Shaina Kelly - Academia.edu (original) (raw)

Papers by Shaina Kelly

Bulletin of Canadian Energy Geoscience

The origin, timing, and evolution of hydrocarbons in the early Triassic Montney Formation siltsto... more The origin, timing, and evolution of hydrocarbons in the early Triassic Montney Formation siltstone has long been debated and is poorly understood. A proper understanding of the timing and processes involved in hydrocarbon emplacement forms an important part of in-situ fluid characterization. Presented here is a case study from northeastern British Columbia. This study integrates basin modeling, carbon isotope geochemistry, fluid inclusion microthermometry, organic and inorganic petrography, sedimentology, and stratigraphy to reconstruct the burial history and relative timing of geological events and mechanisms involved in developing the present-day Montney hydrocarbon system in the Blueberry sub-play. Petrography from whole core indicates that the organic material present is largely pyrobitumen. The lack of primary kerogen suggests that the original oil charge must have migrated into place prior to increasing thermal maturity and conversion to pyrobitumen at maximum burial. In addi...

Applicable flow regimes and diffusion as well as nano-pore capillary and surface force interactio... more Applicable flow regimes and diffusion as well as nano-pore capillary and surface force interactions are topics of great interest for fluid flow in unconventional reservoirs. Liquid flows in shale nano-pores have been wholly less subject to investigation than gas flows. Yet, the study of liquid and multi-component flows at the nano-scale is very important for understanding the interaction of free and bound water with hydrocarbons in shale systems, liquid-driven core analysis methods, and the fate of injected liquids (such as "fracking fluids") into the reservoir. The Young-Laplace equation for capillary pressure and the Washburn equation for imbibition rate are successfully applied in conventional media and have been applied to shale as well. Pore sizes are on the order of nanometers in shale, a scale that is theorized to mark a threshold for new transport phenomena considerations. This work investigates imbibition with various fluids - ketones, alcohols, aqueous solutions, and alkanes - at the nano-scale and reveals compelling evidence that long range intermolecular, electrostatic, and solvation surface interactions play a significant role in nano-capillary imbibition. Experiments are conducted in a pore size distribution of unconnected, fabricated silica and borosilicate glass nanochannels, which serve as a proxy for water-wet nano-pores in shale. The calculated capillary pressures based on the directly measured experimental results for imbibition lengths differ from the macroscopically predicted results by one order of magnitude. Additionally, in many fluid cases, the trend of the capillary pressure curves derived from the data show a decrease in capillary pressure with a decrease in channel size, or a "dewetting trend." This trend is contradictory to the prediction of the Young-Laplace formula. Accordingly, as the size of the pores decreases the relative scale of surface interactions increases, possibly leading to a departure from a regime dominated by Laplacian pressure to one strongly influenced by disjoining pressure. A positive correlation is found between the saturation of the imbibing fluid into the bundle of nanochannels and the calculated, unique disjoining pressure of the fluid.

Petrophysics, Jun 1, 2022

A novel interpretation workflow was developed using an automated unsupervised learning algorithm ... more A novel interpretation workflow was developed using an automated unsupervised learning algorithm on nuclear magnetic resonance (NMR) T1-T2 log data to quantify fluid-filled porosity and saturation, producible oil volumes, and to characterize matrix pore sizes and formation wettability. Core porosity and saturation measurements, scanning electron microscope images (SEM), Rock-Eval pyrolysis, wettability measurements, and mercury injection capillary pressure (MICP) tests are compared with the NMR interpretation for calibration and validation. Understanding in-situ fluid types and volumetrics is key for reservoir characterization. The traditional static formation evaluation model based on triple-combo logs (density, neutron, resistivity, and gamma ray) has been widely used to characterize formations to provide cost-effective answers of lithology, total porosity, and water saturation. Nevertheless, the dynamic result from production often shows quite a different water cut than total water saturation because the static model cannot distinguish immobile hydrocarbons from producible oil. NMR log data show unique signatures of formation fluids, such as gas, immobile hydrocarbon, producible oil, T1-T2 immobile, and free water. The NMR data also provide a method to interpret fluid and matrix properties, including fluid viscosity, pore geometry, and fluid-pore interaction. However, due to the downhole environment and the resolution limitation of the logging tool, the signatures of the fluids are not always well separated. It is challenging to visually separate the signal contributions of different formation fluids on T1-T2 maps. An automated unsupervised learning algorithm based on non-negative matrix factorization (NMF) and hierarchical clustering (Venkataramanan et al., 2018) is implemented in the new workflow to separate T1-T2 signatures of different pore fluids, enabling fluid typing and providing quantitative fluid-filled porosities and associated saturations. T1-T2 signatures of separated fluids are used to characterize fluid mobility, pore sizes, and formation wettability. The new approach is successfully applied to multiple wells for a field case study to characterize the saturation and producibility of hydrocarbon and water, which routine petrophysical models are unable to distinguish. Results are corroborated with dynamic production data showing high free water and high residual oil. This is also validated by routine and special core analyses. Integration of NMR, MICP, and SEM gives pore-body and pore-throat-size distributions with body-to-throat ratio (BTR), increasing the precision of estimated formation permeability. A high T1/T2 ratio of the oil suggests that the formation is partially oil-wet. The wettability results from NMR are consistent with the core wettability test and production results. Understanding which portion of a reservoir contains mobile fluids impacts target zone selection and reserves estimation.

