Author Identifier

Auby Baban

https://orcid.org/0000-0003-4447-7903

Date of Award

2023

Document Type

Thesis

Publisher

Edith Cowan University

Degree Name

Doctor of Philosophy

School

School of Engineering

First Supervisor

Stefan Iglauer

Second Supervisor

Alireza Keshavarz

Abstract

Carbon geosequestration (CGS) has been recognized as a strategic solution to prevent/counter the catastrophic consequences of climate change. However, despite recent cutting-edge technical research, predicting quantitative CO2 trapping in geological formations via capillary trapping is currently scarce. Moreover, several aspects of multiphase flow characteristics of CO2/brine/rock systems, that greatly impact carbon capture and containment security, require further investigations. Furthermore, combining carbon geosequestration with Enhanced Oil Recovery (EOR) is an efficient and economically attractive technology to reduce global warming caused by emissions of anthropologic CO2 from the combustion of fossil fuels, whereby it offsets some of the costs of CO2 extraction. The aim of CO2 geosequestration is to maximize the trapping of injected CO2 in subsurface geological formations, whilst the primary purpose of EOR is to enhance the recovery of the remaining oil in the reservoir. Among various subsurface processes, capillary trapping is a key storage mechanism that renders the injected CO2 immobile and securely contains the trapped CO2 for millions of years. The pore-scale properties, such as microscopic wettability, of the CO2-brinerock system closely correlated to the processes governing capillary trapping, and controls the Darcy-scale (macro-scale) flow functions, including Capillary Pressure (Pc) characteristics, Relative Permeability (Kr) measurements, Saturation history (Sw), and Pore-size Distribution (PSD), in the pore space. Thus, understanding these petrophysical characteristics is essential to the successful implementation of CGS-EOR technologies. Furthermore, the management of CO2 storage capacity and containment integrity as well as recovery of additional oil in subsurface geological formations is significantly impacted by the physicochemical characteristics (wettability) of the targeted reservoirs, which has not been adequately reported and has been scarcely documented in the scientific literature. More specifically, has not been verified with versatile techniques such as Nuclear Magnetic Resonance (NMR). Thus, it is of vital importance to understand the wetting characteristics of storage formation and its impact on pore-scale physics in the pore network, which dominates pore-scale multiphase flow and ultimately controls overall field‐scale fluid dynamics. In this study, robust Nuclear Magnetic Resonance (NMR) was used to investigate three aspects of wettability:

i) The impact of the rock surface's physicochemical properties (wettability) on capillarity and capillary trapping in CO2-brine-rock systems.

ii) The effect of hydrophobic, oil-wet, rock surfaces on the pore-scale flow mechanics, which has a substantial impact on enhanced oil recovery (EOR) and residual CO2 trapping in the multiphase flow of CO2/brine/oil systems - (CGSEOR).

iii) The influence of organic compounds that are naturally found in geological formations on residual CO2 trapping in carbonate geological formations, ranging from pore-scale to reservoir-scale observations.

This dissertation aimed at addressing longstanding uncertainties about the wetting characteristics of CO2-brine-rock systems under reservoir conditions, which are typical of CO2 storage in subsurface formations including saline aquifers and hydrocarbon reservoirs. Previous studies, using various techniques, have indicated that the wetting property of CO2-brine-rock systems is influenced by pressure, temperature, and brine salinity. Here, we present data on the impact of the microscopic wettability on the relative permeability (kr) and capillary pressure (Pc) characteristic curves as a function of reservoir conditions for water-wet and oil-wet San Saba sandstone samples, during drainage (CO2 displacing brine). These multiphase flow petrophysical parameters were found to have a major impact on CO2 trapping determination and significantly e affect geostorage integrity; i.e. capacities and containment security, over reservoir-scale implementations, as well as the outlining CO2-EOR project designs in terms of CO2-EOR and CO2 geosequestration budgets.

