6.9 MPa) is calculated to be between 7 and 10 scf/t (≈3% of total gas). Currently, Mannville coal gas production is limited to an area in central Alberta of about 2200 km 2 (850 miles 2). Outside the producing fairway, sustained commercial production has not been achieved due to low permeability. In the producing and prospective fairway, the net thickness of the coal within ± 20 m of the main coal seam, varies from 0 to 10.8 m and averages 5.1 m. Here the thickest coal seam ranges up to 4.7 m thick and averages 1.9 m. Due to limited gas content data from core for all seams and wells, a protocol was developed to extrapolate existing core data to non-cored seams and wells through petrophysical logs. The protocol takes into consideration the correlation between gas and ash content and the maturity of the coals. The total coal gas resource density in the current area of production and prospective areas determined by applying this protocol for the average well has a low estimate of 5.4 BCF/mi 2(2) (m 3 /km 2) , a median estimate of 5.9 BCF/mi 2 , and a high estimate of 6.1 BCF/mi 2 .

Along the western margin of central British Columbia and southern Alaska, the Queen Charlotte (QC... more Along the western margin of central British Columbia and southern Alaska, the Queen Charlotte (QC) and Fairweather faults accommodate most of the predominantly transform motion (~50 mm/yr) between the Pacific and North American plates. This fault system is ~1000 km long and was the locus of M=7-8 earthquakes in the last century. Off the Queen Charlotte Islands, the relative Pacific/North

All Days, 2008

The heterogeneity and complexity of gas shales cause substantial and often inexplicable variabili... more The heterogeneity and complexity of gas shales cause substantial and often inexplicable variability in the production histories of gas wells. A major factor contributing to this variability is the microfabric of the matrix and the fracture network of the reservoir. It is widely postulated, although not proven, that the gas production from shales is controlled principally by Darcy flow through the fracture system and the matrix is considered important principally for gas storage. In order to gain insight and test the relative importance of fracture spacing and matrix diffusion/flow on the production of gas shales, we have developed a 2-dimensional numerical simulation model, which considers the flow of gas through both the shale matrices and the fractures for varying fabrics utilising experimental data obtained from a variety of important gas shales. The results of initial, constant parameter, numerical simulations showed that for a wide range of relative fracture permeability, matri...

All Days, 2008

Characterising the pore structure of gas shales is of critical importance to establish the origin... more Characterising the pore structure of gas shales is of critical importance to establish the original gas in place and flow characteristics of the rock matrix. Methods of measuring pore volume, pore size distribution, and sorptive capacity of shales, inherited from the coalbed methane and conventional reservoir rock analyses, although widely applied, are of limited value in characterising many shales Helium which is routinely used to measure shale skeletal and grain density, permeability and diffusivity, has greater access to the fine pore structure of shale than larger molecules such as methane. Utilizing gases other than He to measure porosity or flux requires corrections for sorption to be incorporated in the analyses. Since the permeability of shales vary by several orders of magnitude with effective stress, methods that do not consider effective stress such as crushed permeability, permeability from Hg porosimetry, and from desorption are of limited utility and may be at best ins...

International Journal of Coal Geology, 2012

Abstract As the development of unconventional gas resources has progressed, the heterogeneity and... more Abstract As the development of unconventional gas resources has progressed, the heterogeneity and complexity of shales as gas and oil reservoirs have become apparent. The production histories from shales, both within a sequence of interbedded strata and from adjacent wells, commonly exhibit inexplicable variations and predictions from numerical modeling are rarely accurate. As a result of the variability in the reservoir and rock parameters of gas shales, the complex interaction between the shale properties and the producibility of the reservoir is seldom apparent. One of the most difficult parameters to quantify is the fabric. This study compares the relative importance of the fabric parameters of gas shales on their producibility using a commercial numerical simulator and field and laboratory determined rock properties. The fabric parameters include the stress-dependent fracture permeability, which controls the gas transport through the fracture network, as well as the effective fracture spacing, which controls the path length for gas transport through the matrix, and the stress-dependent matrix permeability, which controls the gas transport through the matrix. The results of the numerical simulations show that for a wide range of stress-dependent fracture permeabilities, stress-dependent matrix permeabilities, and fracture spacings, the productivity of a gas shale reservoir is limited by inefficient gas transport through the matrix. The matrix permeability below which gas production is subeconomic is not a specific value, but varies with the effective fracture spacing and with fracture permeability. The matrix permeability and effective fracture spacing have a greater impact on the producibility of strata with larger fracture permeabilities. The influence of the effective fracture spacing on production is greater than the influence of the matrix permeability. The lower production associated with a large fracture spacing (or a small matrix permeability) can be offset by a large matrix permeability (or a small fracture spacing). The production simulations also show the strong dependence on the geomechanical properties of the rock, which affect how the gas transport through the matrix and fractures changes with stress. The influence of the geomechanical properties on the producibility depends on whether the production is limited by the gas transport through the matrix. When the fabric parameters result in a matrix-independent production (small fracture spacing, large matrix permeability, small fracture permeability), the production is solely controlled by the stress-dependent fracture permeability, with larger initial fracture permeability, larger Young's modulus, and larger Poisson's ratio resulting in higher production. In this case, Young's modulus is much more influential than the Poisson's ratio. When the fabric parameters result in a matrix-limited production, the rock mechanics parameter α , which relates the exponential decline of matrix permeability with effective stress, has the strongest influence on the producibility. The influence of Poisson's ratio on producibility not only varies with the fabric parameters, but also with the Young's modulus and α . When the production is matrix-limited, a smaller Poisson's ratio results in a higher production for all cases except when both α and Young's modulus are small.

