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The CO2CRC Otway Stage 3 project is developing low-impact methods for near-continuous monitoring of storage sites. This paper reports on the design, drilling, instrumenting, and early results from an array of an injector and five monitoring wells, spread over a km2. Highlights include the deployment and use of distributed acoustic sensors on casing, and baseline injections and interpretation of pressure tomography.

[enter Abstract Body]The CSIRO In-Situ Laboratory has been a world first injection of CO2 into a large faulted zone at depth. A total of 38 tonnes of CO2 was injected into the F10 fault zone at approximately 330 m depth and the process monitored in detail. The site uses a well, Harvey-2, in SW Western Australia (the South West Hub CCS Project area). The top 400 m section of Harvey-2 was available for injection and instrumentation. An observation well, ISL OB-1 (400 m depth) was drilled 7 m to the north east of Harvey-2. ISL OB-1 well was cased with fibreglass to provide greater monitoring options. The CSIRO In-Situ Laboratory was designed to integrate existing facilities and infrastructure from the South West Hub CCS Project managed by the West Australian Department of Mines, Industry Regulation and Safety. While new equipment was deployed for this specific project, the site facilities were complemented by a range of mobile deployable equipment from the National Geosequestration Laboratory (NGL). The geology of the area investigated poses interesting challenges: a large fault (F10) is estimated to have up to 1000 m throw overall, the presence of packages of paleosols rather than a contiguous mudstone seal, and a 1500 m vertical thickness of Triassic sandstone as the potential commercial storage interval. This unique site provides abundant opportunities for testing more challenging geological environments for carbon storage than at other sites. While details of this first project are described elsewhere, lessons were learned during the development and execution of the project. A rigorous risk register was developed to manage project risk, but not all events encountered were foreseen. This paper describes some of the challenges encountered and the team’s response. Relocation of the project site due to changes in landholder ownership) and other sensitivities resulted in the need for rapid replanning of activities at short notice resulting in the development of the site at Harvey-2. The relocation allowed other research questions to be addressed through new activities, such as the ability to consider a shallow/controlled release experiment in an extensive fault zone, but this replanning did cause some timing stress. The first test at the In-Situ Laboratory was reconfigured to address some of those knowledge gaps that shallow/controlled release experiments had yet to address. Novel approaches to drilling and completing the monitoring well also threw up unanticipated difficulties. Loss of containment from the wellbore also posed significant challenges, and the team’s response to this unintended release of gas and water from the monitoring well at the conclusion of the field experiment will be discussed. Other challenges that we encountered, their impacts, and our response are also catalogued here (Table 1 and below) to enable broad knowledge exchange.

The CSIRO In-Situ Laboratory Project (ISL) is located in Western Australia and has two main objectives related to monitoring leaks from a CO2 storage complex by controlled-release experiments: 1) improving the monitorability of gaseous CO2 accumulations at intermediate depth, and 2) assessing the impact of faults on CO2 migration. A first test at the In-situ Lab has evaluated the ability to monitor and detect unwanted leakage of CO2 from a storage complex in a major fault zone. The ISL consists of three instrumented wells up to 400 m deep: 1) Harvey-2 used primarily for gaseous CO2 injection, 2) ISL OB-1, a fibreglass geophysical monitoring well with behind-casing instrumentation, and 3) a shallow (27 m) groundwater well for fluid sampling. A controlled-release test injected 38 tonnes of CO2 between 336-342 m depth in February 2019, and the gas was monitored by a wide range of downhole and surface monitoring technologies. CO2 reached the ISL OB-1 monitoring well (7 m away) after approximately 1.5 days and an injection volume of 5 tonnes. Evidence of arrival was determined by distributed temperature sensing and the CO2 plume was detected also by borehole seismic after injection of as little as 7 tonnes. Observations suggest that the fault zone did not alter the CO2 migration along bedding at the scale and depth of the experiment. No vertical CO2 migration was detected beyond the perforated injection interval; no notable changes were observed in groundwater quality or soil gas chemistry during and post injection. The early detection of significantly less than 38 tonnes of CO2 injected into the shallow subsurface demonstrates rapid and sensitive monitorability of potential leaks in the overburden of a commercial-scale storage project, prior to reaching shallow groundwater, soil zones or the atmosphere. The ISL is a unique and enduring research facility at which monitoring technologies will be further developed and tested for increasing public and regulator confidence in the ability to detect potential CO2 leakage at shallow to intermediate depth.