Proceedings of the 11th Unconventional Resources Technology Conference

Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description

Standardized and benchmarked wettability characterization and quantification workflows are lackin... more Standardized and benchmarked wettability characterization and quantification workflows are lacking in unconventional reservoir development. Quantification of in-situ wettability and changes due to wettability alteration efforts can assist with completions decisions, and economic oil production. This manuscript summarizes the establishment and validation of an NMR wettability index (NWI) for unconventional rocks. The method builds upon Looyestijn’s NMR wettability analysis methods for conventional rocks and has been tested on core plug samples from a variety of major producing unconventional reservoirs. It will be of interest to readers to note the marked range of wettability values quantified among the aforementioned tight formations. Our NWI model is well suited for data sets featuring complex oil and water T2 spectra with multiple peaks, common features of unconventional rock spectra. The results were subjected to comprehensive experimental and analytical validation, including com...

Fluid in place: crude oil Capillary number: high Fracture status: disconnected, M2

$Research paper thumbnail of A Microfluidics Study to Quantify the Impact of Microfracture Properties on Two-Phase Flow in Tight Rocks$

Proceedings of the 9th Unconventional Resources Technology Conference, 2021

SPWLA 60th Annual Logging Symposium Transactions, 2019

Fuel, 2019

Micro-and nanoscale surface roughness within subsurface rocks is ubiquitous due to weathering and... more Micro-and nanoscale surface roughness within subsurface rocks is ubiquitous due to weathering and diagenesis. To assess the impacts of surface roughness on non-wetting gas flooding operations, we conducted immiscible drainage experiments in glass micromodels representing single-scale rock matrices with identical pore topology but varying degrees of surface roughness. The experiments were performed in capillary-dominated regimes where air was the non-wetting phase and crude oil was the wetting phase, emulating an enhanced oil recovery or non-aqueous phase liquid phase remediation process. We find that, for approximately constant pore-space topology, surface roughness (quantified with the average hillock height to pore depth ratio, Ω) has minor impact on sweep efficiency when Ω < 5.5%. However, once a critical threshold value of Ω > 12.5% is reached, recovery becomes consistently 10% higher and gas breakthrough occurs at later times. In addition, the roughest micromodel displays the highest repeatability of dendrite pathways validating diagenetic controls on gas flood sweep efficiency. We also find that surface roughness does not considerably affect the morphology of nonwetting phase dendrites and phase topology versus air saturation curves. Sub-pore scale visualizations in the micromodels indicate that contact-line pinning, the phenomenon responsible for higher sweep and greater dendrite tortuosity, only occurs in the roughest micromodel with Ω > 12.5%, whereas pendular rings and grain-lining thin films occur in all of the micromodels. Non-local snapoff occurs in micromodels regardless of roughness. The effects of isolated fracture surface roughness on capillary trapping saturations is found to be negligible for both drainage and imbibition saturation cycles. However, the presence of an isolated fracture diverts gas dendrites from sweeping the matrix and therefore increases oil trapping by approximately 10-30% compared to the micromodels without fractures. The workflow and experimental results in this paper provide benchmarking opportunities for direct numerical simulation algorithms for porous geomaterials. In addition, the paper aims to highlight the nontrivial implications of surface roughness for reservoir quality assessment and various subsurface operations.

Computational Geosciences, 2019

Nanoscale, 2016

Phenomenological models for deformation of nanoscale menisci and effective conduit diameters are ... more Phenomenological models for deformation of nanoscale menisci and effective conduit diameters are required to explain stymied imbibition of various liquids into 2D lyophilic nanochannels and potentially other nanoporous domains.

Proceedings of the 3rd Unconventional Resources Technology Conference, 2015

We create two-dimensional (2D) and three-dimensional (3D) physical representations of shale pore ... more We create two-dimensional (2D) and three-dimensional (3D) physical representations of shale pore networks using cleanroom nanofabrication methods and agarose polymer and experimentally investigate two-phase fluid transport in these nanoscale domains. A key question uniquely addressed by these experiments is whether unconventional imbibition and permeability trends observed in shale are mainly due to breakdowns in continuum fluid flow descriptions in nanoscale pore spaces or the atypical local connectivity of the pore networks. Furthermore, the experiments reveal whether nanoscale transport is governed by interfacial or viscous and diffusive forces for varying solid-liquid and solid-liquid-gas conditions. These findings can potentially lead to improved understanding and predictions of the reach and timescale of fluid release and hydraulic communication between fractures and the adjacent shale matrix, especially with a priori knowledge of fracture and reservoir fluids and rock compositions.

