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Durham, United Kingdom

Noy D.J.,British Geological Survey | Holloway S.,British Geological Survey | Chadwick R.A.,British Geological Survey | Williams J.D.O.,British Geological Survey | And 2 more authors.
International Journal of Greenhouse Gas Control | Year: 2012

The Bunter Sandstone in the UK sector of the Southern North Sea Basin is a reservoir rock that is typically 200m or more thick and has variable but commonly fair to good porosity and permeability. East of the Dowsing Fault Zone it is folded into a number of large periclines as a result of post-depositional halokinesis in the underlying Zechstein salt. It is sealed by the overlying Haisborough Group and younger fine-grained strata and is underlain by the Bunter Shale and Zechstein Group. As such it appears to be an attractive target for industrial-scale CO 2 storage. However, the very large masses of CO 2 that would have to be injected and stored if CCS is to be an effective greenhouse gas mitigation option are likely to cause (a) significant pore fluid pressure rise and (b) displacement of formation brines from the reservoir. A series of reservoir flow simulations of large-scale CO 2 injection was carried out to investigate these effects. A simple, 3D geocellular model of the Bunter Sandstone in the NE part of the UK sector of the Southern North Sea was constructed in the TOUGH2 reservoir simulator in which porosity and both horizontal and vertical permeability could be varied. The injection of CO 2 at various rates into the model through a variable number of wells for 50 years was simulated and the model was then run forward for up to 3000 years to see how pore fluid pressures, brine displacement and CO 2 distribution evolved. The simulations suggest that provided there is good connectivity within the reservoir, and 12 optimally distributed injection locations are used, 15-20 million tonnes of CO 2 per year could be stored in the modelled area without the reservoir pore pressure exceeding 75% of the lithostatic pressure anywhere within the model. However, significant fluxes of the native pore fluid (saline brine) to the sea occurred at a point where the Bunter Sandstone crops out at the seabed. This suggests that the potential environmental impacts of brine displacement to the sea floor should be investigated. The injected CO 2 fills only up to about 1% of the total pore space within the model. This indicates that pore fluid pressure rise may be a greater constraint on CO 2 storage capacity than physical containment within the storage reservoir. © 2012 Natural Environment Research Council. Source

Robertson J.,Durham University | Swarbrick R.E.,GeoPressure Technology Ltd | Goulty N.R.,Durham University
73rd European Association of Geoscientists and Engineers Conference and Exhibition 2011: Unconventional Resources and the Role of Technology. Incorporating SPE EUROPEC 2011 | Year: 2011

Recent discoveries of light oil in Palaeogene reservoirs on the western margin of the Central North Sea have brought a new phase of exploration to an area which was previously considered unprospective, because of the likelihood that any accumulated oil would be biodegraded. Such discoveries highlight the need to better understand migration pathways within the Palaeogene strata of the Central North Sea. In this study, pressure data from 333 wells situated in the Central North Sea have been used to map overpressure variations in all of the major Palaeogene reservoirs, comprising the Palaeocene Maureen Formation Sands, Mey Sandstone Member, Forties Sandstone Member and the Upper Sele Sands, and the Eocene Tay and Caran Sandstone Members. The overpressure distributions confirm the notion that the Palaeocene Forties and Mey reservoirs are laterally draining towards the NW, where these sands are known to thicken and subcrop beneath the Moray Firth. In addition, there is evidence to suggest that the fluids within the Tay Sandstone are laterally draining westwards into the shelfal sands of the Mousa Formation. Over a substantial area of Quad 21, the Forties and Tay sandstones share overpressure values, suggesting good connectivity between the two units. Source

O'Connor S.,GeoPressure Technology Ltd | Swarbrick R.,GeoPressure Technology Ltd | Lahann R.,Indiana University Bloomington
Geofluids | Year: 2011

Abnormal pressure, either low or high, is commonly found in many basins around the world. A clear understanding of these pressure regimes is needed if wells are to be drilled safely. One of the prerequisites for this planning is prediction of pore fluid pressure, in both reservoirs and also in shales and other low-permeability lithologies. To this end, recent advances, captured in this thematic set, have seen the development of geologically derived pressure models, underpinned by an understanding of the multiple mechanisms that cause abnormal pressures. These understandings lead to more accurate pore fluid pressure interpretation in more complex lithological regimes such as carbonate/clastic systems and salt-dominated systems that often contain highly overpressured intra-salt reservoirs. Further, these models are now being used to drive new exploration plays by improving velocity predictions to improve sub-salt pore pressure predictions and identifying hydrodynamic aquifers that provide lateral migration paths for fluids. © 2011 Blackwell Publishing Ltd. Source

O'Connor S.,GeoPressure Technology Ltd | Rasmussen H.,Centrica | Swarbrick R.,GeoPressure Technology Ltd | Wood J.,Centrica
Geofluids | Year: 2011

The Ula Trend lies on the eastern margin of the Central Trough in the Norwegian North Sea and contains the Ula, Gyda and Tambar oilfields. In this Trend, the development of late Jurassic shallow-marine Ula reservoir sands is complex, because of the deposition of these sands in salt-dissolution features, separated by inverted Triassic pods. In this paper, attribute mapping (derived from newly re-processed 3D seismic surveys) has enabled a predictive model to be established for the presence of the Jurassic sands, corroborated by well data, in salt collapse and sand fairway grabens. This model suggests that the Ula sand is laterally continuous over large areas of the Trend. Pressure data from the Chalk in Ula Field wells, and from Jurassic reservoirs on the Cod Terrace, suggest that these continuous sands of the Ula Trend have significantly less pressure than would be expected for their depth of burial. Pressure escape of this nature is often associated with hydrodynamic aquifers, in which overpressure gradients are demonstrable. In this paper, we have used both virgin and postproduction water pressure data from the vicinity of the Ula Field (as well as a new sedimentological model for the reservoir) to test the applicability of a hydrodynamic aquifer versus other models to explain differing oil-water contacts. We establish that the hydrodynamic and structural spill-points are coincident on the SE of the Ula Field, and that, therefore, hydrocarbons have potentially spilt out of the Ula structure SE towards a series of salt-flank traps, generating prospectivity up-dip. The salt features themselves are considered to act as pressure-release valves or vertical 'leak-points', as Ula sands on their flanks are sufficiently shallow, because of salt movement that overpressures exceed the fracture pressure of the rock, therefore allowing the Ula sands to de-pressurise over geological time, setting up this hydrodynamic flow. © 2011 Blackwell Publishing Ltd. Source

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