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It is crucial to ensure the safety and integrity of underground gas storage (UGS) infrastructure for energy reliability in California, and many other places around the world. To address the risk management need in UGS industry, we take advantage of recent advances in downhole fiber optic monitoring and coupled well-reservoir simulation to provide unprecedented understanding of gas flow in wells at UGS sites. We have combined advanced monitoring and simulation of UGS operations into a decision-support system called the Integrated Risk Management and Decision Support System (IRMDSS). The IRMDSS framework includes three components: (i) mechanistic models, (ii) continuous and frequent monitoring data, and (iii) a supervisory interface for performing analyses using the models and monitoring data. The goal of the IRMDSS is to equip UGS operators with real-time monitoring data and simulation tools that can alert them to potential failures, detect early leakage, and support mitigation decision-making to prevent otherwise larger failures. We demonstrate an application of the IRMDSS by analyzing the temperature and pressure response to a hypothetical leak. Through a review of distributed temperature sensing (DTS) data collected at an operating UGS facility we show that DTS can uniquely and precisely identify the depth of the gas-water-contact in the well annulus, and that DTS can provide an early warning signal of upward gas flow as would occur in a well blowout scenario. When combined with modeling analysis, a rough leak rate can be roughly estimated to understand the severity of the leakage conditions and to support the mitigation decision needed.

Well integrity is critical to the safety and success of subsurface energy exploration and management, as leakage of fluids from subsurface reservoirs is often induced by compromised wells. This study investigates bending deformation of a mockup of an oil/gas well that is subjected to loads expected in deviated wells under reservoir compaction and assesses the feasibility of utilizing distributed fiber optic strain sensing to monitor the deformation. A well mockup, which consists of outer and inner steel pipes with a cemented annulus, is tested under three-point bending loading and its strain and curvature development is monitored by Brillouin optical time domain reflectometry/analysis (BOTDR/A) as well as optical frequency domain reflectometry (OFDR). The primary objective of this research is to assess the strain sensing performance of newly fabricated fiber optic cables and to identify key cable characteristics which could improve the quality of distributed strain measurements with BOTDR/A. Results show that the tight-buffered cable is best suited for strain sensing as its maximum errors in the strain measurement were −36% and −24% against conventional sensors at the maximum elastic and plastic bending loads, respectively, whereas those of the non-tight-buffered cable were −45% and −71%, respectively. Similar trends were obtained in the bending curvature measurement. The detailed design of the tight-buffered cable is presented to elucidate key characteristics of such a cable, which will facilitate accurate distributed strain sensing in oil and gas wells.

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.

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 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.

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.

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 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.

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

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.

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.

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.

At Ketzin, located west of Berlin, the GFZ German Centre for Geosciences is operating Europe's largest CO2 research storage site. This pilot site has been developed since 2004 and is comprised of one combined injection/observation well and four monitoring wells. From June 2008 to August 2013, a total of 67 kilotons of CO2 were safely injected into the sandstone units of the Upper Triassic Stuttgart Formation in a depth between 630 to 650 m. The paper discusses the well designs and lessons learned in drilling engineering and operations. The abandonment phase started in Ketzin with the first plug cementation of the observation well Ktzi 202 shortly after shut-in of CO2 injection. The experience with the first CO2 well killing operation will be reviewed.

The Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) is currently injecting 100,000 tons of CO2 in a large scale test of storage technology in a pilot project in South Eastern Australia called the CO2CRC Otway Basin Project (Otway). The Otway Basin with its natural CO2 accumulations and many depleted gas fields, offers an appropriate site for such a pilot project. An 80% CO2 stream is produced from a well (Buttress) near to the depleted gas reservoir (Naylor) used for storage. The goal of this pilot project is to demonstrate that CO2 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 CO2 in the sub-surface reservoir, near surface and atmosphere. This monitoring framework has been selected to address the areas identified by a rigorous process of risk assessment and subsequently 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 provide assurance of safe storage to the satisfaction of the public at large.

Measurements on hydrate-bearing laboratory and field samplesare necessary in order to provide realistic bounds on parameters used innumerically modeling the production of natural gas from hydrate-bearingreservoirs. The needed parameters include thermal conductivity,permeability, relative permeability-saturation(s) relationships, andcapillary pressure-saturation(s) relationships. We have developed atechnique to make hydrate-bearing samples ranging in scale from coreplug-size to core-size in the laboratory to facilitate making thesemeasurements. In addition to pressure and temperature measurements, weuse x-ray computed tomography scanning to provide high-resolution dataproviding insights on processes occurring in our samples. Several methodsare available to make gas hydrates in the laboratory, and we expect thatthe method used to make the hydrate will impact the behavior of thehydrate sample, and the parameters measured.

