Work package 1: impact of depletion and re-inflation on reservoir and caprock behaviour, testing hypotheses 1, 2 and 3 (Leeds, BGS, Edinburgh, NOC)


The seismic responses of different reservoirs to CO2 injection involve a number of process-related trade-offs. High quality (thick, permeable, mechanically compliant) reservoirs tend to have a large seismic sensitivity but show rather small pressure increases for given injection scenarios. Low quality reservoirs tend to have a lower seismic sensitivity but, conversely, show larger pressure increases for given injection scenarios. DiSECCS will have unique access to datasets which cover the reservoir quality spectrum. At Sleipner in the Utsira Sand, a high quality reservoir, statistical analysis of very small timeshifts has shown the possibility of constraining very small pressure changes (Chadwick et al., 2012). At Snøhvit, subtle seismic changes are indicating the potential for discrimination between saturation and pressure in a low quality reservoir (Figure 1). Uncertainties across the quality spectrum are currently high however and it has been suggested (Eiken and Tøndel, 2005) that rock physics data is not good enough to calibrate seismic properties in terms of pressure changes. By incorporating improved laboratory data from work package 3 we aim to reduce these uncertainties.

Task 1.1: hydromechanical simulations

Hydromechanical (coupled fluid-flow and geomechanical) simulation models will be constructed for a number of storage site scenarios, covering a range of reservoir types and injection configurations including Sleipner, Snøhvit and In Salah. These will explore the geomechanical controls on reservoir stress paths and determine the likelihood and type of significant geomechanical response (induced fracturing, fault reactivation, ground displacements, induced microseismicity, etc.) and also seismic response (changes in elastic and poro-elastic properties). The integrated seismic and hydromechanical modelling will use innovative workflows and algorithms (Angus et al., 2010; Angus et al., 2011; Segura et al., 2011; Verdon et al., 2011), which couple the finite element geomechanical solver ELFEN with the fluid flow simulator TEMPEST. The hydromechanical simulation will incorporate poro-elastoplastic constitutive models, and advanced rock physics models will be used to link changes in stress and fluid saturation to changes in seismic attributes.

Task 1.2: tool development and testing

Calculated reservoir parameter responses from task 1.1 will be transformed into synthetic seismic datasets (with realistic noise components) to allow computation of time-lapse seismic and induced seismicity attributes. Careful analysis of the information content of the seismic responses will allow us to determine which parameters can be robustly recovered from the data. Diagnostic tools will be tested on the synthetic datasets, including amplitude and attenuation versus offset and azimuth, waveform coda variation with azimuth and advanced statistical assessments of time shifts using improved techniques such as cross-correlation and waveform warping. We will build on recent research (Varela et al., 2007) to develop tools to analyse multi-azimuth seismic reflection data for fracture and fluid saturation properties. For passive seismics, we will test sensitivity of borehole and surface seismic arrays for induced seismicity detection, incorporating sufficiently accurate waveform simulation to model path effects (Usher, Angus and Verdon, in press) and to derive optimal array design and data processing algorithms.

Task 1.3: application to real case studies

The tools tested and calibrated on the synthetic datasets in task 1.2 will be deployed on datasets from Sleipner, In Salah and Snøhvit, to further calibrate the tools by history matching against real measurements including time-lapse seismic changes, induced geomechanical effects, microseismicity and observed surface displacements.