Time-lapse walkaway vertical seismic profile monitoring for CO [ subscript 2 ] injection at the SACROC enhanced oil recovery field : A case study

Geologic carbon storage involves large-scale injections of carbon dioxide into underground geologic formations. Changes in reservoir properties resulting from CO2 injection and migration can be characterized using monitoring methods with timelapse seismic data. To achieve economical monitoring, vertical seismic profile (VSP) data are often acquired to survey the local injection area. We investigated the capability of walkaway VSP monitoring for CO2 injection into an enhanced oil recovery field at SACROC, West Texas. VSP data sets were acquired in 2008 and 2009, and CO2 injection took place after the first data acquisition. Because the receivers were located above the injection zone, only reflection data contain the information from the reservoir. Qualitative comparison between reverse-time migration images at different times revealed vertical shifts of the reflectors’ center, indicating the presence of velocity changes. We examined two methods to quantify the changes in velocity: standard full-waveform inversion (FWI) and image-domain wavefield tomography (IDWT). FWI directly inverts seismic waveforms for velocity models. IDWT inverts for the time-lapse velocity changes by matching the baseline and time-lapse migration images. We found that, for the constrained geometry of VSP surveys, the IDWT result was significantly more consistent with a localized change in velocity as expected from a few months of CO2 injection. A synthetic example was used to verify the result from the field data. By contrast, FWI failed to provide quantitative information about the volumetric velocity changes because of the survey geometry and data frequency content. INTRODUCTION Public acceptance of geologic carbon storage as an effective and environmentally friendly solution to the mitigation of green house gas emission is a major prerequisite for the method to be widely implemented on the scale necessary to reduce the atmospheric CO2 concentration. The injected CO2 needs to be monitored over time to demonstrate that the fluid is contained within the targeted formation. It is also crucial to detect fluid migration in the subsurface and potential leakage to ensure safe and reliable storage (Bickle et al., 2007). CO2 is usually injected into reservoirs such as saline aquifers and depleted oil and gas fields, which are predominately water-saturated formations (Benson and Cole, 2008). The displacement of water by CO2 tends to reduce the bulk modulus and density of the rock-pore fluid system (Purcell et al., 2010). These properties determine wave speed changes that can be observed using seismic methods. Time-lapse seismic monitoring is widely used in reservoir management in the oil industry to obtain information about reservoir changes caused by fluid injection and subsequent production of fluids from heterogeneous reservoirs. It helps identify bypassed oil to be targeted for infill drilling, and it extends the economic life of a field (Lumley, 2001). It is also capable of monitoring the progress of fluid fronts providing information for injection optimization in enhanced oil recovery (EOR) and long-term CO2 sequestration. Manuscript received by the Editor 21 July 2013; revised manuscript received 12 November 2013; published online 17 February 2014. Massachusetts Institute of Technology, Earth Resources Lab, Cambridge, Massachusetts, USA and Los Alamos National Laboratory, Geophysics Group, Los Alamos, New Mexico, USA. E-mail: diyang@mit.edu. Massachusetts Institute of Technology, Earth Resources Lab, Cambridge, Massachusetts, USA. E-mail: fehler@mit.edu; amalcolm@mit.edu. Los Alamos National Laboratory, Geophysics Group, Los Alamos, New Mexico, USA. E-mail: ljh@lanl.gov. © 2014 Society of Exploration Geophysicists. All rights reserved. B51 GEOPHYSICS, VOL. 79, NO. 2 (MARCH-APRIL 2014); P. B51–B61, 16 FIGS., 1 TABLE. 10.1190/GEO2013-0274.1 D ow nl oa de d 10 /3 0/ 15 to 1 8. 51 . 1 . 3 . R ed is tr ib ut io n su bj ec t t o SE G li ce ns e or c op yr ig ht ; s ee T er m s of U se a t h ttp :// lib ra ry . s eg . o rg / Generally, one baseline survey and subsequent monitoring surveys are acquired over time. Qualitative analysis of time-lapse seismic data gives information about the temporal reservoir changes with amplitude maps and time shifts at certain horizons. Impedance contrasts and seismic response changes such as amplitude changes and tuning effects have been used to characterize CO2 accumulations in thin layers, and velocity pushdown effects that are caused by slower propagation of seismic waves through the CO2 saturated area have been identified (Arts et al., 2004a). Quantitative methods have also been proposed to directly deliver