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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.

The objective of this study is to evaluate the sensitivity of Distributed Temperature Sensing (DTS) data to detect CO2 leakage along an injection well casing. This paper describes the relationship between the CO2 leakage rate and temperature response at DTS locations, and the method and numerical model used for understanding such a relationship. The uncertainties in the parameters are propagated to the interpretation of DTS measurements, which may lead to false positive and false negative identifications of CO2 leakage. We propose to identify CO2 leakage by analyzing both temperature history plots at selected vertical locations as well as the vertical temperature profiles at different times. The analysis should be combined with numerical simulations for the estimation of leakage rates. In addition, leakage needs to be confirmed by data from a warm-up test (temperature recovery after injection of cold CO2 is stopped) to minimize the probability of false identifications.

A blowout of the Sesnon Standard-25 well (SS-25; API 03700776) at the Aliso Canyon Underground Gas Storage Facility, first observed on October 23, 2015, eventually resulted in emission of nearly 100,000 tonnes of natural gas (mostly methane) to the atmosphere. Several thousand people were displaced from their homes as the blowout spanned 111 days. Seven attempts to gain pressure control and stop the gas flow by injection of heavy kill fluids through the wellhead failed, a process referred to as a “top kill.” Introduction of drilling mud when a relief well milled through the casing of SS-25 at a depth of ∼8 400 ft (“bottom kill”) succeeded in halting the gas flow on February 11, 2016. We carried out coupled well-reservoir numerical modeling using T2Well to assess why the top kills failed to control the blowout. T2Well couples a reservoir simulation in which porous media flow is described using Darcy's law with a discretized wellbore in which the Navier-Stokes momentum equation implemented via a drift-flux model (Shi et al., 2005) is used to describe multi-phase fluid transport to allow detailed process modeling of well blowouts and kill attempts. Modeling reveals the critical importance of well geometry in controlling flow dynamics and the corresponding success or failure of the kill attempts. Geometry plays a role in controlling where fluids can flow, e.g., when gas flow prevents liquid flow from entering the tubing from the annulus, but geometry also provides the opportunity for dead end regions to accumulate stagnant gas and liquid that can also affect kill attempts. Simulations show that follow-up fluid injections after the main kill attempts likely would have been effective to ensure that gas leakage remains stopped. T2Well is capable of simulating well kills and understanding the mechanisms behind well control failures and successes.

CO2 has been proposed as a working fluid for geothermal energy production because of its ability to establish a self-sustaining CO2 thermosiphon, taking advantage of the strong temperature dependence of CO2 density. To test the concept of CO2 heat extraction, in January 2015 a CO2 thermosiphon was operated at the SECARB Cranfield Site, Cranfield, Mississippi, where a brine-saturated sand at a depth of 3.2 km has been under near continuous CO2 flood since December 2009 as part of a U.S. Department of Energy demonstration of CO2 sequestration, resulting in a partially saturated reservoir surrounding a well pair. The lateral distance between the producer and injector was 112 m at reservoir depth, a distance considered pre-commercial in scale, but great enough that thermal breakthrough was still not significant after several years of injection. Instead of producing power with a turbine, heat was extracted heat from recirculated fluid using a heat exchanger and portable chiller. The well field and surface equipment were instrumented to compare field observations with predicted responses from numerical models. Thermosiphon flow could be initiated by venting, but thereafter flow rate steadily declined, indicating that the thermosiphon was not sustainable. To model the system, the capability of T2Well, a fully coupled wellbore/reservoir numerical simulator, was expanded to enable simulation of the entire loop of fluid circulation in the fully-coupled system consisting of the injection/production wells, the reservoir, and the surface devices (heat exchanger, flow-rate regulator etc.). Combined with the newly developed TOUGH2 equation of state module called EOS7CMA, the enhanced T2Well was used prior to the field experiment to simulate the circulation of a CO2-H2O-CH4 mixture in a model geothermal system patterned after the Cranfield demonstration test. The model predicted that a sustainable thermosiphon could be achieved. After the field thermosiphon did not achieve the pre-test prediction of flow rates and thermosiphon sustainability, the numerical model was modified to improve realism and calibrate certain processes; it was then able to reproduce the major phenomena observed in the field. In a series of sensitivity studies, many factors were found that could potentially contribute to the failing of a sustainable thermosiphon. These factors could be categorized as two types: factors that increase the resistance to flow and factors that increase heat loss of the working fluid. The lessons learned can be applied to both future modeling and to achieving CO2-based geothermal reservoir exploitation.

