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A baseline 3D VSP survey at the Aquistore CO2 storage site in Saskatchewan served as a technology test for distributed acoustic sensing (DAS). DAS data was acquired as a vertical seismic profile (VSP) on two codeployed fibers, one single-mode (SM) and one multi-mode (MM), simultaneously with a 60-level 3-component wireline geophone array. A 2D grid of explosive shots, used for baseline 4D surface seismic, provided 3D-VSP data from all sensors, while vibroseis sources were used for a single 2D VSP line. The DAS fibers were cemented in place on the outside of the well casing during the original well completion and extend to a depth of ~2.8 km. Initial results indicate good quality data was acquired by all systems with comparable SM and MM results. While DAS recording is itself relatively novel, the use of MM fiber for DAS in any field acquisition is quite new. MM fiber DAS is significant because of the large number of borehole MM fibers deployed for distributed temperature sensing (DTS), implying the potential ability to utilize these existing MM deployments for seismic monitoring and imaging.

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.

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

Distributed acoustic sensing (DAS) is a relatively recent development in the use of fiber-optic cable for measurement of ground motion. Discrete fiber-optic sensors, typically using a Bragg diffraction grating, have been in research and development and field testing for more than 15 years with geophysical applications at least 12 years old (Bostick, 2000, and summary in Keul et al., 2005). However, developments in recent years have sought to remove the need for point sensors by using the fiber cable itself as a sensor (Mestayer et al., 2011; Miller et al., 2012).

[1] At Cranfield, Mississippi, United States, a large-scale carbon dioxide (CO2) injection through an injection well (∼3,080 m deep) was continuously monitored using U-tube samplers in two observation wells located 68 and 112 m east of the injector. The Lower Tuscaloosa Formation injection zone, which consists of amalgamated fluvial point-bar and channel-fill deposits, presents an interesting environment for studying fluid flow in heterogeneous formations. Continual fluid sampling was carried out during the first month of CO2 injection. Two subsequent tracer tests using sulfur hexafluoride (SF6) and krypton were conducted at different injection rates to measure flow velocity change. The field observations showed significant heterogeneity of fluid flow and for the first time clearly demonstrated that fluid flow evolved with time and injection rate. It was found the wells were connected through numerous, separate flow pathways. CO2 flowed through an increasing fraction of the reservoir and sweep efficiency improved with time. The field study also first documented in situ component exchange between brine and gas phases during CO2 injection. It was found that CH4 degassed from brine and is enriched along the gas–water contact. Multiple injectate flow fronts with high CH4 concentration arrived at different times and led to gas composition fluctuations in the observation wells. The findings provide valuable insights into heterogeneous multiphase flow in rock formations and show that conventional geological models and static fluid flow simulations are unable to fully describe the heterogeneous and dynamic flow during fluid injection.

Little is known about hydrogeochemical conditions beneath thick permafrost, particularly in fractured crystalline rock, due to difficulty in accessing this environment. The purpose of this investigation was to develop methods to obtain physical, chemical, and microbial information about the subpermafrost environment from a surface-drilled borehole. Using a U-tube, gas and water samples were collected, along with temperature, pressure, and hydraulic conductivity measurements, 420 m below ground surface, within a 535 m long, angled borehole at High Lake, Nunavut, Canada, in an area with 460-m-thick permafrost. Piezometric head was well above the base of the permafrost, near land surface. Initial water samples were contaminated with drill fluid, with later samples

Monitoring of geological carbon sequestration (GCS) sites will primarily depend upon the tools and technology developed over many decades in support of the oil and gas industries for ensuring the safe injection and storage of CO2 in the subsurface. For more than thirty years CO2 has been compressed and transported in pipelines for injection as part of enhanced oil recovery projects. However, the aims of CO2 injection for carbon sequestration have significant differences from EOR injections, where the motivation is enhanced production. While the regulatory environment that will govern CO2 storage in the subsurface is still evolving, operators of GCS sites will need to demonstrate protection of drinking water resources, accountability of the volume injection and permanence for the CO2 emplaced. The US Department of Energy has coined the acronym MVA to describe the requirement to monitor the movement of CO2 into, through, and out of the targeted geologic storage area, verify the location of CO2 that has been placed in geologic storage, and account for the CO2 that has been transported to a geologic storage site. To accomplish this, advanced well-based technologies will be needed to meet regulatory and technical requirements. Recent demonstration projects have incorporated permanently emplaced sensors including pressure, distributed fiber-optic, temperature, seismic, electrical resistivity, and geochemical sampling to name a few. These are often installed so that they are compatible with periodic wireline operations. In this paper we will examine integrated well-based monitoring programs that were part of CO2 storage demonstration programs and will discuss requirements for future commercial installations.

