High-resolution seismic experiments, employing arrays of closely spaced, four-component ocean-bottom seismic recorders, were conducted at a site off western Svalbard and a site on the northern margin of the Storegga slide, off Norway to investigate how well seismic data can be used to determine the concentration of methane hydrate beneath the seabed. Data from P-waves and from S-waves generated by P-S conversion on reflection were inverted for P-and S-wave velocity (Vp and Vs), using 3D travel-time tomography, 2D ray-tracing inversion and 1D waveform inversion. At the NW Svalbard site, positive Vp anomalies above a sea-bottomsimulating reflector (BSR) indicate the presence of gas hydrate. A zone containing free gas up to 150-m thick, lying immediately beneath the BSR, is indicated by a large reduction in Vp without significant reduction in Vs. At the Storegga site, the lateral and vertical variation in Vp and Vs and the variation in amplitude and polarity of reflectors indicate a heterogeneous distribution of hydrate that is related to a stratigraphically mediated distribution of free gas beneath the BSR. Derivation of hydrate content from Vp and Vs was evaluated, using different models for how hydrate affects the seismic properties of the sediment host and different approaches for estimating the background velocity of the sediment host. The error in the average Vp of an interval of 20-m thickness is about 2.5%, at 95% confidence, and yields a resolution of hydrate concentration of about 3%, if hydrate forms a connected framework, or about 7%, if it is both pore-filling and framework-forming. At NW Svalbard, in a zone about 90-m thick above the BSR, a Biot-theory-based method predicts hydrate concentrations of up to 11% of pore space, and an effective-medium-based method predicts concentrations of up to 6%, if hydrate forms a connected framework, or 12%, if hydrate is both pore-filling and frameworkforming. At Storegga, hydrate concentrations of up to 10% or 20% were predicted, depending on the hydrate model, in a zone about 120-m thick above a BSR. With seismic techniques alone, we can only estimate with any confidence the average hydrate content of broad intervals containing more than one layer, not only because of the uncertainty in the layer-by-layer variation in lithology, but also because of the negative correlation in the errors of estimation of velocity between adjacent layers. In this investigation, an interval of about 20-m thickness (equivalent to between 2 and 5 layers in the model used for waveform inversion) was the smallest within which one could sensibly estimate the hydrate content. If lithological layering much thinner than 20-m thickness controls hydrate content, then hydrate concentrations within layers could significantly exceed or fall below the average values derived from seismic data.

We present a new petro-elastical and numerical-simulation methodology to compute synthetic seismograms for reservoirs subject to CO 2 sequestration. The petro-elastical equations model the seismic properties of reservoir rocks saturated with CO 2 , methane, oil and brine. The gas properties are obtained from the van der Waals equation and we take into account the absorption of gas by oil and brine, as a function of the in situ pore pressure and temperature. The dry-rock bulk and shear moduli can be obtained either by calibration from real data or by using rock-physics models based on the Hertz-Mindlin and Hashin-Shtrikman theories. Mesoscopic attenuation due to fluids effects is quantified by using White's model of patchy saturation, and the wet-rock velocities are calculated with Gassmann equations by using an effective fluid modulus to describe the velocities predicted by White's model. The simulations are performed with a poro-viscoelastic modeling code based on Biot's theory, where viscoelasticity is described by generalizing the solid/fluid coupling modulus to a relaxation function. Using the pseudo-spectral method, which allows general material variability, a complete and accurate characterization of the reservoir can be obtained. A simulation, that considers the Utsira sand of the North Sea, illustrates the methodology.

The CO 2 storage operation at Sleipner in the Norwegian North Sea provides an excellent demonstration of the application of time-lapse surface seismic methods to CO 2 plume monitoring under favourable conditions. Injection commenced at Sleipner in 1996 with CO 2 separated from natural gas being injected into the Utsira Sand, a major saline aquifer of late Cenozoic age. CO 2 injection is via a near-horizontal well, at a depth of about 1012 m bsl, some 200 m below the reservoir top, at a rate approaching 1 million tonnes (Mt) per year, with more than 11 Mt currently stored.A comprehensive time-lapse surface seismic programme has been carried out, with 3D surveys in 1994, 1999, 2001, 2002, 2004, 2006 and 2008. Key aims of the seismic monitoring are to track plume migration, demonstrate containment within the storage reservoir and provide quantitative information as a means to better understand detailed flow processes controlling development of the plume in the reservoir.The CO 2 plume is imaged as a number of bright sub-horizontal reflections within the reservoir, growing with time ( Figure 1). The reflections mostly comprise tuned wavelets arising from thin (mostly < 8 m thick) layers of CO 2 trapped beneath very thin intra-reservoir mudstones and the reservoir caprock. The plume is roughly 200 m high and elliptical in plan, with a major axis increasing to over 3000 m by 2008. As well as its prominent reflectivity, the plume also produces a large velocity pushdown caused by the seismic waves travelling more slowly through CO 2 -saturated rock than through the virgin aquifer. This paper summarises some of the quantitative methods that have been applied to the Sleipner seismic datasets.

A B S T R A C TWe estimate the quality factor (Q) from seismic reflections by using a tomographic inversion algorithm based on the frequency-shift method. The algorithm is verified with a synthetic case and is applied to offshore data, acquired at western Svalbard, to detect the presence of bottom-simulating reflectors (BSR) and gas hydrates. An array of 20 ocean-bottom seismographs has been used.The combined use of traveltime and attenuation tomography provides a 3D velocity-Q cube, which can be used to map the spatial distribution of the gas-hydrate concentration and free-gas saturation. In general, high P-wave velocity and quality factor indicate the presence of solid hydrates and low P-wave velocity and quality factor correspond to free-gas bearing sediments.The Q-values vary between 200 and 25, with higher values (150-200) above the BSR and lower values below the BSR (25-40). These results seem to confirm that hydrates cement the grains, and attenuation decreases with increasing hydrate concentration.

Summary Processing and interpretation of a grid of intermediate‐resolution multichannel seismic reflection profiles collected on the NE sector of the South Shetland continental margin, allowed us to map the lateral extent of a Bottom Simulating Reflector (BSR). The margin, an accretionary wedge located off the northern tip of the Antarctic Peninsula, consists of two distinct and superimposed tectonic regimes: an older regime is related to Mesozoic–Middle Cenozoic subduction‐related tectonism; a younger one is associated with a mainly extensional tectonic phase, and related to the Oligocene development of the western Scotia Sea. The occurrence of the BSR appears to be controlled by the geological structure of the margin. The BSR lacks continuity near basement structures, main geological discontinuities and faults. On the other hand, the amplitude and continuity of the BSR are not affected by the presence of folded structures and undeformed sedimentary layering. We found that the BSR is mostly confined to the NE sector of the South Shetland Margin, where propagation of faulting associated with the Shackleton Fracture Zone may have driven migration of natural gas towards the surface and created the conditions for a BSR to appear. The application of reflection tomography techniques allowed us to reconstruct the averaged seismic velocity field between the seafloor and BSR in order to map the depth of BSR. By averaging the observed velocity structure above and below the BSR, and applying a theoretical model of elastic wave propagation in porous media, we attempted as rigorous a quantitative assessment as possible of the natural gas present as gas hydrate above the BSR and as free gas between the BSR and the Base of Gas Reflector (BGR).