reservoir property changes such as pore pressure and fluid saturation by linking the rock-physics modeling, reservoir simulation, and 4D seismic response simulation (Landa and Kumar, 2011; Tolstukhin et al., 2012). However, these methods are conducted with poststack data or even 1D wave propagation, which focus on a local region and lose general information during the stacking process. For example, the time-lapse changes illuminated by the seismic waves from a certain angle could be indistinct in the stacked data. The amplitude changes are also not well preserved after stacking without an updated velocity model. Lumley (2010) proposes a high-resolution quantitative method to estimate the volume of CO2 underground by combining 4D seismic, electromagnetic, gravity, and inSAR satellite data; however, time-lapse seismic is used to provide qualitative information in this process. Full-waveform inversion (FWI) has the potential to estimate subsurface density and elasticity parameters quantitatively (Tarantola, 1984; Virieux and Operto, 2009), and it is becoming more feasible with increasing computing power. However, FWI often requires large-offset surveys and low-frequency data to resolve low wavenumber velocities. Large monitoring networks on land or on the seafloor have been successfully deployed for CO2 monitoring (Aoki et al., 2013; Bakulin et al., 2013). For small pilot carbon sequestration projects, economic considerations mean that limited acquisition is generally used to monitor CO2 injection. Vertical seismic profile (VSP) data have been acquired in a few carbon-sequestration demonstration projects (Daley et al., 2008). The vertical resolution of VSP data is typically higher than that of surface seismic data because VSP data contain higher frequencies than surface seismic data. Unfortunately, VSP survey geometry reduces the ability of FWI to resolve volumetric velocity changes. In this geometry, FWI tends to produce a reflectivity model like that obtained using least-squares migration. Between baseline and time-lapse surveys, amplitude changes can be transformed into reflectivity differences between images. Kinematic information is indicated by changes in the apparent depths of reflectors instead of direct measures of velocity changes. If a constraint that forces the locations of reflectors can be used in FWI, the velocity-depth bias would be removed. However, we did not find an efficient way to implement such constraints. As an alternative to FWI, we apply an image domain wavefield tomography (IDWT) method (Yang et al., 2013) to time-lapse VSP data. Based on the assumption that the geology has not changed dramatically over time, both the baseline and time-lapse seismic data should be able to image the same area in the subsurface. If the correct velocity models are provided for both data sets, the reflectors should be at the same location assuming that reservoir compaction is negligible compared to the seismic wavelength. In an inverse problem setting, given a baseline velocity model, the time-lapse velocity anomaly can be resolved by matching the reflector locations in time-lapse images with those in the baseline image. The amplitude differences between images, which could be caused by reflectivity changes, are not sensitive to the smooth (low-wavenumber) velocity perturbations in the inversion. The goal of this paper is to investigate the practical capability of VSP reflection data for monitoring CO2 injection. We first introduce the theory of the imaging and inversion methods that we apply to the time-lapse VSP data, including reverse-time migration (RTM), FWI, and IDWT. In the following sections, we describe the geologic background of the SACROC EOR site, the injection history, and the seismic data acquisition and processing. Images and models obtained from different methods are compared to demonstrate how they provide different types of information about changes in the reservoir. Preliminary interpretation is given about the mechanism of reservoir response to CO2 injection and the CO2 fluid migration at the SACROC EOR field. METHODOLOGY In this section, we briefly introduce the methods used in this study: RTM, FWI, and IDWT. RTM An RTM algorithm consists of three steps: (1) forward propagation of the source wavefield, (2) backward propagation of the receiver wavefield, and (3) application of the imaging condition. Wavefield extrapolation is conducted by solving the wave equation: 1 c2ð~ xÞ ∂ ∂t uðt; ~ xÞ − ∇2uðt; ~ xÞ 1⁄4 Sðt; ~ xÞ; (1) where uðt; ~ xÞ is the wavefield at a spatial location ~ x and time t, cð~ xÞ is the P-wave velocity in the medium, and Sðt; ~ xÞ is the source function. The image is constructed by the zero-lag crosscorrelation of the source wavefield usðt; ~ xÞ and receiver wavefield urðt; ~ xÞ at the image point as follows: