In this First Break article, published in October 2024, TGS experts present a novel workflow for developing a basin-scale stratigraphic architecture for defining the major saline reservoirs and sealing units within a basin.
Introduction
Carbon Capture and Storage (CCS) is a proven and safe technology that involves capturing (purifying) carbon dioxide (CO2) released from point emission sources or directly removed
from the atmosphere, compressing it for transportation and then injecting it into a carefully selected subsurface reservoir for permanent storage. The success of CO2 storage relies heavily on the identification and characterisation of suitable subsurface reservoirs for secure and permanent storage. Geologic formations, whether they are depleted hydrocarbon or deep saline reservoirs, present unique challenges and opportunities for CO2 storage. The advantages of saline reservoirs over depleted hydrocarbon reservoirs include potential access to a large volume of available pore space, and a smaller number of well penetrations, which results in reduced risks of potential leakage pathways through these wells. However, the lack of comprehensive reservoir data in saline reservoirs increases uncertainty in defining reservoir confinement, cap rock integrity, and fluid flow behaviour. Therefore, saline reservoir storage assessment requires comprehensive reservoir characterisation and modelling to be carried out before large-scale CO2 storage planning is possible.
Figure: Regional cross-sectional view of Spontaneous Potential (SP) logs displaying depositional units for basin-scale mapping. The application enabled interactive interpretation of 12 formation tops across the study area and direct saving of standardised names and cross-section numbers to a cloud database for further quality assurance.
Some important parameters to consider for subsurface CO2 storage are depth of injection and density of CO2, which is dependent on subsurface temperature and pressure. The densityof CO2 increases with pressure at temperatures above critical conditions (Klins and Bardon, 1991). At about 1084 psi pressure and 88°F temperature, CO2 reaches a supercritical state (Qi et al., 2010), after which the volume decreases dramatically with depth, along with the increase in CO2 density. These conditions generally correspond to a depth of around 2600 to 3000 ft. In a supercritical state, CO2 acts as a gas-like compressible fluid, resulting in complete pore volume utilisation and mobility within a reservoir (Ketzer et al., 2012), with a liquid-like density. The main advantage of storing CO2 in a supercritical state is that the required storage volume is substantially less than what it would be at surface conditions (Donaldson, 2021). Most of the onshore and offshore sedimentary basins in North America have sufficient data for subsurface evaluation to identify regional fairways for CO2 storage. Integration of geological, geophysical, and petrophysical assessment from the well log data helps in evaluating deep saline reservoir zones for their storage suitability. The initial step in any subsurface assessment is to accurately map the geological units at the well level. This involves correlating these units along strike and dip-oriented sections to understand their distribution and variability across the basin. Building a basin-scale stratigraphic framework by correlating a large number of geophysical well logs is a crucial but labor-intensive process. This task is especially challenging in the study area allows ample opportunity for mapping and characterisation of the key geologic units for subsurface CO2 storage.
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