Using oxygen isotopes to quantitatively assess residual CO₂ saturation during the CO2CRC Otway Stage 2B Extension residual saturation test

Highlights

• Oxygen and hydrogen isotope data from water and gas samples from Otway 2B Extension.

• Oxygen isotope ratio of reservoir water changes due to contact with free-phase CO₂.

• Change in oxygen isotope ratio of reservoir water occurs within a few days.

• Early oxygen isotope-based saturation estimate is similar to a neutron log measure.

Abstract

Residual CO₂ trapping is a key mechanism of secure CO₂ storage, an essential component of the Carbon Capture and Storage technology. Estimating the amount of CO₂ that will be residually trapped in a saline aquifer formation remains a significant challenge. Here, we present the first oxygen isotope ratio (δ¹⁸O) measurements from a single-well experiment, the CO2CRC Otway 2B Extension, used to estimate levels of residual trapping of CO₂. Following the initiation of the drive to residual saturation in the reservoir, reservoir water δ¹⁸O decreased, as predicted from the baseline isotope ratios of water and CO₂, over a time span of only a few days. The isotope shift in the near-wellbore reservoir water is the result of isotope equilibrium exchange between residual CO₂ and water. For the region further away from the well, the isotopic shift in the reservoir water can also be explained by isotopic exchange with mobile CO₂ from ahead of the region driven to residual, or continuous isotopic exchange between water and residual CO₂ during its back-production, complicating the interpretation of the change in reservoir water δ¹⁸O in terms of residual saturation. A small isotopic distinction of the baseline water and CO₂ δ¹⁸O, together with issues encountered during the field experiment procedure, further prevents the estimation of residual CO₂ saturation levels from oxygen isotope changes without significant uncertainty. The similarity of oxygen isotope-based near-wellbore saturation levels and independent estimates based on pulsed neutron logging indicates the potential of using oxygen isotope as an effective inherent tracer for determining residual saturation on a field scale within a few days.

Introduction

Geological storage of CO₂ in rock formations, as part of Carbon Capture and Storage (CCS), is a promising means of directly lowering CO₂ emissions from fossil fuel combustion (Metz et al., 2005). CO₂ can be stored in the subsurface in three different ways over short timescales: (1) structural trapping, where gaseous or liquid CO₂ is trapped beneath an impermeable cap rock, (2) residual trapping, the immobilisation of CO₂ through trapping within individual and dead end spaces between rock grains, and (3) solubility trapping, where CO₂ is dissolved into the reservoir water that fills the pores between rock grains. Mineral trapping of CO₂ as a result of chemical reactions of the injected CO₂ with the host rock, forming new carbonate minerals within the pores, is a longer term storage mechanism, likely to play a role in siliciclastic formations several hundreds of years after initiation of CO₂ injection (e.g., Audigane et al., 2007, Sterpenich et al., 2009, Xu et al., 2003, Xu et al., 2004, Zhang et al., 2009).

For accurately modelling the long-term fate of CO₂ in a commercial-scale CCS project, it is of value to develop an efficient plan to quantitatively assess the amount of structural, residual and solubility trapping at the reservoir scale through a short-term test undertaken in the vicinity of an injection well prior to large-scale injection. Such a test would reduce risk and uncertainty in estimating the storage capacity of a formation and would provide a commercial operator with greater reassurance of the viability of their proposed storage site. This is particularly true for residual trapping of CO₂ which can play a major role for CO₂ plume migration, immobilisation, storage security and reservoir management (Doughty and Pruess, 2004, Ennis-King and Paterson, 2002, Juanes et al., 2006, Krevor et al., 2015, Qi et al., 2009). Despite the important role of residual trapping of CO₂ in commercial-scale CCS projects, there is a current lack of cost-effective and reliable methodologies to estimate the degree of residual trapping on the reservoir scale (Mayer et al., 2015).