Geophysical Journal International, 2007

The Queen Charlotte Fault zone is the transpressive boundary between the North America and Pacifi... more The Queen Charlotte Fault zone is the transpressive boundary between the North America and Pacific Plates along the northwestern margin of British Columbia. Two models have been suggested for the accommodation of the ∼20 mm yr −1 of convergence along the fault boundary: (1) underthrusting; (2) internal crustal deformation. Strong evidence supporting an underthrusting model is provided by a detailed teleseismic receiver function analysis that defines the underthrusting slab. Forward and inverse modelling techniques were applied to receiver function data calculated at two permanent and four temporary seismic stations within the Queen Charlotte Islands. The modelling reveals a ∼10 km thick low-velocity zone dipping eastward at 28 • interpreted to be underthrusting oceanic crust. The oceanic crust is located beneath a thin (28 km) eastward thickening (10 •) continental crust.

Geofluids, 2009

Permeability and diffusivity are critical parameters of tight reservoir rocks that determine thei... more Permeability and diffusivity are critical parameters of tight reservoir rocks that determine their viability for commercial development. Current methods for measuring permeability and ⁄ or diffusivity may lead to erroneous results when applied to very tight rocks including gas shales, coal, and tight gas sands, as well as rocks considered as seals for nuclear waste repositories and strata for geological sequestration of CO 2. The use of He as routinely applied to measure porosity, permeability, and diffusivity may result in non-systematic errors because of the molecular sieving effect of the fine pore structure to larger molecules such as reservoir gases. Utilizing gases with larger adsorption potentials than He, such as N 2 , and including all reservoir gases to measure porosity or permeability of rocks with high surface area is a viable alternative, but requires correcting for adsorption in the analyses. This study expands several approaches to measure permeability and diffusivity with considerations for gas adsorption, which has not been explicitly considered in previous studies. We present new models that explicitly correct for adsorption during pulse-decay measurements of core under reservoir conditions, as well as on crushed samples used to approximate permeability or diffusivity. We also present a method to determine permeability or diffusivity from on-site drill-core desorption test data as carried out to determine gas in place in coals or gas shales. Our new approach utilizes late-time data from experimental pressure-decay tests, which we show to be more reliable and theoretically (and practically) accurate than the early-time approach commonly used to estimate gastransport properties.

Fuel, 2013

ABSTRACT Small-angle and ultra-small-angle neutron scattering (SANS and USANS), low-pressure adso... more ABSTRACT Small-angle and ultra-small-angle neutron scattering (SANS and USANS), low-pressure adsorption (N2 and CO2), and high-pressure mercury intrusion measurements were performed on a suite of North American shale reservoir samples providing the first ever comparison of all these techniques for characterizing the complex pore structure of shales. The techniques were used to gain insight into the nature of the pore structure including pore geometry, pore size distribution and accessible versus inaccessible porosity. Reservoir samples for analysis were taken from currently-active shale gas plays including the Barnett, Marcellus, Haynesville, Eagle Ford, Woodford, Muskwa, and Duvernay shales.

Canadian Journal of Earth Sciences, 2013

The southern Coast Mountains of British Columbia are characterized by voluminous plutonic and gne... more The southern Coast Mountains of British Columbia are characterized by voluminous plutonic and gneissic rocks of mainly Middle Jurassic to Eocene age (the Coast Plutonic Complex), as well as metamorphic rocks, folds, and thrust and reverse faults that mostly diverge eastward and westward from an axis within the present mountains, and by more localized Eocene and younger normal faults. In the southeastern Coast Mountains, mid-Cretaceous and younger plutons intrude Bridge River, Cadwallader, and Methow terranes and overlap Middle Jurassic through Early Cretaceous marine clastic rocks of the Tyaughton–Methow basin. The combination of geological data with new or reanalyzed geophysical data originating from Lithoprobe and related studies enables revised structural interpretations to be made to 20 km depth. Five seismic profiles show very cut-up and chaotic reflectivity that probably represents slices and segments of different deformed and rearranged rock assemblages. Surface geology, seis...

Energies

The APPEA Journal

Day 1 Mon, April 25, 2022

Engineering, 2020

Minerals, 2019

Engineering, 2018

International Journal of Geosciences, 2019

Engineering, 2017

International Journal of Coal Geology, 2016

All Days, 2008

International Journal of Coal Geology, 2012

Geophysical Journal International, 2007

Geofluids, 2009

Fuel, 2013

Canadian Journal of Earth Sciences, 2013