The microscopic wettability measurements via independent Nuclear Magnetic Resonance (NMR) experiments on sandstone (CO2–brine systems) to quantify Wettability Indices (WI) using the United States Bureau of Mines (USBM) scale, during drainage, to determine capillary pressure characteristic curves and relative permeability for a water-wet San Saba sandstone were measured at pressure of 8 MPa, temperature of 333 K, and ionic strength (3 mol kg-1 NaCl + 2 mol kg-1 KCl). The exposure to CO2 (either molecularly dissolved or as a separate supercritical phase) during drainage significantly reduced the hydrophilicity of the sandstone from strongly water-wet to weakly water-wet. This reduction in hydrophilicity was attributed to additional protonation of surface silanol groups on the quartz, induced by carbonic acid (H2CO3). The physicochemical properties of a strongly oil-wet, which is CO2-wet, using similar tests were conducted under the same conditions on an identical analogous oil-wet core, rendered the sample intermediate-wet. The NMR transverse relaxation time (T2) response is correlated with Pore Size Distributions (PSD), whereby residual CO2 trapping was shown to be significantly lower than that of an analogous waterwet sandstone sample. These results were then compared with that in the literature, whereby a general consistency was found for CO2-brine-sandstone systems in multiphase flow properties across a wide range of reservoir conditions.

Saline aquifers are abundant and cover the vast majority of storage sites for permanently sequestrating CO2, whereby combining CGS with EOR in multiphase flow oil reservoirs is an effective and economically attractive technology to mitigate global warming, as it offsets some of the costs of CO2 extraction. The targeted oil reservoirs, however, display oil-wet characteristics, primarily because of the strong affinity of polar molecules present in oil; a mixture of a large number of chemical compounds to the rock's surface; and oil-wet surfaces drastically reduce the storage capacity of geological trapping mechanisms and increase the vertical migration of CO2. Accordingly, we characterised the effect of the wettability of rock on pore-scale physics in a pore network that dominates Three- Phase Flow, which in turn controls overall reservoir‐scale fluid dynamics, and thus determines residual CO2 trapping and the success of CO2‐EOR projects. The motivation of this work is to understand the residual CO2 (capillary) trapping mechanism for subsurface oil reservoirs and simultaneously measure how much additional oil can be produced, which in turn underpins geostorage capacities and containment security, over reservoir-scale implementations. The results of the CO2-brine system show that residual trapping of supercritical CO2 in an oil-wet (hydrophobic) San Saba sandstone was significantly lower than that of analogous water-wet (hydrophilic) rock. In the oil-wet sample, a maximum residual CO2 saturation of 12% was measured, which is significantly lower than the 23% of CO2 trapping in the analogous water-wet sample. T1-T2 2D Maps and Transverse Relaxation Time (T2) measurements were used to quantify residual CO2 (capillary) trapping and to systematically measure how much additional oil can be produced (CGS-EOR) in multiphase flow systems for carbonate reservoirs that encounter 60% of global oil reservoirs. The results show a decrease in CO2 trapping and lower oil production in oil-wet samples. We have investigated the root cause of this decline in capillary trapping and reduction in oil volume production in CO2-wet rock samples. This is the first multi-scale study using NMR directly to uncover pore-scale displacement physics and saturation configurations in the pore space (pore occupancy) that can be used to improve geo-storage integrity and containment security over reservoir-scale implementations, in addition to improving the outlining of future CO2-EOR projects. The results of T1-T2 2D images demonstrated pore-scale configurations of the fluids subsequent to supercritical CO2 and brine injections. The high-intensity area (red band), which represents 1H content, was fragmented severely following the introduction of scCO2 (drainage), while the brine reinjection (imbibition) did not recombine the red pigments completely. The decline in T2 incremental volumes to lower T2 values (which are proportional to the oil/water saturations) is due to CO2 displacing water from large pores. Contrastingly, the brine reinjection did not displace all the CO2. The scCO2 was disconnected in the form of individual clusters and was trapped as ganglia in the large pores, facilitating the desaturation of oil that leads to enhanced oil recovery. The dataset is exclusively coherent, with results demonstrating the impact of microscopic wettability on capillary trapping and enhanced oil recovery over reservoir-scale CO2-EOR implementations.

This work, therefore, enhances understanding of scCO2 processes at the pore scale in porous media, thus aiding in the implementation of field-scale CO2 geosequestration by increasing the certainty of geosequestration and carbon capture and storage schemes. This, in turn, supports decarbonisation initiatives via net-zero, i.e. cutting climate pollution to zero, and substantially improves knowledge of CO2 injection in oil reservoirs (CO2-EOR) for future projects whilst contributing to further securing energy supply which are among the most economically appealing projects.

DOI

10.25958/ny7r-1152

Available for download on Saturday, September 28, 2024

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