A modular borehole monitoring concept has been implemented to provide a suite of well-based monitoring tools that can be deployed cost effectively in a flexible and robust package. The initial modular borehole monitoring system was deployed as part of a CO2 injection test operated by the Southeast Regional Carbon Sequestration Partnership near Citronelle, Alabama. The Citronelle modular monitoring system transmits electrical power and signals, fibre-optic light pulses, and fluids between the surface and a reservoir. Additionally, a separate multi-conductor tubing-encapsulated line was used for borehole geophones, including a specialized clamp for casing clamping with tubing deployment. The deployment of geophones and fibre-optic cables allowed comparison testing of distributed acoustic sensing. We designed a large source effort (>64 sweeps per source point) to test fibre-optic vertical seismic profile and acquired data in 2013. The native measurement in the specific distributed acoustic sensing unit used (an iDAS from Silixa Ltd) is described as a localized strain rate. Following a processing flow of adaptive noise reduction and rebalancing the signal to dimensionless strain, improvement from repeated stacking of the source was observed. Conversion of the rebalanced strain signal to equivalent velocity units, via a scaling by local apparent velocity, allows quantitative comparison of distributed acoustic sensing and geophone data in units of velocity. We see a very good match of uncorrelated time series in both amplitude and phase, demonstrating that velocityconverted distributed acoustic sensing data can be analyzed equivalent to vertical geophones. We show that distributed acoustic sensing data, when averaged over an interval comparable to typical geophone spacing, can obtain signal-to-noise ratios of 18 dB to 24 dB below clamped geophones, a result that is variable with noise spectral amplitude because the noise characteristics are not identical. With vertical seismic profile processing, we demonstrate the effectiveness of downgoing deconvolution from the large spatial sampling of distributed acoustic sensing data, along with improved upgoing reflection quality. We conclude that the extra source effort currently needed for tubing-deployed distributed acoustic sensing vertical seismic profile, as part of a modular monitoring system, is well compensated by the extra spatial sampling and lower deployment cost as compared with conventional borehole geophones.

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.

Author(s): Lindsey, NJ; Martin, ER; Dreger, DS; Freifeld, B; Cole, S; James, SR; Biondi, BL; Ajo-Franklin, JB | Abstract: Our understanding of subsurface processes suffers from a profound observation bias: seismometers are sparse and clustered on continents. A new seismic recording approach, distributed acoustic sensing (DAS), transforms telecommunication fiber-optic cables into sensor arrays enabling meter-scale recording over tens of kilometers of linear fiber length. We analyze cataloged earthquake observations from three DAS arrays with different horizontal geometries to demonstrate some possibilities using this technology. In Fairbanks, Alaska, we find that stacking ground motion records along 20nm of fiber yield a waveform that shows a high degree of correlation in amplitude and phase with a colocated inertial seismometer record at 0.8–1.6nHz. Using an L-shaped DAS array in Northern California, we record the nearly vertically incident arrival of an earthquake from The Geysers Geothermal Field and estimate its backazimuth and slowness via beamforming for different phases of the seismic wavefield. Lastly, we install a fiber in existing telecommunications conduits below Stanford University and show that little cable-to-soil coupling is required for teleseismic P and S phase arrival detection.

