Monitoring aims

Plume: plume imaging and tracking in the reservoir

Click in the red box to show an example from a time‐lapse seismic survey over a CO2 plume (courtesy of the SACS and CO2STORE projects). Click again to hide the image.

The ability to explicitly image the plume of free CO2 and track its movement in the subsurface may be a pre‐requisite for many monitoring programmes. In the early stages of CO2 injection, plume imaging is likely to involve tracking/mapping free CO2 in the primary storage reservoir using time‐lapse seismic surveying.

Top‐seal: Reservoir top‐seal integrity

Close monitoring of the reservoir topseal for evidence of failure or leakage will be important, especially during the injection stage of a project. During this period, and for some time afterwards, reservoir pressures are likely to be significantly elevated immediately beneath the caprock. A maximum permissible (threshold) value is likely to have been determined during site characterisation, prior to injection. Evidence of reducing seal integrity or failure could be obtained from a number of monitoring techniques including direct detection or imaging of CO2, pressure changes in the reservoir or overburden, or changes in aquifer chemistry.

Overburden: Migration in the overburden (> 25 m depth)

The overburden comprises those rock units lying between the storage reservoir and the land surface (or seabed). The basal overburden unit comprises the reservoir caprock or topseal (for the purpose of the decision tool, monitoring the topmost 25 m or so of the overburden will be considered under surface leakage).

Monitoring in the overburden is likely to be required if CO2 has migrated from the storage reservoir. Many, though not all, of the techniques deployed for monitoring plume migration in the reservoir, would be equally suitable for monitoring migration in the overburden.

Processes: Subsurface quantification and fine‐scale processes

The mass of CO2 that has been injected for storage can be readily monitored at the wellhead. However in some circumstances it may be necessary to provide supporting evidence, through geological monitoring, that the mass of CO2 within the reservoir is equivalent or comparable to that injected and, within the bounds of uncertainty, that no losses have occurred.

Currently, accurate quantification of CO2 in the subsurface poses a serious technical challenge. State‐of‐the‐art analysis can show that quantitative estimates of CO2 derived from monitoring datasets are consistent with known injected amounts, but unique verification has not yet been achieved. Deployment of multiple monitoring techniques providing complementary datasets, either in terms of measured property, or in terms of measurement scale, can significantly reduce uncertainty.

Long‐term storage potential is influenced by a number of factors that include plume migration, CO2 solution in reservoir porewaters, structural and stratigraphical trapping and residual gas trapping in pore spaces. These processes are often influenced by fine‐scale variations in reservoir geometry, lithology, pore architecture and porewater chemistry. In addition, key reservoir parameters such as seismic velocity are influenced by fine‐scale processes such as fluid mixing scales. Specialised monitoring tools can be targeted on particular parts of the storage reservoir to help gain insights into these processes.

Calibrate: Calibration of predictive models

Predicting how the CO2 will be stored over the long‐term requires the integration of many geological processes in a predictive model. Such models require detailed site‐specific geological knowledge of the reservoir, caprock and overburden. By acquiring monitoring data on key processes and their interactions during and after injection, outputs from the predictive models can tested and calibrated, enabling the models to be suitably modified or rejected. This will decrease uncertainty in long term model predictions.

Detect: Surface leakage detection (<25m depth to air or water)

As well as defining storage performance, leakage to surface would be considered a significant irregularity. Monitoring technologies to detect surface leakage may well be routinely deployed prior to injection as part of the site baseline characterisation process. Repeat monitoring may be required to establish natural cycles in background variations. This will be especially relevant for onshore situations where diurnal, seasonal and annual variations in biogenic CO2 may need to be characterised, so that any future leaks can be identified and compared to background variations.

Additional monitoring might be required around facilities and infrastructure during injection, if leaks are identified or suspected. Early warning of leakage might be provided by other techniques providing surveillance of the reservoir and overburden. Monitoring may also be required to identify the source of any gas anomalies that may originate from the storage site.

Quantify: Surface emissions quantification

In the event that leakage to the atmosphere or ocean has been positively identified, quantification may be required to account for these emissions in national inventories, to adjust operator allowances and/or to initiate further financial transactions. Additional monitoring activities, remediation plans, regulator notification and licence conditions may also be affected by the quantified amount of CO2 leakage.

Seismicity: induced seismicity and earth movements

In some cases CO2 injection can lead to increased (micro) seismic activity and may in some circumstances, lead to ground movements, especially for shallower storage reservoirs. As well as covering safety aspects, such as the geomechanical integrity of the store, microseismic monitoring can also enable advancing CO2 fronts to be mapped in the subsurface. In favourable situations traveltime and attenuation tomography may allow fluid movements to be mapped.

Wellbores: well integrity

The ability of wells to retain CO2 during the injection, post‐injection and post‐closure phases, is an important issue in many storage situations. Geomechanical and, in the longer term, geochemical processes, can severely degrade well integrity. Mature hydrocarbon fields, especially onshore, are likely to contain significant numbers of wells of varying ages and styles of completion and abandonment. While new completion materials will greatly enhance the stability of new wells, older wells may need closer monitoring.