InSAR monitoring of ground deformation due to CO2 injection at an enhanced oil recovery site, West Texas
Introduction
An important aspect of large-scale carbon capture, utilization and storage (CCUS) is the ability to assess the fate of injected CO2 and test for leakage. These so-called monitoring, verification and accounting (MVA) activities typically involve active seismic surveys and down-hole techniques for precise tracking of CO2 plume migration, both of which can be expensive. Since the economic viability of CCUS is impacted by the cost of MVA activities, development of lower cost approaches is desirable.
Injection of CO2 or other fluid into a reservoir at depth increases fluid pressure in the reservoir, causing deformation in the overlying strata and inducing surface deformation. If the pressure change is large enough, the surface deformation may be measurable. In principle, the measured surface deformation can be inverted to estimate pressure changes at depth and track the CO2 plume (e.g., Vasco et al., 2008, Vasco et al., 2010, Rinaldi and Rutqvist, 2013, White et al., 2014, Karegar et al., 2015). Over long periods (decades or centuries), chemical reactions that result in formation of mineral phases will cause pressure and volume reduction and subsidence, and could not be distinguished from migration or leakage with this technique alone. On the other hand, surface deformation can be measured at relatively low cost, the interpretation is relatively straightforward, and the technique gives useful information in the critical few years immediately following injection.
Enhanced oil recovery (EOR) refers to techniques for increasing the amount of oil extracted at depleted or high viscosity oil fields. CO2-enhanced oil recovery (CO2-EOR) has been used by the oil and gas industry for over 40 years (Orr and Taber, 1984), but only recently has its potential as a promising method of carbon sequestration been realized and investigated (Bryant, 2007). Considering the potential of CO2-EOR for implementation of large-scale carbon emission reduction (Metz et al., 2005), it is important to test surface deformation MVA techniques in a CO2-EOR field.
Interferometric synthetic aperture radar (InSAR) technique has been successfully used to monitor surface deformation associated with CO2 injection at the In Salah field in Algeria (Mathieson et al., 2009, Morris et al., 2011, Shi et al., 2012, Verdon et al., 2013). In this paper, we use InSAR to study surface deformation associated with a CO2-EOR project in West Texas. We use an analytical model and historical injection and production data to estimate CO2 plume extent and reservoir pressure change constrained by surface deformation observations. The study reveals that ground uplift between January 2007 and March 2011 is mainly caused by CO2 injection. The maximum pressure change due to net injection and production of CO2, water, oil and hydrocarbon gas is up to 10 MPa.
Section snippets
Study area description
The CO2-EOR field is located in Scurry County, West Texas (Fig. 1). The reservoir is the southeastern segment of the Horseshoe Atoll play within the Midland basin, one of the largest subsurface limestone reef mounds in the world (Galloway et al., 1983). It is a chain of oil fields with the major one being the Kelly-Snyder field. The producing zones are Pennsylvanian-aged Cisco and Canyon formations, and are comparable to a large class of potential brine storage reservoirs. Average depth of the
Observed ground deformation
Advanced Land Observing Satellite (ALOS) image data from the Japan Aerospace Exploration Agency (JAXA) are used to monitor surface displacement above the CO2-EOR field. The satellite repeat cycle is 46 days. Thirteen images were acquired from January 08, 2007 to March 06, 2011 on ascending path 184, frame 640, from which 53 interferograms were generated. The small Baseline Subset technique (Berardino et al., 2002) is applied to generate displacement time series. By using L-band SAR data, the
Analytical solution for ground displacement
An analytical solution for ground displacement associated with injection or withdrawal of fluid at depth may be derived in two steps: (a) the approximate solution for reservoir pressure change due to fluid injection (Mathias et al., 2009a, Mathias et al., 2009b) and production (Theis, 1935); and (b) the solution for surface deformation due to pressure change in depth estimated in an elastic half space (Xu et al., 2012).
First, we calculate the reservoir pressure change field due to fluid
Simulation results
Fig. 7 shows the simulated changes in reservoir pressure due to different fluid injection/extraction rates for three assumed values of rock formation porosity and permeability. The local maxima and minima patterns are similar for the different values of porosity and permeability. Calculated pressure change in the reservoir decreases for higher values of porosity and permeability. Net CO2 injection/production significantly affects reservoir pressure. Since volumes of water injection and
Discussion
We modeled a reservoir as a simplified body with uniform properties. In fact, it almost certainly has significant spatial variation in porosity, permeability and elastic properties. We have also ignored inter-well pressure interaction when simulating reservoir pressure change. Despite these simplifications, we are able to obtain good fits to the surface deformation data and obtain useful information on the reservoir. This reflects the fact that the free surface is 2000 m above the reservoir,
Conclusions
We evaluated injection and production data for CO2, water, oil and hydrocarbon gas at individual wells in a CO2-EOR field between 2004 and 2011. Approximately 50 Mt of CO2 were sequestered between 2004 and 2011, equal to the total sequestered CO2 between 1972 and 2003. InSAR data observe up to 10 cm line of sight displacement between January 2007 and March 2011 in this field. Water injection alone cannot explain surface uplift between January 2007 and March 2011 because net injected water (∼1 Mt)
Acknowledgements
We thank the field operator for providing historical injection and production data. We also thank the Railroad Commission of Texas for providing information on the location and depth of individual wells in our study area. This research was supported by DOE grant DE-FE0001580. We thank Karen Kluger for support and advice throughout our project and two anonymous reviewers for thoughtful comments.
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