A single well characterisation test was conducted at the CO2CRC Otway storage site in Victoria, Australia, in 2011 and repeated in 2014. The near-well permeability was found to have declined nearly 60% since the 2011 test, while the residual saturation inferred from a variety of techniques was lower in 2014. There was a significant change in water chemistry, suggesting an alteration of near-well reservoir properties. Possible reasons for these changes are explored, and the implications for other field tests are discussed.

Summary Carbon geosequestration requires the mapping and monitoring of the injected CO2 to assure the gas is safely stored in the formation. In this context, Distributed Acoustic Sensing (DAS) has the potential to reduce the costs of seismic operations and increase equipment survivability. Field demonstrations show that DAS can be used for reservoir monitoring in geosequestration applications but most of its studies are limited to borehole seismic surveys, while very little has been published towards DAS for surface seismic. To bridge this gap, capability for seismic monitoring using a 3D DAS array was tested during a test CO2 injection of the CO2CRC Otway Project (Victoria, Australia). DAS was deployed together with geophones along eleven receiver lines and data were acquired before and after the injection of 5kt, 10kt and 15kt of supercritical CO2. Processing of DAS data is very challenging due to strong angle dependence of its sensitivity and very large volumes of recorded data. Preliminary processing results show that we can identify the main reflectors but noise is still strong. The results also show strong azimuth dependence of DAS sensitivity.

Monitoring the fate of the injected CO2 and possible associated effects, such as hydro-mechanical and chemical effects in the target reservoir and its surroundings, is essential for safe operation of a storage facility. In this chapter, we shall first provide an overview of the technologies available and used for monitoring of CO2. We shall then proceed to describe specific methods and finally present some important case studies that will demonstrate the use of the discussed monitoring technologies under specific field settings.

The Containment and Monitoring Institute (CaMI) has built a Field Research Station (FRS) near Calgary, Alberta, Canada, designed around small injections (up to 1000 tonnes per year) of CO2 at depths of approximately 300 m and 500 m. Baseline borehole geophysical surveys have been completed at the CaMI site as part of a larger monitoring effort aimed at detecting and monitoring the small (1-2 ton) gas phase CO2 plume as well as any vertical migration. Crosswell seismic and EM data, as well as borehole-to-surface EM data, were recorded and have sufficient data quality to proceed with time-lapse monitoring. Initial processing for quality control has been accomplished. Seismic processing to date includes initial travel time picking and indicates that data is sufficient for velocity inversion. EM processing includes comparison of acquired data (amplitude and phase) with a layered model based on resistivity logs with repeatability of ~2%. The use of fiberglass casing in one monitoring well supports the use of EM methods. Joint inversion of the seismic and EM measurements (i.e. P-wave velocity and electrical conductivity) is planned to improve the estimate of CO2 saturation in the subsurface.

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 large-scale carbon dioxide (CO2) injection pilot is ongoing at Cranfield, Mississippi, in a saline aquifer with high dissolved methane (CH4) content, employing one injection well and two observation wells. The breakthrough of CH4 and CO2 at the observation wells provides insights to phase partitioning and the multipath nature of flow through the formation. Injected CO2 is cooler than the formation temperature, making temperature another useful observation. Simulations of the first year of CO2 injection were conducted with the numerical simulator TOUGH2 and the equation of state module EOS7C, which includes CO2, CH4, and H2O, using an axisymmetric model with layering based on well logs from the injection well. Although the simplification of an axisymmetric model precludes study of formation dip or lateral heterogeneity, its simple structure enables a focus on physical processes involving the phase partitioning of CH4 and CO2, and temperature effects. Field observations that the model reproduces include the arrival of a bank of free-phase CH4 ahead of the main CO2 plume at each observation well, and non-monotonic changes in CH4 and CO2 mole fraction as a function of time, suggesting that multiple distinct flow paths exist between the injection well and the observation wells, each with its own bank of free-phase CH4 leading the CO2. Model results are compared with temperature observations made in the field with a Distributed Temperature Sensor (DTS) system, suggesting that a well-defined thermal response reached the near observation well within the seven-month monitoring period, but not the more distant observation well. © 2013 Society of Chemical Industry and John Wiley & Sons, Ltd