We have developed a borehole methodology to estimate formation thermal conductivity in situ with a spatial resolution of one meter. In parallel with a fiber-optic distributed temperature sensor (DTS), a resistance heater is deployed to create a controlled thermal perturbation. The transient thermal data is inverted to estimate the formation's thermal conductivity. We refer to this instrumentation as a Distributed Thermal Perturbation Sensor (DTPS), given the distributed nature of the DTS measurement technology. The DTPS was deployed in permafrost at the High Lake Project Site (67 degrees 22 minutes N, 110 degrees 50 minutes W), Nunavut, Canada. Based on DTPS data, a thermal conductivity profile was estimated along the length of a wellbore. Using the thermal conductivity profile, the baseline geothermal profile was then inverted to estimate a ground surface temperature history (GSTH) for the High Lake region. The GSTH exhibits a 100-year long warming trend, with a present-day ground surface temperature increase of 3.0 {+-} 0.8 C over the long-term average.

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.

LBNL's GEOSEQ project is a key participant in the Frio IIbrine pilot studying geologic sequestration of CO2. During During theinjection phase of the Frio-II brine pilot, LBNL collected multiple datasets including seismic monitoring, hydrologic monitoring and geochemicalsampling. These data sets are summarized in this report including allCASSM (continuous active source seismic monitoring) travel time data,injection pressure and flow rate data and gaseous sampling and tracerdata. Additional results from aqueous chemistry analysis performed by theU. S. Geological Survey (USGS) are summarized. Post injectionmodification of the flow model for Frio II is shown. Thesemodificationsare intended to facilitate integration with the monitoring data andincorporation of model heterogeneity. Current activities of LBNL's GEOSEQproject related to the Frio II test are shown, including development of anew petrophysical model for improved interpretation of seismic monitoringdata and integration of this data with flow modeling.

This report summarizes fluid electrical conductivity (FEC) and thermal logging data collected in Borehole NC-EWDP-24PB, located approximately 15 km south of the proposed repository at Yucca Mountain. Preliminary analyses of a small fraction of the FEC and temperature data indicate that relatively large, localized fluid fluxes are likely to exist at this location. The implication that considerable flow is induced by small gradients, and that flow is highly localized, is significant for the estimation of groundwater transport velocities and radionuclide travel times. The sensitivity of the data to potential perturbations during testing (i.e., internal wellbore flow in the case of FEC data, and buoyancy effects in the case of thermal logging data) make it difficult to conclusively derive fluid fluxes and transport velocities without a detailed analysis of all data and processes involved. Such a comprehensive analysis has not yet been performed. However, the preliminary results suggest that the ambient component of the estimated flow rates is significant and on the order of liters per minute, yielding groundwater transport velocities in the range of kilometers per year. One particular zone in the Bullfrog tuff exhibits estimated velocities on the order of 10 km/yr. Given that the preliminary estimates of ambient flow rates and transport velocities are relatively high, and considering the potential impact of high rates and velocities on saturated-zone flow and transport behavior, we recommend that a comprehensive analysis of all the available data be performed. Moreover, additional data sets at other locations should be collected to examine whether the current data set is representative of the regional flow system near Yucca Mountain.

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.

We have carried out numerical simulations of three-dimensional non-isothermal flow around an in situ heat-based flow sensor to investigate how formation heterogeneities can affect the interpretation of ground water flow velocities from this instrument. The flow sensor operates by constant heating of a 0.75 m long, 5 cm diameter cylindrical probe, which contains 30 thermistors in contact with the formation. The temperature evolution at each thermistor can be inverted to obtain an estimate of the ground water flow velocity vector using the standard interpretive method, which assumes that the formation is homogeneous. Analysis of data from heat-based flow sensors installed in a sand aquifer at the Former Fort Ord Army Base near Monterey, California suggested an unexpected component of downward flow. The magnitudes of the vertical velocities were expected to be much less than the horizontal velocities at this site because the sensors were installed just above a clay aquitard. Numerical simulations were conducted to examine how differences in thermal conductivities may lead to spurious indications of vertical flow velocities. We found that a decrease in the thermal conductivity near the bottom of the sensor can perturb the temperature profiles along the instrument in such a manner that analyses assuming homogeneous thermal conductivity could indicate a vertical flow component even though flow is actually horizontal. This work demonstrates how modeling can be used to simulate instrument response to formation heterogeneity, and shows that caution must be used in interpreting data from such devices using overly simplistic assumptions.

