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Mathias S.A.,Durham University | Gluyas J.G.,Durham University | Gonzalez Martinez De Miguel G.J.,Durham University | Gonzalez Martinez De Miguel G.J.,ERC Equipoise Ltd | Hosseini S.A.,University of Texas at Austin
Water Resources Research | Year: 2011

This work extends an existing analytical solution for pressure buildup because of CO 2 injection in brine aquifers by incorporating effects associated with partial miscibility. These include evaporation of water into the CO 2 rich phase and dissolution of CO 2 into brine and salt precipitation. The resulting equations are closed-form, including the locations of the associated leading and trailing shock fronts. Derivation of the analytical solution involves making a number of simplifying assumptions including: vertical pressure equilibrium, negligible capillary pressure, and constant fluid properties. The analytical solution is compared to results from TOUGH2 and found to accurately approximate the extent of the dry-out zone around the well, the resulting permeability enhancement due to residual brine evaporation, the volumetric saturation of precipitated salt, and the vertically averaged pressure distribution in both space and time for the four scenarios studied. While brine evaporation is found to have a considerable effect on pressure, the effect of CO 2 dissolution is found to be small. The resulting equations remain simple to evaluate in spreadsheet software and represent a significant improvement on current methods for estimating pressure-limited CO 2 storage capacity. Copyright 2011 by the American Geophysical Union.

Mathias S.A.,Durham University | de Miguel G.J.G.M.,Durham University | de Miguel G.J.G.M.,ERC Equipoise Ltd | Thatcher K.E.,Durham University | Zimmerman R.W.,Imperial College London
Transport in Porous Media | Year: 2011

CO2 injected into porous formations is accommodated by reduction in the volume of the formation fluid and enlargement of the pore space, through compression of the formation fluids and rock material, respectively. A critical issue is how the resulting pressure buildup will affect the mechanical integrity of the host formation and caprock. Building on an existing approximate solution for formations of infinite radial extent, this article presents an explicit approximate solution for estimating pressure buildup due to injection of CO2 into closed brine aquifers of finite radial extent. The analysis is also applicable for injection into a formation containing multiple wells, in which each well acts as if it were in a quasi-circular closed region. The approximate solution is validated by comparison with vertically averaged results obtained using TOUGH2 with ECO2N (where many of the simplifying assumptions are relaxed), and is shown to be very accurate over wide ranges of the relevant parameter space. The resulting equations for the pressure distribution are explicit, and can be easily implemented within spreadsheet software for estimating CO2 injection capacity. © 2011 Springer Science+Business Media B.V.

Mathias S.A.,Durham University | Gluyas J.G.,Durham University | Gonzalez Martinez de Miguel G.J.,Durham University | Gonzalez Martinez de Miguel G.J.,ERC Equipoise Ltd | And 2 more authors.
International Journal of Greenhouse Gas Control | Year: 2013

Performance assessment of possible CO2 storage schemes is often investigated through numerical simulation of the CO2 injection process. An important criterion of interest is the maximum sustainable injection rate. Relevant numerical models generally employ a multi-phase extension to Darcy's law, requiring data concerning the evolution of relative permeability for CO2 and brine mixtures with increasing CO2 saturation. Relative permeability data is acutely scarce for many geographical regions of concern and often cited as a major source of uncertainty. However, such data is expensive and time consuming to acquire. With a view to improving our understanding concerning the significance of relative permeability uncertainty on injectivity, this article presents a sensitivity analysis of sustainable CO2 injection rate with respect to permeability, porosity and relative permeability. Based on available relative permeability data obtained from 25 sandstone and carbonate cores discussed in the literature, injectivity uncertainty associated with relative permeability is found to be as high as ±57% for open aquifers and low permeability closed aquifers (<50mD). However, for high permeability closed aquifers (>100mD), aquifer compressibility plays a more important role and the uncertainty due to relative permeability is found to reduce to ±6%. © 2012 Elsevier Ltd.

Lohr T.,ERC Equipoise Ltd | Underhill J.R.,Heriot - Watt University
Petroleum Geoscience | Year: 2015

The results of well-constrained seismic interpretation and new mapping of three-dimensional (3D) seismic data volumes demonstrates that the North Falkland Basin consists of two superimposed failed rift basins: a Late Jurassic NW–SEstriking Southern Rift Basin (SRB); and an Early Cretaceous north–south-striking Northern Rift Basin (NRB). The SRB is best developed in coastal waters of the Falkland Islands, where it comprises a series of extensional sub-basins that are transected by faults belonging to the more substantive NRB. Regional interpretation demonstrates that the NRB consists of a southward-tapering, asymmetric extensional basin containing a thick (in excess of 10 km) sequence of sediments. Its syn-rift subsidence history was controlled by a major west-dipping normal fault array comprising several fault segment precursors, which, together with corresponding antithetic faults, effectively subdivides the hanging wall into a series of subbasins throughout its length. The NRB initially developed in a fluvial and later lacustrine environment before becoming predominantly marine in the Tertiary. A prograding delta system filled the basin from the north during the early post-rift phase. Contemporaneously, sediment was shed off the segmented basin-bounding fault via long-established feeder drainage systems through breached relay ramps into the depocentre. The resultant sediment dispersal led to deposition of numerous lacustrine turbidites that created the Sea Lion fans and its affiliates, the location of which mimics, and is thus interpreted to have been controlled by, the underlying syn-rift sub-basins. Post-rift subsidence was punctuated by an important, but short-lived, phase of basin inversion during the Aptian that created a large, broad and gentle north–south-striking anticline that runs along the central basin axis. Whilst the episode of basin inversion arrested subsidence, it did not inhibit petroleum prospectivity. The syn-rift lacustrine source intervals did subsequently pass through the critical moment in the Cretaceous leading to hydrocarbon maturation and the migration of waxy oil, a process that continues to the present day. © 2015 The Author(s).

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