The In-Situ Laboratory Project entails completing, instrumenting and pump testing five intervals in an existing well and injecting a small volume of CO2 for testing purposes into the Lesueur Formation at the South West Hub project in Western Australia. The project commenced in the middle of October 2016 and is scheduled to run until the end of April 2019, with hydraulic testing and CO2 injection planned towards the end of 2018. The purpose is to aid demonstration of the commercial viability of geologically storing carbon and contribute to broadening the portfolio of globally evaluated geological settings for storage via testing of a more than 1000 m thick injection reservoir in which CO2 migration is largely governed by residual saturation and dissolution trapping. The project will develop the first part of an enduring research facility at the South West Hub to enable further research of a geological environment that has more uncertainty than many other current projects; i.e. in the case of the South West Hub there is uncertainty around the extent of a regional seal.

Active time-lapse seismic is widely employed for monitoring CO2 geosequestration due to its ability to track the distribution of fluids in space and time. However, standard 4D seismic monitoring suffers from several challenges, including high cost, disruption to other land uses, and, consequently, relatively large intervals between monitor surveys. Some of these challenges can be mitigated using permanently installed sources and receivers. Such an approach was tested at the CO2CRC Otway site by continuous offset VSP monitoring of 15,000 t of supercritical CO2 injected into an aquifer 1,500 m deep with nine permanent seismic sources (surface orbital vibrators or SOVs) and five downhole fibre-optic receivers. This continuous monitoring is complemented by multi-well 4D VSP using a mobile vibroseis source and the same DAS receivers, which included one baseline and two monitor surveys after injection of 4,000 and 12,000 t of CO2. The continuous DAS-SOV monitoring detected an abrupt increase of travel times below the injection interval on the second day of injection (after injection of 300 t of CO2) and tracked the growth of the areal CO2 plume by mapping changes of reflection amplitudes. The plume is also detected by time-lapse changes of reflection amplitudes in multi-well 4D VSPs. The plume images obtained from continuous offset VSP and 4D VSP are broadly consistent with each other but with some differences due to differences in illumination, lateral variations of velocities and seismic anisotropy. These differences also serve as a measure of uncertainty of 4D VSP images.

Time-lapse (4D) seismic monitoring of injected CO2 in geological formations is being increasingly employed as the principal method for ensuring containment of the CO2 and testing conformance of predicted plume behaviour. However, to bring further confidence in this method, the CO2 volume detection limit in the seismic monitoring and key factors controlling it need to be quantitatively understood. The CO2CRC Otway Project attempts to improve this understanding by exploring the capability of seismic reflection method to detect and monitor a 15,000 t injection of supercritical CO2/CH4 mixture in a saline aquifer at a depth of 1500 m. To increase the signal to noise ratio and to reduce the disruption to land users, seismic acquisition is performed using a buried geophone array. Seismic acquisition occurred at injection intervals of 5000, 10,000 and 15,000 t over a 5-month period. The seismic images clearly show the distribution and evolution of the stored CO2/CH4 plume. The analysis confirms that signal from pure CO2 would be of similar magnitude to the signal from CO2/CH4 mixture. The results demonstrate the potential of time-lapse reflection seismic to provide key information to both operators and regulators for confirming the security and behaviour of stored CO2 at very small volumes.

The South West Hub CCS project (SW Hub) in Western Australia is proceeding to reduce uncertainties related to injectivity, capacity and containment through a well drilling, coring and logging program. This study provides reviews of well designs for in situ tests and well-based monitoring methods at CO 2 storage sites. Wells are expensive and complex engineering undertakings, and their design including size, geometry and materials, greatly impacts on the type of data that can be collected and techniques for monitoring that can be performed at a site. There is no ‘one size-fits-all’ monitoring well, but there is a tool-box or ensemble of solutions that can achieve a broad range of relevant monitoring objectives given constraints of site characteristics and budgetary limitations. For the SW Hub, a multi-well, multi-use and multi-completion monitoring scheme is proposed that combines the benefit of four different types of monitoring wells in addition to equipping the injector: 1) a well completed in the reservoir for conformance monitoring with additional completion above the storage complex, 2) a well completed above the confining layer for ensuring containment, 3) a well completed in the reservoir in the vicinity of an identified fault for monitoring potential across-fault migration and fault re-activation risks and 4) a well for fault leakage surveillance above the storage complex.

