Carbon Capture and Storage

Carbon capture and storage (CCS) is a process in which a relatively pure stream of carbon dioxide (CO2) from industrial sources is separated, treated and transported to a long-term storage location. The aim is to reduce greenhouse gas emissions and thus mitigate climate change. The IPCC's most recent report on mitigating climate change describes CCS retrofits for existing power plants as one of the ways to limit emissions from the electricity sector and meet Paris Agreement goals. AEGeo’s expertise pertaining to CCS is in assessing options and capacity for long-term subsurface storage of CO2.

Options considered for permanent storage of CO2 include storage in deep geological formations (including depleted oil and gas fields, deep saline aquifers, unminable coal seams and saline-filled basalt formations), and solid storage by reaction of CO2 with metal oxides to produce stable carbonates. Storage capacity, containment efficiency and injectivity are the three factors that require major pre-assessment to decide the feasibility of CO2 storage in a candidate geological formation. To maximize capacity in case of subsurface storage, CO2 is preferably injected and stored in supercritical phase because of its favourable properties: a density slightly lighter than water but a viscosity close to that of a hydrocarbon gas. Impermeable caprock and a variety of fluid-dynamic and geochemical trapping mechanisms prevent the CO2 from escaping to the surface. As illustrated in diagrams below, even in supercritical phase CO2-density varies considerably with temperature and pressure with significant implications for subsurface storage capacity. Predicting CO2 phase and property behavior is therefore a key and integral element of any CO2 storage assessment.

Depleted gas fields can store significant quantities of CO2 with the added advantage of (typically) rich subsurface datasets from existing wells and seismic as well as insights on reservoir behaviour from historical production data. Depending on reservoir setting, properties and aquifer size, material balance assumptions ("what came out can go back in") could be applicable to estimation of storage capacity but in less favorable cases significant discounts (e.g., to cater for aquifer encroachment or buoyancy effects) might apply.  Gas fields with strong water-drive are akin a saline-aquifer play with a small gas attic. Limited sweep efficiency from CO2 injection in the water-invaded zone combined with significant water-saturation residual to CO2 may result in a significant storage-resource downside. This is illustrated in a series of pictures below.

Whilst it is reasonable to assume that injection of CO2 may at least repressurize the field to pre-production conditions without invoking significant leakage risks, integrity of existing (abandoned) wellbores under such a repressurization scenario would have to be verified. Formation damage, loss of injectivity and flow-assurance issues due to severe cooling around the wellbore in situations where dense supercritical CO2 enters a severely depleted reservoir (Joule-Thomson cooling effect) also need to be managed. AEGeo has developed methodology for quick storage-resource assessment depleted gas fields either at individual field or portfolio level. Example below shows a high-level inventory of the entire portfolio of in-production and depleted gas fields (mostly Miocene carbonate buildups) across Sarawak from a point of view of CCS potential. The screening methodology involved, per field, review of initial volumetric, PTV, aquifer strength and abandonment conditions. These parameters were used in combination with the fluid property differences between the original gas fill and a high-CO2 waste-stream to work out storage potential for CO2 at different pipeline and injection-pressure constraints.

Unminable coal seams can be used because CO2 molecules attach to the coal surface. Technical feasibility depends on the coal bed's permeability. In the process of absorption the coal releases previously absorbed methane, and the methane can be recovered (enhanced coal bed methane recovery). Methane revenues can offset a portion of the cost, although burning the resultant methane, however, produces another stream of CO2 to be sequestered.

Saline aquifers have occasionally been used for storage of chemical waste in a few cases. The main advantage of saline aquifers is their large potential storage volume and their ubiquity. The major disadvantage of saline aquifers is that relatively little is known about them. To keep the cost of storage acceptable, geophysical exploration may be limited, resulting in larger uncertainty about the aquifer structure. Unlike storage in oil fields or coal beds, no side product offsets the storage cost. Initial trapping during active CO2 injection would be mostly from structural trapping. Whilst over longer timescales and especially after end of injection, other trapping mechanisms like residual and hydrodynamic trapping, solubility trapping and mineral trapping become more significant; these are likely to slow down CO2 plume migration and eventually immobilize the CO2 underground. Some of the rewetting and hydrodynamic-trapping process complexities involved in long-term CO2 storage and plume immobilization are illustrated in the figure below.

From a point of view of CCS potential, depleted oil fields are to some extent similar to saline aquifers but with material quantities of residual oil in the field. This residual oil occupies part of the pore space that is hence taken away from the theoretical CO2 trapping capacity (unless it is produced during CO2 injection as part of an EOR scheme). On the other hand, at reservoir conditions oil (especially light oil) can adsorb very significant quantities of CO2, hence increasing solubility trapping potential. Similar to depleted gas fields, depleted oil fields typically have rich subsurface datasets from existing wells and seismic as well as insights on reservoir behaviour from historical production data. A possible limitation for CCS in depleted oil fields is compartmentalization (stratigraphically or by faults) leading to poor sweep and a need for high well counts, and/or limited aquifer size which could lead to excessive pressure buildup during CO2 injection.