Natural-gas hydrates have been encountered beneath the permafrost and considered a nuisance by the oil and gas industry for years. Engineers working in Russia, Canada and the USA have documented numerous drilling problems, including kicks and uncontrolled gas releases, in arctic regions. Information has been generated in laboratory studies pertaining to the extent, volume, chemistry and phase behavior of gas hydrates. Scientists studying hydrate potential agree that the potential is great--on the North Slope of Alaska alone, it has been estimated at 590 TCF. However, little information has been obtained on physical samples taken from actual rock containing hydrates. The work scope drilled and cored a well The Hot Ice No. 1 on Anadarko leases beginning in FY 2003 and completed in 2004. An on-site core analysis laboratory was built and utilized for determining the physical characteristics of the hydrates and surrounding rock. The well was drilled from a new Anadarko Arctic Platform that has a minimal footprint and environmental impact. The final efforts of the project are to correlate geology, geophysics, logs, and drilling and production data and provide this information to scientists developing reservoir models. No gas hydrates were encountered in this well; however, a wealth of information was generated and is contained in this report. The Hot Ice No. 1 well was drilled from the surface to a measured depth of 2300 ft. There was almost 100% core recovery from the bottom of surface casing at 107 ft to total depth. Based on the best estimate of the bottom of the methane hydrate stability zone (which used new data obtained from Hot Ice No. 1 and new analysis of data from adjacent wells), core was recovered over its complete range. Approximately 580 ft of porous, mostly frozen, sandstone and 155 of conglomerate were recovered in the Ugnu Formation and approximately 215 ft of porous sandstone were recovered in the West Sak Formation. There were gas shows in the bottom part of the Ugnu and throughout the West Sak. No hydrate-bearing zones were identified either in recovered core or on well logs. The base of the permafrost was found at about 1260 ft. With the exception of the deepest sands in the West Sak and some anomalous thin, tight zones, all sands recovered (after thawing) are unconsolidated with high porosity and high permeability. At 800 psi, Ugnu sands have an average porosity of 39.3% and geometrical mean permeability of 3.7 Darcys. Average grain density is 2.64 g/cc. West Sak sands have an average porosity of 35.5%, geometrical mean permeability of 0.3 Darcys, and average grain density of 2.70 g/cc. There were several 1-2 ft intervals of carbonate-cemented sandstone recovered from the West Sak. These intervals have porosities of only a few percent and very low permeability. On a well log they appear as resistive with a high sonic velocity. In shallow sections of other wells these usually are the only logs available. Given the presence of gas in Hot Ice No. 1, if only resistivity and sonic logs and a mud log had been available, tight sand zones may have been interpreted as containing hydrates. Although this finding does not imply that all previously mapped hydrate zones are merely tight sands, it does add a note of caution to the practice of interpreting the presence of hydrates from old well information. The methane hydrate stability zone below the Hot Ice No. 1 location includes thick sections of sandstone and conglomerate which would make excellent reservoir rocks for hydrates and below the permafrost zone shallow gas. The Ugnu formation comprises a more sand-rich section than does the West Sak formation, and the Ugnu sands when cleaned and dried are slightly more porous and significantly more permeable than the West Sak.

Residual trapping is one of the four trapping mechanisms that have been identified for geological CO2 storage, a means to reduce atmospheric emissions and the related impacts as a result of continued use of fossil fuels. The objective of this research is to design a single-well injection-withdrawal test to estimate residual CO2 trapping (Sgr) in brine aquifers. Due to the high cost associated with drilling to depths of potential CO2 storage site, single-well test can cost-effectively provide data sets to assess reservoir properties and reduce uncertainties in the appraisal phase for finding commercial scale storage sites. The main challenges in the design are the following: (1) It is difficult to quantify the amount that is trapped using a mass balance approach; (2) correlations among various parameters leads to a highly uncertain or non-unique Sgr estimate; and (3) the Sgr estimate could be biased due to heterogeneity of the geological medium. We have proposed our design to address each of these challenges by (1) use a detailed reservoir model to simulate the relevant physical processes in the tests; (2) perform a test sequence that yields multiple types of complementary data to constrain the estimate of Sgr; (3) remove or reduce the bias caused by the heterogeneity of the storage formation by repeating the same test under different saturation conditions. The design will be applied to a practical field test that will be carried out as part of the CO2CRC Otway Project, at Victoria Australia.