The CO2CRC's “Otway Stage 2C project” is a test injection of 15,000 tons of supercritical gas mixture (80 mole% CO 2 & 20 mole% CH 4 ) at the CO2CRC Otway site in the Australian state of Victoria. The objective of this test is to examine the limits of surface seismic detection and to conduct detailed pressure monitoring of the injection. A key design feature of the project is injection near the bottom of a highly permeable formation, thereby allowing for buoyancy driven flow to thicken the plume and enhance seismic response. The project is specifically targeting observation of the development of the gas plume through a combination of multi-vintage 4D seismic surveys acquired with a buried seismic receiver array, 4D Vertical Seismic Profiling (VSP) and pressure measurements. Using both time-lapse seismic data and reservoir simulations, we aim to not only detect the plume but also demonstrate its eventual stabilisation. In this paper we discuss the technical aspects of the Otway Stage 2C seismic monitoring program and the initial results.

The CO2CRC Otway Project “Stage 3” is planned to be an injection of between 15,000 and 30,000 tonnes, to be carried out at the Otway site in South Western Victoria, Australia. The objective of the project is to test unobtrusive, continuous monitoring methods that would operate with a small environmental footprint and limited impact on other land use activities such as farming. Progress since GHGT13 falls into three broad areas; reservoir characterisation, dynamic modelling, and feasibility and design of the monitoring methods. The appraisal well CRC-3 was successfully drilled and a wide range of core and log data was collected. While only 600-700 metres from existing logged wells, it was crucial to confirm that the injection concept was feasible and that the plume would migrate towards the proposed monitoring wells. In addition, injection tests were performed that confirmed pressure continuity to the existing wells. As there are many small faults in the area this was an important outcome. The geological and dynamical models for the experiment have been updated with the data from CRC-3; and model predictions have benefited from the ongoing performance history match to the stage 2C time-lapse seismic monitoring experiment. Currently the Stage 3 project is in its Define phase, having completed its Opportunity Definition and Evaluate phases. By the time of GHGT14 we expect to be commencing the Execution phase, with designs finalised and the drilling programme imminent.

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.

Monitoring techniques capable of deep subsurface detection are desirable for early warning and leakage pathway identification in geologic carbon storage formations. This work demonstrates the feasibility of a pulse-testing-based leakage detection procedure, in which the storage reservoir is stimulated using periodic injection patterns and the acquired pressure perturbation signals are analyzed in the frequency domain to detect potential deviations in the reservoir's frequency domain responses. Unlike the traditional well testing and associated time domain analyses, pulse testing aims to minimize the interference of reservoir operations and other ambient noise by selecting appropriate pulsing frequencies such that reservoir responses to coded injection patterns can be uniquely determined in frequency domain. Field demonstration of this pulse-testing leakage detection technique was carried out at a CO2 enhanced oil recovery site—the Cranfield site located in Mississippi, USA, which has long been used as a carbon storage research site. During the demonstration, two sets of pulsing experiments (baseline and leak tests) were performed using 90-min and 150-min pulsing periods to demonstrate feasibility of time-lapse leakage detection. For leak tests, an artificial leakage source was created through rate-controlled venting of CO2 from one of the monitoring wells because of the lack of known leakage pathways at the site. Our results show that leakage events caused a significant deviation in the amplitude of the frequency response function, indicating that pulse testing may be deployed as a cost-effective active monitoring technique, with a great potential for site-wide automated monitoring.

Commercial scale Geological Carbon Storage (GCS) projects have high capital costs and energy penalties that could be partially offset by including the production of geothermal energy. An important requirement is to match the geothermal resources available at GCS sites with local market opportunities. This paper examines the key parameters that determine viable economics for various hybrid GCS-Geothermal energy applications with a focus on Australian GCS flagship sites as case study examples linked with the initial observations from a pilot trial at the SECARB Cranfield CO2 demonstration project in Cranfield, Mississippi, USA. At first approximation, offshore GCS-Geothermal coupling seems unlikely due to well costs and the additional engineering requirements. The Perth Basin provides the best opportunity for GCS-Geothermal direct use for desalination. Whilst none of the case study examples would be ideally suited for GCS-Geothermal, insights gained are used to speculate on what conditions would be required for an economically viable opportunity. A strong enabling economic driver is when a GCS project already includes pressure relief water production as part of its base case.

A controlled-release test at the In-Situ Laboratory Project in Western Australia injected 38 tonnes of gaseous CO2 between 336-342 m depth in a fault zone, and the gas was monitored by a wide range of downhole and surface monitoring technologies. Injection of CO2 at this depth fills the gap between shallow release (600 m) field trials. The main objectives of the controlled-release test were to assess the monitorability of shallow CO2 accumulations, and to investigate the impacts of a fault zone on CO2 migration. CO2 arrival was detected by distributed temperature sensing at the monitoring well (7 m away) after approximately 1.5 days and an injection volume of 5 tonnes. The CO2 plume was detected also by borehole seismic and electric resistivity imaging. The early detection of significantly less than 38 tonnes of CO2 in the shallow subsurface demonstrates rapid and sensitive monitorability of potential leaks in the overburden of a commercial-scale storage project, prior to reaching shallow groundwater, soil zones or the atmosphere. Observations suggest that the fault zone did not alter the CO2 migration along bedding at the scale and depth of the test. Contrary to model predictions, no vertical CO2 migration was detected beyond the perforated injection interval. CO2 and formation water escaped to the surface through the monitoring well at the end of the experiment due to unexpected damage to the well’s fibreglass casing. The well was successfully remediated without impact to the environment and the site is ready for future experiments.

At the Cooperative Research Centre for Greenhouse Gas Technology's (CO2CRC) field site in the Otway Basin of Victoria, Australia, investigations into the storage of CO2-rich gas in a depleted hydrocarbon gas field have been conducted in the Waarre C reservoir. The injected gas from the nearby Buttress field contained 75 mol% CO2, 21 mol% CH4 with the remaining balance being a mixture of wet hydrocarbons, condensate and nitrogen. Chemical tracers (sulphur hexafluoride, SF6; krypton, Kr; perdeuterated methane, CD4) were added on the basis of literature surveys and small volume trials at the Frio II Brine experiment in Texas. The aim of the project was to measure, monitor and verify the presence of injected CO2 in a depleted gas field and that the arrival of tracers was a major component of demonstrating breakthrough of CO2 at the monitoring well, Naylor-1. The paper focuses on methods developed for the injection, recovery and analysis of samples collected at the Naylor-1 well. Results of tracer analysis compare well with other data collected (including pH and density measurements) to demonstrate breakthrough. A slip-stream injection system was designed to deliver the tracers mixed with the CO2-rich gas into the subsurface at the CRC-1 well. The tracers were added to the gas stream 17 days after the start of injection (CO2 injection commenced 18th March, 2008) into the depleted natural gas field at Naylor. A U-tube system was used to retrieve the samples from the Naylor-1 monitoring well. Collected gas and formation water samples were analysed in detail for gas composition, tracers, isotopes (13C CO2 mainly) and inorganic geochemistry for the broader project. The tracer results confirm that CO2 breakthrough at the monitoring well occurred within the predicted times. However the interval between samples taken from the U-tubes was too coarse to resolve detailed differences in arrival times between the CO2 and tracers. Of the three tracers used, SF6 provided the clearest evidence of breakthrough at U-tube 2. Kr, because of its abundance in air, and its potential to be present in the subsurface, was more prone to contamination and had higher background levels prior to breakthrough. CD4 was expected to provide some more unique data based on the presence of abundant CH4 in the reservoir interval. With hindsight, larger volumes should have been injected to facilitate comparisons with the other tracers and add value to the data set. The test of CD4 however acted as a suitable proof of concept that CD4 could be used in such a high background of CH4. Further work is ongoing to generate data for partition coefficients between supercritical CO2, CH4 and water under the injection conditions.

We consider using CO 2 as an alternative to water as a working fluid to produce geothermal electricity through the application of a coupled reservoir, wellbore, and surface power-plant model. Our approach has relaxed some of the simplifying assumptions others have made in previous work, through the application of a subsurface reservoir model fully coupled with a detailed wellbore simulator. We also include a simplified representation of CO 2 turbomachinery for a surface plant optimized for direct use of supercritical CO 2 . The wellbore model includes heat transfer between the fluid in the well and the surrounding formation, in addition to frictional, inertial, and gravitational forces. Our results show that thermophysical operating conditions and the amount of power production are greatly influenced by wellbore flow processes and by wellbore/caprock heat transfer. We investigate competing effects that control development of a thermosiphon, which enables production of geothermal electricity without the need for a continuously operating external pump.

Understanding the impacts caused by injection of large volumes of CO 2 in the deep subsurface necessitates a comprehensive monitoring strategy. While surface-based and other remote geophysical methods can provide information on the general morphology of a CO 2 plume, verification of the geochemical conditions and validation of the remote sensing data requires measurements from boreholes that penetrate the storage formation. Unfortunately, the high cost of drilling deep wellbores and deploying instrumentation systems constrains the number of dedicated monitoring borings as well as limits the technologies that can be incorporated in a borehole completion. The objective of the Modular Borehole Monitoring (MBM) Program was to develop a robust suite of well-based tools optimized for subsurface monitoring of CO 2 that could meet the needs of a comprehensive well-based monitoring program. It should have enough flexibility to be easily reconfigured for various reservoir geometries and geologies. The MBM Program sought to provide storage operators with a turn-key fully engineered design that incorporated key technologies, function over the decades long time-span necessary for post-closure reservoir monitoring, and meet industry acceptable risk profiles for deep-well installations. While still within the conceptual design phase of the MBM program, the SECARB Anthropogenic Test in Citronelle, Alabama, USA was identified as a deployment site for our engineered monitoring systems. The initial step in designing the Citronelle MBM system was to down-select from the various monitoring tools available to include technologies that we considered essential to any program. Monitoring methods selected included U-tube geochemical sampling, discrete quartz pressure and temperature gauges, an integrated fibre-optic bundle consisting of distributed temperature and heat-pulse sensing, and a sparse string of conventional 3C-geophones. While not originally planned within the initial MBM work scope, the fibre-optic cable was able to also be used for the emergent technology of distributed acoustic sensing. The MBM monitoring string was installed in March, 2012. To date, the Citronelle MBM instruments continue to operate reliably. Results and lessons learned from the Citronelle MBM deployment are addressed along with examples of data being collected.

A major global research and development effort is underway to commercialize carbon capture and storage (CCS) as a method to mitigate climate change. Recent studies have shown the potential to couple CCS with geothermal energy extraction using supercritical CO 2 (ScCO 2 ) as the working fluid. In a geothermal reservoir, the working fluid produces electricity as a byproduct of the CCS process by mining heat out of a reservoir as it is circulated between injector and producer wells. While ScCO 2 has lower heat capacity than water, its lower viscosity more than compensates by providing for greater fluid mobility. Furthermore, CO 2 exhibits high expansivity and compressibility, which can both help reduce parasitic loads in fluid cycling. Given the high capital costs for developing the deep well infrastructure for geologic storage of CO 2 , the potential to simultaneously produce geothermal energy is an attractive method to offset some of the costs and added energy requirements for separating and transporting the waste CO 2 stream. We present here the preliminary design and reservoir engineering associated with the development of direct-fired turbomachinery for pilot-scale deployment at the SECARB Cranfield Phase III CO 2 Storage Project, in Cranfield, Mississippi, U.S.A. The pilot-scale deployment leverages the prior investment in the Cranfield Phase III research site, providing the first ever opportunity to acquire combined CO 2 storage/geothermal energy extraction data necessary to address the uncertainties involved in this novel technique. At the SECARB Cranfield Site, our target reservoir, the Tuscaloosa Formation, lies at a depth of 3.0 km, and an initial temperature of 127 °C. A CO 2 injector well and two existing observation wells are ideally suited for establishing a CO 2 thermosiphon and monitoring the thermal and pressure evolution of the well-pair on a timescale that can help validate coupled models. It is hoped that this initial demonstration on a pre-commercial scale can accelerate commercialization of combined CCS/geothermal energy extraction by removing uncertainties in system modeling.

The Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) Otway Project in Australia is the first heavily monitored pilot site for CO2 storage in a depleted natural gas reservoir. With the site characterisation and risk analysis complete, the new CRC-1 injection well was drilled in April 2007. An updated static and dynamic model forecast an injected gas transit time of between 4 and 8months between CRC-1 injection and Naylor-1 observation wells. Injection began on March 18th 2008 and was halted on August 29th 2009 with 65,445 tonnes of CO2 mixed gas stored. Two pulses of tracer compounds were added to help identify the injected CO2 from other naturally occurring CO2 and to track dispersion and diffusion. Assurance monitoring included surveillance of the atmosphere, soil gas and shallow groundwater. To date, no tracer compounds have been detected above background levels in samples taken as part of the assurance monitoring system. Monitoring of the reservoir has been accomplished with a combined geophysical and geochemical approach. Formation fluids are sampled at pressure with the multilevel U-Tube system. The transient geochemistry at the observation well has: (1) recorded injected gas arrival at the Naylor-1 observation well; (2) recorded tracer compound arrival at Naylor-1; (3) shown a mixing trend between the isotopic signature of the Naylor indigenous CO2 and that of the injection supply gas; and (4) provided an estimate for the dynamic storage capacity for a portion of the Naylor reservoir. The data collected are compared with the pre-injection dynamic model forecasts and provide a means of calibration. The CO2CRC Otway Project has successfully demonstrated the storage of CO2 in a depleted gas field. Geochemical assurance monitoring and reservoir surveillance will continue post injection. Continued analysis of the data will serve to reduce uncertainty in forecasting long term fate of the injected CO2 mixed gas.

The CO2CRC Otway Project in southwestern Victoria, Australia has injected over 17 months 65,445 tonnes of a mixed CO2-CH4 fluid into the water leg of a depleted natural gas reservoir at a depth of ∼2km. Pressurized sub-surface fluids were collected from the Naylor-1 observation well using a tri-level U-tube sampling system located near the crest of the fault-bounded anticlinal trap, 300m up-dip of the CRC-1 gas injection well. Relative to the pre-injection gas-water contact (GWC), only the shallowest U-tube initially accessed the residual methane gas cap. The pre-injection gas cap at Naylor-1 contains CO2 at 1.5mol% compared to 75.4mol% for the injected gas from the Buttress-1 supply well and its CO2 is depleted in 13C by 4.5‰ VPDB compared to the injected supercritical CO2. Additional assurance of the arrival of injected gas at the observation well is provided by the use of the added tracer compounds, CD4, Kr and SF6 in the injected gas stream. The initial breakthrough of the migrating dissolved CO2 front occurs between 100 and 121 days after CO2 injection began, as evidenced by positive responses of both the natural and artificial tracers at the middle U-tube, located an average 2.3m below the pre-injection GWC. The major CO2 increase to ∼60mol% and transition from sampling formation water with dissolved gas to sampling free gas occurred several weeks after the initial breakthrough. After another ∼3 months the CO2 content in the lowest U-tube, a further average 4.5m deeper, increased to ∼60mol%, similarly accompanied by a transition to sampling predominantly gases. Around this time, the CO2 content of the upper U-tube, located in the gas cap and an average 10.4m above the pre-injection GWC, increased to ∼20mol%. Subsequently, the CO2 content in the upper U-tube approaches 30mol% while the lower two U-tubes show a gradual decrease in CO2 to ∼48mol%, resulting from mixing of injected and indigenous fluids and partitioning between dissolved and free gas phases. Lessons learnt from the CO2CRC Otway Project have enabled us to better anticipate the challenges for rapid deployment of carbon storage in a commercial environment at much larger scales.

Single-well experimental design for studying residual trapping of supercritical carbon dioxide Yingqi Zhang 1 , Barry Freifeld 1 , Stefan Finsterle 1 , Martin Leahy 2,3 , Jonathan Ennis-King 2,3 , Lincoln Paterson 2,3 , Tess Dance 2,3 Lawrence Berkeley National Laboratory, Berkeley, CA,USA CSIRO Petroleum, Clayton, Victoria, Australia Cooperative Research Centre for Greenhouse Gas Technologies, Australia Abstract The objective of our research is to design a single-well injection withdrawal test to evaluate residual phase trapping at potential CO 2 geological storage sites. Given the significant depths targeted for CO 2 storage and the resulting high costs associated with drilling to those depths, it is attractive to develop a single well test that can provide data to assess reservoir properties and reduce uncertainties in the appraisal phase of site investigation. The main challenges in a single-well test design include (1) difficulty in quantifying the amount of CO 2 that has dissolved into brine or migrated away from the borehole; (2) non-uniqueness and uncertainty in the estimate of the residual gas saturation (S gr ) due to correlations among various parameters; and (3)the potential biased S gr estimate due to unaccounted heterogeneity of the geological medium. To address each of these challenges, we propose (1) to use a physical-based model to simulation test sequence and inverse modeling to analyze data information content and to quantify uncertainty; (2) to jointly use multiple data types generated from different kinds of tests to constrain the S gr estimate; and (3) to reduce the sensitivity of the designed tests to geological heterogeneity by conducting the same test sequence in both a water-saturated system and a system with residual gas saturation. To perform the design calculation, we build a synthetic model and conduct a formal analysis for sensitivity and uncertain quantification. Both parametric uncertainty and geological uncertainty are considered in the analysis. Results show (1) uncertainty in the estimation of S gr can be reduced by jointly using multiple data types and repeated tests; and (2) geological uncertainty is essential and needs to be accounted for in the estimation of S gr and its uncertainty. The proposed methodology is applied to the design of a CO 2 injection test at CO2CRC’s Otway Project Site, Victoria, Australia. 1. Introduction and Objective The geologic sequestration of anthropogenic greenhouse gases to mitigate climate change is receiving increasing attention as a means to reduce atmospheric emissions and the related impacts as a result of continued use of fossil fuels. The ability of a host formation to effectively trap CO 2 determines the suitability of a proposed site for long-term CO 2 sequestration. Four trapping mechanisms have been identified (IPCC, 2005): structural trapping, residual phase trapping, solubility trapping and mineralization trapping. This study focuses on residual phase trapping, i.e., the immobilization of individual bubbles or relatively small blobs of the CO 2 -rich phase. TheCO 2 bubbles are either trapped by capillary forces or are stuck in local trapping structures or dead-end portions of the pore space, preventing further CO 2 migration in response to pressure gradients or buoyancy forces. (CO 2 saturation can be reduced below the residual value by processes other than viscous flow, e.g., by compression or dissolution.) A parameter referred to as residual gas saturation (S gr ) is used to characterize the tendency of a geologic formation to trap some of the non-wetting phase in its pore space. The residual gas saturation is a property of the interaction between the porous medium and the fluids, mostly reflecting the size and shape of its pores and their connectivity. However, residual gas saturation is not a static parameter; it depends on the sequence of hysteretic drainage and imbibition processes, i.e., it is history-dependent, with different values at each point in the storage formation as the fluid saturation changes during CO 2 injection and redistribution. Only its maximum value S grmax (associated with the primary imbibition curve) can be considered as a formation parameter independent of the dynamic system

LUCI, the Laboratory for Underground CO2 Investigations, is an experimental facility being planned for the DUSEL underground laboratory in South Dakota, USA. It is designed to study vertical flow of CO2 in porous media over length scales representative of leakage scenarios in geologic carbon sequestration. The plan for LUCI is a set of three vertical column pressure vessels, each of which is ~500 m long and ~1 m in diameter. The vessels will be filled with brine and sand or sedimentary rock. Each vessel will have an inner column to simulate a well for deployment of down-hole logging tools. The experiments are configured to simulate CO2 leakage by releasing CO2 into the bottoms of the columns. The scale of the LUCI facility will permit measurements to study CO2 flow over pressure and temperature variations that span supercritical to subcritical gas conditions. It will enable observation or inference of a variety of relevant processes such as buoyancy-driven flow in porous media, JouleThomson cooling, thermal exchange, viscous fingering, residual trapping, and CO2 dissolution. Experiments are also planned for reactive flow of CO2 and acidified brines in caprock sediments and well cements, and for CO2-enhanced methanogenesis in organic-rich shales. A comprehensive suite of geophysical logging instruments will be deployed to monitor experimental conditions as well as provide data to quantify vertical resolution of sensor technologies. The experimental observations from LUCI will generate fundamental new understanding of the processes governing CO2 trapping and vertical migration, and will provide valuable data to calibrate and validate large-scale model simulations. © 2010 Elsevier Ltd. All rights reserved

To demonstrate the potential for geologic storage of CO 2 in saline aquifers, the Frio-I Brine Pilot was conducted, during which 1600 tons of CO 2 were injected into a high-permeability sandstone and the resulting subsurface plume of CO 2 was monitored using a variety of hydrogeological, geophysical, and geochemical techniques. Fluid samples were obtained before CO 2 injection for baseline geochemical characterization, during the CO 2 injection to track its breakthrough at a nearby observation well, and after injection to investigate changes in fluid composition and potential leakage into an overlying zone. Following CO 2 breakthrough at the observation well, brine samples showed sharp drops in pH, pronounced increases in HCO 3 − and aqueous Fe, and significant shifts in the isotopic compositions of H 2 O and dissolved inorganic carbon. Based on a calibrated 1-D radial flow model, reactive transport modeling was performed for the Frio-I Brine Pilot. A simple kinetic model of Fe release from the solid to aqueous phase was developed, which can reproduce the observed increases in aqueous Fe concentration. Brine samples collected after half a year had lower Fe concentrations due to carbonate precipitation, and this trend can be also captured by our modeling. The paper provides a method for estimating potential mobile Fe inventory, and its bounding concentration in the storage formation from limited observation data. Long-term simulations show that the CO 2 plume gradually spreads outward due to capillary forces, and the gas saturation gradually decreases due to its dissolution and precipitation of carbonates. The gas phase is predicted to disappear after 500 years. Elevated aqueous CO 2 concentrations remain for a longer time, but eventually decrease due to carbonate precipitation. For the Frio-I Brine Pilot, all injected CO 2 could ultimately be sequestered as carbonate minerals.

The Otway Project in Victoria, Australia, run by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) began injecting gas (80% CO2: 20% CH4) in a supercritical state in April, 2008. It has been labeled with tracers (SF6, Kr and CD4) added via a purpose built slip-stream injector to unequivocally allow verification of the presence of the injected CO2 at various monitoring sites. A bottom-hole assembly installed in the Naylor-1 monitoring well enables multi-level sampling of fluids at reservoir pressure to allow the determination of hydrological and geochemical processes that control plume movement and water-rock- CO2 interactions in the subsurface.

We analyzed a data set of thermally induced changes in fractured rock permeability during a 4-year heating (up to 200 °C) and subsequent 4-year cooling of a large volume, partially saturated and highly fractured volcanic tuff at the Yucca Mountain Drift Scale Test, Nevada, USA. Permeability estimates were derived from about 700 pneumatic (air-injection) tests, taken periodically at 44 packed-off borehole intervals during the heating and cooling cycle from November 1997 through November 2005. We analyzed air-permeability data by numerical modeling of thermally induced stress and moisture movements and their impact on air permeability within the highly fractured rock. Our analysis shows that changes in air permeability during the initial 4-year heating period, which were limited to about one order of magnitude, were caused by the combined effects of thermal-mechanically induced stress on fracture aperture and thermal-hydrologically induced changes in fracture moisture content. At the end of the subsequent 4-year cooling period, air-permeability decreases (to as low as 0.2 of initial) and increases (to as high as 1.8 of initial) were observed. By comparison to the calculated thermo-hydro-elastic model results, we identified these remaining increases or decreases in air permeability as irreversible changes in intrinsic fracture permeability, consistent with either inelastic fracture shear dilation (where permeability increased) or inelastic fracture surface-asperity shortening (where permeability decreased). In this paper, we discuss the possibility that such fracture asperity shortening and associated decrease in fracture permeability might be enhanced by dissolution of highly stressed surface asperities over years of elevated stress and temperature.

We performed a series of experiments to provide data for validating numerical models of gas hydrate behavior in porous media. Methane hydrate was formed and dissociated under various conditions in a large X-ray transparent pressure vessel, while pressure and temperature were monitored. In addition, X-ray computed tomography (CT) was used to determine local density changes during the experiment. The goals of the experiments were to observe changes occurring due to hydrate formation and dissociation, and to collect data to evaluate the importance of hydrate dissociation kinetics in porous media. In the series of experiments, we performed thermal perturbations on the sand/water/gas system, formed methane hydrate, performed thermal perturbations on the sand/hydrate/water/gas system resulting in hydrate formation and dissociation, formed hydrate in the resulting partially dissociated system, and dissociated the hydrate by depressurization coupled with thermal stimulation. Our CT work shows significant water migration in addition to possible shifting of mineral grains in response to hydrate formation and dissociation. The extensive data including pressure, temperatures at multiple locations, and density from CT data is described.

A dedicated field site was developed and a suite of experiments were conducted in the Sierra Nevada foothills, near the town of Raymond, CA to develop and test a multi-disciplinary approach to the characterization of groundwater flow and transport in fractured rocks. A wealth of geologic, hydrologic and geophysical data was collected at the site using a variety of unique tools. A cluster of nine approximately 90 m deep boreholes were drilled at the site in a V-shaped pattern with an angle of 60°. The boreholes are spaced 7.5, 15, 30 and 60 m from the central borehole. Various geophysical and hydrologic tests were conducted in and between these boreholes. Integration of cross-hole radar and seismic tomography, borehole flow surveys and images from a new digital borehole scanner indicated that groundwater flow is mainly confined to a few sub-horizontal fracture zones. A unique suite of hydraulic tests were conducted, in which three to four intervals in each of the nine boreholes were isolated using pneumatic packers. Some 130 injection tests were conducted, and more than 4100 cross-hole transient pressure measurements were obtained. A computer algorithm was developed to analyze such massive interference data systematically. As a result of the analysis, an image of the fracture connections emerged, which is consistent with the geophysical data. High precision tiltmeters were effective in remotely characterizing the preferential flow path. Several radial convergent tracer tests were conducted by injecting a mixture of several conservative tracers and one sorbing tracer: deuterium, fluorescein, lithium bromide and polystyrene micro-spheres. Some differences between the breakthrough curves are observed, which may be due to possible differences among so-called “conservative” tracers. Some characterization tools were found to be more effective than others in locating flowing fractures. However, no single tool was almighty. Characterization of fractured rock is extremely challenging and requires a stepwise and well-thought approach, which is basically a good old scientific approach. Prediction of transport based on the characterization results is even more challenging and one should always bear in mind that it is virtually impossible to uniquely characterize a fractured rock.