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Two sand-rich channelized depositional systems, fornled by strong contour currents, were studied west of the Faeroe Bank Channel and in the Gulf of Cadiz. Both are areas beyond the exit of constrictions where water overflows from the Norwegian Sea and the Mediterranean Sea, respectively. West of the Faeroe Bank, newly mapped channels are developed mainly under the influence of a geostrophic current and are characterized by significant lateral migration, which determines the marked cross-sectional asymmetry and the architecture of the deposits. The pathways of the Mediterranean Undercurrent in the Gulf of Cadiz are complex, with the greater proportion flowing under geostrophic conditions along a terrace but with some of the denser water becoming ageostrophic and descending downslope owing to gravity. A series of 'peeloff' channels is formed, with the largest one, Gil Eanes, being about 40 km long. Most of the channel fills consist of medium-coarse sand. Levees are mainly silts with a higher sand content in the vicinity of the channel. Both depositional systems have a variety of contoufite sand channels, which in most respects are remarkably similar. In both cases there are stretches where the flow is ageostrophic, with water descending downslope for as much as 400 m before resuming geostrophic flow at deeper levels. In each case the main pathway of the densest water is the shallowest and several branches turn off to the left of this main pathway before bending to the fight under the influence of Coriolis forces. In both cases there are channel fills of medium-coarse sand, probably cross-bedded, and up to 200 ms thick. Sheets of sand with a thickness of a few metres to a few tens of metres are common. Similarities to turbidite channels are the aggradational nature of some channel floors and the flanking muddy or silty sediment waves. Contourite channel depositional complexes are distinguished from turbiditic ones by their coarseningup rather than fining-up sand units, the asymmetry in channel architecture, the presence of regional unconformities, and the distribution pattern with well-marked boundaries of current-derived deposits.

Instrumenting wells with distributed acoustic sensors (DAS) and illuminating them with passive or active seismic sources allows precise tracking of temporal variations of direct-wave traveltimes and amplitudes, which can be used to monitor variations in formation stiffness and density. This approach has been tested by tracking direct-wave amplitudes and traveltimes as part of a CCS project where a 15 kt supercritical CO2 injection was monitored with continuous offset VSPs using nine permanently mounted surface orbital vibrators (SOVs) acting as seismic sources and several wells instrumented with DAS cables cemented behind the casing. The results show a significant (from 15 to 30%) increase of strain amplitudes within the CO2 injection interval, and travetime shifts of 0.3 to 0.4 ms below this interval, consistent with full-wave 1.5D numerical simulations and theoretical predictions. The results give independent estimates of the CO2 plume thickness and P-wave velocity reduction within it.

4D surface seismic monitoring is a standard method for reservoir surveillance during production of hydrocarbons or COlt;subgt;2lt;/subgt; injection. However, land 4D seismic acquisition is often associated with high cost and disruptions to industrial operation or agricultural activities in the area of acquisition. An alternative technique for time-lapse monitoring of the subsurface is 3D VSP, which becomes particularly attractive when used with distributed acoustic fiber optic sensors (DAS) installed in wells. The advantages of 3D DAS VSP include its relatively low cost, minimal footprint on the local area during acquisition, and superior spatial resolution compared to the resolution of geophones. The potential of this technique is explored by processing and analysing multi-well 3D DAS VSP data acquired at the CO2CRC Otway Project site in Victoria, Australia. The DAS data were recorded using an engineered fiber with enhanced backscattering cemented behind the casing of five wells. The data from each well are processed individually using the same processing flow and then migrated using a 3D migration code tailored to DAS data. Having DAS along the full extent of multiple wells ensures adequate seismic coverage of the area of CO2 injection. The migrated images provide detailed information about subsurface up to 700 m away from a well and up to 2 km depth. The images are consistent with previously acquired geophone VSP and surface seismic data. The quality of the 3D DAS VSP imaging is comparable or superior to the quality of conventional imaging using geophone data. Therefore, 3D DAS VSP is demonstrably an optimal solution for reservoir monitoring.

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