Advances in Water Resources, 2016

Highlights  We investigate if 3D models from FIB-SEM image stacks are a suitable REV for shale. ... more Highlights  We investigate if 3D models from FIB-SEM image stacks are a suitable REV for shale.  Data includes groups of local 2D and 3D images and corresponding core measurements.  Image analysis of image stacks and LBM fluid flow simulations are performed.  We conclude that FIB-SEMs are not suitable domains for permeability simulations.  Averaging local 2D and 3D images can provide representative volumetric properties.

International Communications in Heat and Mass Transfer, 2008

The influence of nozzle selection and consequent impact of momentum thickness is rarely investiga... more The influence of nozzle selection and consequent impact of momentum thickness is rarely investigated in heated horizontal plane jets. In the present work an experimental study is performed using a two dimensional converging nozzle and then by attaching a channel to the nozzle with air issued at a moderate Reynolds number of 4000 and at an inlet temperature of 60 °C. A hotwire anemometer is used to measure velocity and temperature fields. The ratio of heat to momentum transport is 1.33 for nozzle jets and 1.4 for channel jets. Half widths based on mean excess temperature and velocity is higher for channel jets. The influence of buoyancy is negligible for the present case. But the spread of temperature as a scalar is important in the transport process.

Langmuir, 2015

Liquid imbibition, the capillary-pressure-driven flow of a liquid into a gas, provides a mechanis... more Liquid imbibition, the capillary-pressure-driven flow of a liquid into a gas, provides a mechanism for studying the effects of solid−liquid and solid−liquid−gas interfaces on nanoscale transport. Deviations from the classic Washburn equation for imbibition are generally observed for nanoscale imbibition, but the identification of the origin of these irregularities in terms of transport variables varies greatly among investigators. We present an experimental method and corresponding image and data analysis scheme that enable the determination of independent effective values of nanoscale capillary pressure, liquid viscosity, and interfacial gas partitioning coefficients, all critical transport variables, from imbibition within nanochannels. Experiments documented herein are performed within two-dimensional siliceous nanochannels of varying size and as small as 30 nm × 60 nm in cross section. The wetting fluid used is the organic solvent isopropanol and the nonwetting fluid is air, but investigations are not limited to these fluids. Optical data of dynamic flow are rare in geometries that are nanoscale in two dimensions due to the limited resolution of optical microscopy. We are able to capture tracer-free liquid imbibition with reflected differential interference contrast microscopy. Results with isopropanol show a significant departure from bulk transport values in the nanochannels: reduced capillary pressures, increased liquid viscosity, and nonconstant interfacial mass-transfer coefficients. The findings equate to the nucleation of structured, quasi-crystalline boundary layers consistently ∼10−25 nm in extent. This length is far thicker than the boundary layer range prescribed by long-range intermolecular force interactions. Slower but linear imbibition in some experimental cases suggests that structured boundary layers may inhibit viscous drag at confinement walls for critical nanochannel dimensions. Probing the effects of nanoconfinement on the definitions of capillary pressure, viscosity, and interfacial mass transfer is critical in determining and improving the functionality and fluid transport efficacy of geological, biological, and synthetic nanoporous media and materials.

GEOPHYSICS, 2014

We have developed a new pore-scale method to quantify petrophysical properties of hydrocarbon (HC... more We have developed a new pore-scale method to quantify petrophysical properties of hydrocarbon (HC)-bearing shale. Recent studies indicate that slip flow, Knudsen diffusion, Langmuir desorption, and diffusion in kerogen contribute to the unconventional production properties of shale-gas formations. Conventional petrophysical interpretation methods do not account for the aforementioned phenomena and are often inconclusive when estimating petrophysical properties in shale formations. We constructed a pore-scale representation of the lower Eagle Ford Shale based on focused-ion-beam–scanning-electron-microscope (FIB-SEM) images. Permeability is calculated via previously developed finite-difference methods for the cases with and without slip flow and Knudsen diffusion. The method also calculates streamlines to describe sample pore connectivity. Weighted throat-size distributions are defined based on streamlines to represent the most resistive paths for fluid flow in the FIB-SEM image. Sub...

xv 8.3.2.4 Task 4: Utilize emergent nanoscale phenomena for enhanced flow control in nanoconfinem... more xv 8.3.2.4 Task 4: Utilize emergent nanoscale phenomena for enhanced flow control in nanoconfinements .