Composition of soil samples from injection location

CO2 leakage from subsurface storage sites is one of the main concerns connected with the CCS technology. As CO2 leakages into near surface formations appear to be very unlikely within pilot CCS projects, the aim of this work is to emulate a leakage by injecting CO2 into a near surface aquifer. The two main questions pursued by the injection test are (1) to investigate the impact of CO2 on the hydrogeochemistry of the groundwater as a base for groundwater risk assessment and (2) to develop and apply monitoring methods and monitoring concepts for detecting CO2 leakages in shallow aquifers. The presented injection test is planned within the second half of 2010, as a joint project of the University of Kiel (Germany), the Helmholtz-Centre for Environmental Research (Leipzig, Germany) and the Engineering Company GICON (Dresden, Germany). The test site has been investigated in detail using geophysical methods as well as direct-push soundings, groundwater well installation and soil and groundwater analyses. The present paper presents briefly the geological and hydrogeological conditions at the test site as well as the planned injection test design and monitoring concept.

Table 1. Mean geochemical values for Baseline (pre-injection) and Monitor-1 (post-injection) samples, and the percent change between the two weighted means

The Weyburn Oil Field, Saskatchewan is the site of a large (5000 tonnes/day of CO2) CO2-EOR injection project By EnCana Corporation. Pre- and post-injection samples (Baseline and Monitor-1, respectively) of produced fluids from approximately 45 vertical wells were taken and chemically analyzed to determine changes in the fluid chemistry and isotope composition between August 2000 and March 2001. After 6 months of CO2 injection, geochemical parameters including pH, [HCO3], [Ca], [Mg], and ?13CO2(g) point to areas in which injected CO2 dissolution and reservoir carbonate mineral dissolution have occurred. Pre-injection fluid compositions suggest that the reservoir brine in the injection area may be capable of storing as much as 100 million tonnes of dissolved CO2. Modeling of water-rock reactions show that clay minerals and feldspar, although volumetrically insignificant, may be capable of acting as pH buffers, allowing injected CO2 to be stored as bicarbonate in the formation water or as newly precipitated carbonate minerals, given favorable reaction kinetics.

Gas composition, concentration and stable isotope ratios (Table 2, 3, 4)

The deployment of CCS (carbon capture and storage) at industrial scale implies the development of effective monitoring tools. Noble gases are tracers usually proposed to track CO2. This methodology, combined with the geochemistry of carbon isotopes, has been tested on available analogues. At first, gases from natural analogues were sampled in the Colorado Plateau and in the French carbogaseous provinces, in both well-confined and leaking-sites. Second, we performed a 2-years tracing experience on an underground natural gas storage, sampling gas each month during injection and withdrawal periods. In natural analogues, the geochemical fingerprints are dependent on the containment criterion and on the geological context, giving tools to detect a leakage of deep-CO2 toward surface. This study also provides information on the origin of CO2, as well as residence time of fluids within the crust and clues on the physico-chemical processes occurring during the geological story. The study on the industrial analogue demonstrates the feasibility of using noble gases as tracers of CO2. Withdrawn gases follow geochemical trends coherent with mixing processes between injected gas end-members. Physico-chemical processes revealed by the tracing occur at transient state. These two complementary studies proved the interest of geochemical monitoring to survey the CO2 behaviour, and gave information on its use.

High resolution study of sediment core GeoB3606-1

Based on a high-resolution analysis of the diatom signal and biogenic bulk components at site GeoB3606-1 (25°S, off Namibia), we describe rapid palaeoceanographic changes in the Benguela Upwelling System (BUS) from early MIS 3 through to the early Holocene (55 000 to 7 000 14C yr BP). Coastal upwelling strongly varied at 25°S from MIS 3 through to MIS 2. The abrupt decrease in the accumulation rate of biogenic silica and diatoms from MIS 3 into MIS 2 records rapid oceanographic changes in the BUS off Namibia. During MIS 3, leakage of excess H4SiO4 acid from the Southern Ocean into low-latitude surface waters, as indicated by the occurrence of Antarctic diatoms, enhanced the production of spores of Chaetoceros at the expense of calcareous phytoplankton. Furthermore, shallower Antarctic Intermediate Water (AAIW) would have enriched the thermocline off Namibia with silicate transported from the Southern Ocean. The strong decrease of the siliceous signal throughout MIS 2 represents a decrease in the nutrient input to the BUS, even though the diatom assemblage is still dominated by spores of the upwelling-associated diatom genus Chaetoceros. Depletion of silicate in the thermocline from the onset of MIS 2 through to the early Holocene reflects the shutdown of AAIW injection from the Southern Ocean into the BUS, causing upwelled waters to become reduced in silicate, hence less favourable for diatom production. The deglaciation and early Holocene are characterised by the replacement of the upwelling-associated flora by a non-upwelling-related diatom community, reflecting weakened upwelling, retraction of the seaward extension of the chlorophyll filament off Lüderitz, and dominance of warmer waters.

Fig. S1. Loci of possible event locations based on differential ts - tp arrival times at the single functioning geophone

Geological storage of CO2 that has been captured at large, point source emitters represents a key potential method for reduction of anthropogenic greenhouse gas emissions. However, this technology will only be viable if it can be guaranteed that injected CO2 will remain trapped in the subsurface for thousands of years or more. A signi?cant issue for storage security is the geomechanical response of the reservoir. Concerns have been raised that geomechanical deformation induced by CO2 injection will create or reactivate fracture networks in the sealing caprocks, providing a pathway for CO2 leakage. In this paper, we examine three large-scale sites where CO2 is injected at rates of ab. 1 megatonne/y or more: Sleipner, Weyburn, and In Salah. We compare and contrast the observed geomechanical behavior of each site, with particular focus on the risks to storage security posed by geomechanical deformation. At Sleipner, the large, high-permeability storage aquifer has experienced little pore pressure increase over 15 y of injection, implying little possibility of geomechanical deformation. At Weyburn, 45 y of oil production has depleted pore pressures before increases associated with CO2 injection. The long history of the ?eld has led to complicated, sometimes nonintuitive geomechanical deformation. At In Salah, injection into the water leg of a gas reservoir has increased pore pressures, leading to uplift and substantial microseismic activity. The differences in the geomechanical responses of these sites emphasize the need for systematic geomechanical appraisal before injection in any potential storage site.

Macrofauna biodiversity from ECO2 water-formation experiment

The injection of gas into sub-seabed aquifers may lead to the displacement of hypoxic and hypersaline fluids (reservoir formation water) major environmental risk. To investigate this risk, the impact of formation water release on the macrofaunal community in a mesocosm experiment at Solbergstrand was conducted. 20 boxcores were exposed to 4 treatments (high salinity, hypoxic, mixed and tidal) during two weeks. The abundance of macrofauna was quantified for each treatment and richness, eveness and biodiversity indices calculated. The data are reported in this dataset.