AEGeo has developed a toolkit to assess the anticipated ranges in storage capacity in saline aquifers and depleted oil fields. Methodology used in the tool is aligned with the US-DOE CCS resource-assessment concepts (Goodman et al, 2011) for structural trapping. But in addition, solubility-storage potential of CO2 But in addition, solubility-storage potential for CO2 in the residual fluid fraction of the injected plumes (formation brine and, in case of depleted oil fields, residual oil), is also quantified, is also quantified. Methodology of assessment is outlined in figure below.

Outputs include expectation curves for the various elements comprising storage-resource, tornado charts illustrating the impact of subsurface uncertainty and CO2 phase diagrams illustrating reservoir conditions at start and end of injection. See figure below for a snapshot view of the tool inputs and outputs.

An essential element of any CO2-Storage Development scheme is a plan to monitor, measure and verify (MMV) CO2-plume behavior during and after injection, to ensure long-term integrity of the CO2-storage site. MMV plans may involve a range of physical measurements: at surface (e.g., CO2 detection), in the wells (pressure, CO2 detection) and also indirect geophysical measurements. In the latter category, timelapse (4D) seismic is a promising technique since in many typical CO2-storage settings,  compressional velocity of supercritical CO2 is much lower than that of the host fluids (e.g., water and residual oil) which is likely to result in a seismically-detectable acoustic contrast.

At project feasibility stage,  a screening study into the applicability 4D seismic for plume monitoring could involve the following:

• Construction of acoustic-property models covering the range of reservoir lithologies/properties, temperature/pressure and fluid fills anticipated at the storage sites;

• Simple fluid-substitution modelling of compressional acoustic properties to illustrate the impact of CO2 displacing in-situ reservoir fluids. Full elastic modelling might be attempted at later stages but would be complex as the shear-properties of supercritical CO2 are less well understood.

This could then be followed by creation of simple, vertical-incidence synthetic seismic traces for selected examples of wells, to illustrate how acoustic-property changes due to CO2 sweeping might alter the seismic response. AEGeo has developed a bespoke set of simple screening tools that cover the scope as explained; see pictorials below for some examples. More sophisticated modeling using specialist geophysical tools (e.g., RokDoc) could also be done but in general, is more valuable in the project definition stage.

A non-exhaustive list of Dr Arnout's CCS experience includes the following projects:

Sarawak CCS Technical Assurance and project reviews (Malaysia, 2024): Acting as the subsurface Technical Assurance panel member to support the regulator for CCS in Sarawak acreage. Activities to date include review of project robustness for the planned CO2 storage in depleted gas reservoirs of M1 (part of PETRONAS’ Kasawari project) and Golok (part of PTTEP’s Lang Lebah project), ad-hoc assistance to PETROS’ in-house compilation of an “atlas” of CCS opportunities across Sarawak, and provision of CCS introduction training to PETROS staff.

East of Shetland CCS Phase 3 – early risk assessment (UK, 2023): As part of a large integrated study of CCS feasibility across a series of assets, Dr Arnout's specific workscope elements comprised integrated subsurface-risk assessment, storage-resource assessment for a number of secondary reservoirs (saline aquifers) across the various assets, and 4D seismic feasibility for plume monitoring for each of the assets under study.

Sabah CCS feasibility study (Malaysia, 2023): support to reservoir model-building, dynamic simulation and conceptual injection strategy for CCS in turbidite sandstones of a depleted gas field.

Sarawak CCS options inventory (Malaysia, 2023): high-level inventory of the entire portfolio of in-production and depleted gas fields (mostly Miocene carbonate buildups) across Sarawak from a point of view of CCS potential. Target of the screening was to establish high-level technical feasibility of a large, integrated storage scheme of up to 0.15 Mtonne CO2 per day (56 Mtonne per annum). The screening methodology involved, per field, review of initial volumetric, PTV, aquifer strength and abandonment conditions. These parameters were used in combination with the fluid property differences between the original gas fill and a high-CO2 waste-stream to work out storage potential for CO2 at different pipeline and injection-pressure constraints.

CCS CarbonNet project (Victoria Gvt, Australia, 2016-17): geoscientist/advisor for the CarbonNet carbon capture and storage project which aims to store up to 6 Mtonne CO2 per annum in saline aquifers of the Pelican structure off Golden Beach in the Gippsland Basin. Scope included evaluation of alternative reservoirs for CO2 storage, geological considerations, compositional reservoir simulation, design of experiments.