Accurate estimation of CO2 saturation in a saline aquifer is essential for the monitoring of supercritical CO2 injected for geological sequestration. Because of strong contrasts in density and elastic properties between brine and CO2 at reservoir conditions, seismic methods are among the most commonly employed techniques for this purpose. However the relationship between seismic (P‐wave) velocity and CO2 saturation is not unique because the velocity depends on both wave frequency and the CO2 distribution in rock. In the laboratory, we conducted measurements of seismic properties of sandstones during supercritical CO2 injection. Seismic responses of small sandstone cores were measured at frequencies near 1 kHz, using a modified resonant bar technique (Split Hopkinson Resonant Bar method). Concurrently, saturation and distribution of supercritical CO2 in the rock cores were determined via x‐ray CT scans. Changes in the determined velocities generally agreed with the Gassmann model. However, both the velocity and attenuation of the extension wave (Young's modulus or ‘bar’ wave) for the same CO2 saturation exhibited differences between the CO2 injection test and the subsequent brine re‐injection test, which was consistent with the differences in the CO2 distribution within the cores. Also, a comparison to ultrasonic velocity measurements on a bedded reservoir rock sample revealed that both compressional and shear velocities (and moduli) were strongly dispersive when the rock was saturated with brine. Further, large decreases in the velocities of saturated samples indicated strong sensitivity of the rock's frame stiffness to pore fluid.

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.

Permanent downhole gauges for measuring pressure and temperature are very useful for reservoir surveillance. Whereas most applications have used a single downhole gauge, here we discuss experience using multiple downhole gauges simultaneously in a single well. At the CO2CRC Otway site four permanent gauges were installed in the CRC-2 well in 2011 with these gauges bracketing the perforation interval. The gauges were used to monitor the injection at various stages of water, pure carbon dioxide, impure carbon dioxide and nitrogen. Observations from these gauges have allowed the position of the gas-water interface to be observed as it moved up and down through the perforation interval. This provides information on the effectiveness of the perforations and the fraction of reservoir zone being accessed. The changing densities of gas mixtures due to temperature and composition were also inferred. These observations assist the development of better wellbore models for use in reservoir simulation of near-wellbore fluid flow, replacing the often-used initial assumption that one single phase contacts the entire injection or production interval. The current installation in CRC-2 at Otway has eight gauges distributed over two completion intervals, one flowing and one isolated from the wellbore. This elaborate configuration allows observations of additional information including the vertical pressure diffusion between the reservoir intervals.

International audience; This paper provides an overview of the site characterization work at the Heletz site, in preparation to scientifically motivated CO2 injection experiments. The outcomes are geological and hydrogeological models with associated medium properties and baseline conditions. The work has consisted on first re-analyzing the existing data base from ∼40 wells from the previous oil exploration studies, based on which a 3-dimensional structural model was constructed along with first estimates of the properties. The CO2 injection site is located on the saline edges of the Heletz depleted oil field. Two new deep (>1600 m) wells were drilled within the injection site and from these wells a detailed characterization program was carried out, including coring, core analyses, fluid sampling, geophysical logging, seismic survey, in situ hydraulic testing and measurement of the baseline pressure and temperature. The results are presented and discussed in terms of characteristics of the reservoir and cap-rock, the mineralogy, water composition and other baseline conditions, porosity, permeability, capillary pressure and relative permeability. Special emphasis is given to petrophysical properties of the reservoir and the seal, such as comparing the estimates determined by different methods, looking at their geostatistical distributions as well as changes in them when exposed to CO2.

A permanent geophone array along with a fibre optic distributed acoustic sensing (DAS) array were deployed at the CO2CRC Otway Project site in order to conduct seismic monitoring of a CO2 plume during a small-scale injection test. This study aims to assess the ability for a permanent geophone array to overcome issues related to different acquisition (receiver) designs, high ambient noise level and seasonal variations in the near surface, as well as to test the DAS system for performing cost-effective time lapse seismic measurements. The acquisition of 3D seismic data is performed for this purpose using ~3000 vibroseis source points. We show the preliminary results of seismic reflection imaging conducted using DAS data. We observe the differences in performance between a standard commercially available tactical fibre optic cable and a custom helically wound cable. The results of this study and the workflows established will be used for processing a complete 3D seismic dataset acquired with a DAS array before being compared to a conventional geophone array.

In response to the urgent need for estimates of the oil and gas flow rate from the Macondo well MC252-1 blowout, we assembled a small team and carried out oil and gas flow simulations using the TOUGH2 codes over two weeks in mid-2010. The conceptual model included the oil reservoir and the well with a top boundary condition located at the bottom of the blowout preventer. We developed a fluid properties module (Eoil) applicable to a simple two-phase and two-component oil-gas system. The flow of oil and gas was simulated using T2Well, a coupled reservoir-wellbore flow model, along with iTOUGH2 for sensitivity analysis and uncertainty quantification. The most likely oil flow rate estimated from simulations based on the data available in early June 2010 was about 100,000 bbl/d (barrels per day) with a corresponding gas flow rate of 300 MMscf/d (million standard cubic feet per day) assuming the well was open to the reservoir over 30 m of thickness. A Monte Carlo analysis of reservoir and fluid properties provided an uncertainty distribution with a long tail extending down to 60,000 bbl/d of oil (170 MMscf/d of gas). The flow rate was most strongly sensitive to reservoir permeability. Conceptual model uncertainty was also significant, particularly with regard to the length of the well that was open to the reservoir. For fluid-entry interval length of 1.5 m, the oil flow rate was about 56,000 bbl/d. Sensitivity analyses showed that flow rate was not very sensitive to pressure-drop across the blowout preventer due to the interplay between gas exsolution and oil flow rate.

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.

An in-situ incubation device (ISI) was developed in order to investigate the stability and dynamics of sediment associated microbial communities to prevailing subsurface oxidizing or reducing conditions. Here we describe the use of these devices at the Old Rifle Uranium Mill Tailings Remedial Action (UMTRA) site. During the 7 month deployment oxidized Rifle aquifer background sediments (RABS) were deployed in previously biostimulated wells under iron reducing conditions, cell densities of known iron reducing bacteria including Geobacteraceae increased significantly showing the microbial community response to local subsurface conditions. PLFA profiles of RABS following in situ deployment were strikingly similar to those of adjacent sediment cores suggesting ISI results could be extrapolated to the native material of the test plots. Results for ISI deployed reduced sediments showed only slight changes in community composition and pointed toward the ability of the ISIs to monitor microbial community stability and response to subsurface conditions.

The Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) is currently injecting 100,000 tons of CO{sub 2} in a large-scale test of storage technology in a pilot project in southeastern Australia called the CO2CRC Otway Project. The Otway Basin, with its natural CO{sub 2} accumulations and many depleted gas fields, offers an appropriate site for such a pilot project. An 80% CO{sub 2} stream is produced from a well (Buttress) near the depleted gas reservoir (Naylor) used for storage (Figure 1). The goal of this project is to demonstrate that CO{sub 2} can be safely transported, stored underground, and its behavior tracked and monitored. The monitoring and verification framework has been developed to monitor for the presence and behavior of CO{sub 2} in the subsurface reservoir, near surface, and atmosphere. This monitoring framework addresses areas, identified by a rigorous risk assessment, to verify conformance to clearly identifiable performance criteria. These criteria have been agreed with the regulatory authorities to manage the project through all phases addressing responsibilities, liabilities, and to assure the public of safe storage.

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.

Careful site characterization is critical for successful geologic storage of carbon dioxide (CO2) because of the many physical and chemical processes impacting CO2 movement and containment under field conditions. Traditional site characterization techniques such as geological mapping, geophysical imaging, well logging, core analyses, and hydraulic well testing provide the basis for judging whether or not a site is suitable for CO2 storage. However, only through the injection and monitoring of CO2 itself can the coupling between buoyancy flow, geologic heterogeneity, and history-dependent multi-phase flow effects be observed and quantified. CO2 injection and monitoring can therefore provide a valuable addition to the site-characterization process. Additionally, careful monitoring and verification of CO2 plume development during the early stages of commercial operation should be performed to assess storage potential and demonstrate permanence. The Frio brine pilot, a research project located in Dayton, Texas (USA) is used as a case study to illustrate the concept of an iterative sequence in which traditional site characterization is used to prepare for CO2 injection and then CO2 injection itself is used to further site-characterization efforts, constrain geologic storage potential, and validate understanding of geochemical and hydrological processes. At the Frio brine pilot, in addition to traditional site-characterization techniques, CO2 movement in the subsurface is monitored by sampling fluid at an observation well, running CO2-saturation-sensitive well logs periodically in both injection and observation wells, imaging with crosswell seismic in the plane between the injection and observation wells, and obtaining vertical seismic profiles to monitor the CO2 plume as it migrates beyond the immediate vicinity of the wells. Numerical modeling plays a central role in integrating geological, geophysical, and hydrological field observations.

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.

Summary We present results from an intermediate scale field experiment conducted in December 2014, evaluating the use of Distributed Acoustic Sensing (DAS) for recording ambient noise generated by infrastructure use; the future aim of our effort is to utilize ambient noise for real-time geotechnical evaluation of soils beneath active infrastructure. We present details of the installation, recording comparisons of 4 selected DAS cables, and a noise comparison between DAS and classical 3C geophones. We conclude by showing preliminary examples of ambient noise interferometry using passive data acquired with DAS vs. 3C geophones.

Author(s): Freifeld, Barry M.; Kneafsey, Timothy J.; Rack, Frank | Abstract: X-ray computed tomography (CT) is an established technique for nondestructively characterizing geologic cores. CT provides information on sediment structure, diagenetic alteration, fractures, flow channels and barriers, porosity, and fluid-phase saturation. A portable CT imaging system has been developed specifically for imaging whole-round cores at the drilling site. The new system relies upon carefully designed radiological shielding to minimize the size and weight of the resulting instrument. Specialized x-ray beam collimators and filters maximize system sensitivity and performance. The system has been successfully deployed on the research vessel Joides Resolution for Ocean Drilling Program's Leg 204 and 210, within the Ocean Drilling Program's refrigerated Gulf Coast Core Repository, as well as on the Hot Ice #1 drilling platform located near the Kuparuk Field, Alaska. A methodology for performing simple densiometry measurements, as well as scanning for gross structural features, will be presented using radiographs from ODP Leg 204. Reconstructed CT images from Hot Ice #1 will demonstrate the use of CT for discerning core textural features. To demonstrate the use of CT to quantitatively interpret dynamic processes, we calculate 95 percent confidence intervals for density changes occurring during a laboratory methane hydrate dissociation experiment. The field deployment of a CT represents a paradigm shift in core characterization, opening up the possibility for rapid systematic characterization of three-dimensional structural features and leading to improved subsampling and core-processing procedures.

During the last decade, distributed acoustic sensing (DAS) has emerged as a new technology for seismic acquisition. DAS has the potential to reduce the cost of permanent monitoring operations over time as it offers long equipment survivability and requires minimum maintenance. However, broad adoption of DAS technology still faces some challenges, such as low sensitivity and high levels of noise compared to conventional seismic sensors. Recent developments in fiber-optic systems and cable designs aim to overcome these limitations. To understand how DAS can be used in monitoring applications, it is important to know how it behaves with varying offsets and incidence angles. An offset VSP survey was acquired, at the CO2CRC Otway Project, using a straight single-mode fiber, a straight “enhanced-backscatter” fiber, and a conventional three-component geophone tool. The results from this survey show that DAS has the potential to provide similar, or even superior, quality data sets as conventional geophones.