Stable isotopes may be highly suitable for assessing the movement and fate of injected CO₂ in the formation since they fingerprint the injected CO₂ rather than being a co-injected compound like perfluorocarbon tracers, Kr or Xe (Mayer et al., 2013). There are few sources of available oxygen other than the reservoir water within CO₂ storage reservoirs (Johnson et al., 2011, Mayer et al., 2015). Any other reservoir oxygen that is available for water-rock reactions is typically in isotopic equilibrium with the reservoir fluid due to relatively fast reaction kinetics in the water-carbonate system (e.g., Mills and Urey, 1940, Vogel et al., 1970). During CO₂ injection, a new major source of oxygen is added to the system in the form of supercritical CO₂. Isotopic equilibrium exchange proceeds rapidly between oxygen in CO₂ and oxygen in water of various salinities (Kharaka et al., 2006, Lécuyer et al., 2009). In most natural environments the amount of oxygen in CO₂ is negligible compared to the amount of oxygen in water. Consequently, the oxygen isotope ratio (δ¹⁸O) of water remains essentially constant and δ¹⁸O of CO₂ approaches that of the water plus the appropriate isotopic enrichment factor between water and CO₂ (ε ≈ 10³ ln ${\alpha }_{{\text{CO}}_2{\text{-H}}_2\text{O}}$), depending on the reservoir temperature (Bottinga, 1968). At CO₂ injection sites, due to the large quantities of CO₂ injected, CO₂ becomes a major oxygen source, and both CO₂ and water will change their δ¹⁸O due to isotopic equilibrium exchange reactions if the injected CO₂ is isotopically distinct with respect to the baseline reservoir water (Barth et al., 2015, Johnson and Mayer, 2011, Johnson et al., 2011, Kharaka et al., 2006, Mayer et al., 2015). This has also been observed in natural settings characterised by vast amounts of free-phase CO₂ in contact with water produced from CO₂-rich springs, for example in south east Spain (Céron and Pulido-Bosch, 1999, Céron et al., 1998) or in Bongwana, South Africa (Harris et al., 1997). The change in reservoir water δ¹⁸O due to isotopic exchange with CO₂ under conditions typical for CO₂ injection sites can be related to the fraction of oxygen in the system sourced from CO₂ (Barth et al., 2015, Johnson and Mayer, 2011, Johnson et al., 2011, Kharaka et al., 2006), and the fraction of oxygen sourced from CO₂ can be successfully used to assess volumetric saturation of free-phase and dissolved CO₂ in the reservoir (Johnson et al., 2011, Li and Pang, 2015).

CO2CRC Limited (CO2CRC) developed and has operated the CO2CRC Otway Facility in the Otway Basin near Nirranda South, Victoria, Australia, since 2004 (Sharma et al., 2007). The facility allows for trial injection in multiple storage types, including a saline formation that currently uses a single-well configuration. This configuration is ideal for the development of an effective reservoir characterisation test prior to commercial-scale CO₂ injection (Paterson et al., 2011). In 2011, the first single-well injection test (using the CRC-2 injection well) was undertaken at the Otway facility using 150 t of injected CO₂ to quantify reservoir-scale residual trapping of CO₂ in a saline formation in the absence of an apparent structural closure (CO2CRC Otway Stage 2B – henceforth referred to as Otway 2B; Paterson et al., 2011, Paterson et al., 2013, Paterson et al., 2014). The target reservoir for the experiment was within the Paaratte Formation, a saline formation at 1075–1472 m TVDSS (true vertical depth below mean sea level), with the target interval for the Otway 2B experiment at 1392–1399 m TVDSS. Deep saline formations are the most likely candidates for geological CO₂ storage because of their huge potential capacity and their locations close to major CO₂ sources (Holloway, 2001). The Paaratte Formation, while only used for research purposes, is a saline formation analogous to those proposed for commercial-scale CO₂ injection and storage. Two of the original measurements of residual CO₂ saturation were acquired using noble gas (Xe and Kr) tracer injection and recovery data (LaForce et al., 2014), and pulsed neutron logging of the CRC-2 injection well (Schlumberger Residual Saturation Tool; Dance and Paterson, 2016, Paterson et al., 2013, Paterson et al., 2014). The second part of the recent COCRC Otway Stage 2B Extension project (henceforth referred to as Otway 2B Extension) was a smaller-scale repeat of these two residual saturation tests using improved methodologies.

Here we present oxygen (δ¹⁸O) and hydrogen isotope (δ²H) data from produced water and formation water (U-tube) samples, and oxygen isotope data from CO₂ samples from the Otway 2B Extension. For the first time we estimate levels of residual trapping of CO₂ based on oxygen isotope data from a single-well test. We compare our results with measures from independent techniques to estimate residual saturation.