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.

A novel system has been deployed to obtain geochemical samples of water and gas, at in situ pressure, during a geologic CO2 sequestration experiment conducted in the Frio brine aquifer in Liberty County, Texas. Project goals required high-frequency recovery of representative and uncontaminated aliquots of a rapidly changing two-phase (supercritical CO2-brine) fluid from 1.5 km depth. The datasets collected, using both the liquid and gas portions of the downhole samples, provide insights into the coupled hydro-geochemical issues affecting CO2 sequestration in brine-filled formations. While the basic premise underlying the U-Tube sampler is not new, the system is unique because careful consideration was given to the processing of the recovered two-phase fluids. In particular, strain gauges mounted beneath the high-pressure surface sample cylinders measured the ratio of recovered brine to supercritical CO2. A quadrupole mass spectrometer provided real-time gas analysis for perfluorocarbon and noble gas tracers that were injected along with the CO2. The U-Tube successfully acquired frequent samples, facilitating accurate delineation of the arrival of the CO2 plume, and on-site analysis revealed rapid changes in geochemical conditions.

A field investigation of unsaturated flow through a lithophysal unit of fractured welded tuff containing lithophysal cavities has been initiated. To characterize flow in this spatially heterogeneous medium, a systematic approach has been developed to perform tests in boreholes drilled at regular intervals in an underground tunnel (drift). The purpose of the testing is to quantify the amounts of water seeping into the drift versus the amount of water moving around the drift when released into boreholes at many equidistant locations along the drift. In this paper, we describe the test equipment system that has been built for this purpose. Because the field-scale measurements--of liquid flow in the unsaturated, fractured rocks--require continuous testing for periods of days to weeks, the control of test equipment has been fully automated, allowing operation with no human presence at the field site. Preliminary results from the first set of tests indicate that, while the effects of evaporation on characterization of hydrological properties of the rock can be significant, these effects can be controlled and quantified. These tests give insight into the role of the cavities as potential storage during the initial transient flow prior to the breakthrough of water at the drift crown, as well as the role of connected fractures that provide the subsequent quasi-steady flow. In addition to the stated purpose of realizing the flow partitioning, the results yield values for the effective porosity in the pathways for liquid flow in the regions tested thus far.

An x-ray scanner was designed and fabricated at Lawrence Berkeley National Laboratory to provide high speed acquisition of x-ray images of sediment cores collected on the Ocean Drilling Program (ODP) Leg 204: Drilling Gas Hydrates On Hydrate Ridge, Cascadia Continental Margin. This report discusses the design and fabrication of the instrument, detailing novel features that help reduce the weight and increase the portability of the instrument. Sample x-ray images are included. The x-ray scanner was transferred to scientific drilling vessel, the JOIDES Resolution, by the resupply ship Mauna Loa, out of Coos Bay, Oregon on July 25. ODP technicians were trained in the instruments operation. The availability of the x-ray scanner at the drilling site allows real-time imaging of cores containing methane hydrate immediately after retrieval. Thus, imaging experiments on cores can yield information on the distribution and quantity of methane hydrates. Performing these measurements at the location of core collection eliminates the need for high pressures or low temperature core handling while the cores are stored and transported to a remote imaging laboratory.

Deposits of naturally occurring methane hydrate have been identified in permafrost and deep oceanic environments with global reserves estimated to be twice the total amount of energy stored in fossil fuels. The fundamental behavior of methane hydrate in natural formations, while poorly understood, is of critical importance if the economic recovery of methane from hydrates is to be accomplished. In this study, computed X-ray tomography (CT) scanning is used to image an advancing dissociation front in a heterogeneous gas hydrate/sand sample at 0.1 MPa. The cylindrical methane hydrate and sand aggregate, 2.54 cm in diameter and 6.3 cm long, was contained in a PVC sample holder that was insulated on all but one end. At the uninsulated end, the dissociated gas was captured and the volume of gas monitored. The sample was initially imaged axially using X-ray CT scanning within the methane hydrate stability zone by keeping the sample temperature at 77°K. Subsequently, as the sample warmed through the methane hydrate dissociation point at 194°K and room pressure, gas was produced and the temperature at the bottom of the sample plug was monitored while CT images were acquired. The experiment showed that CT imaging can resolve the reduction in density (as seen by a reduction in beam attenuation) of the hydrate/sand aggregate due to the dissociation of methane hydrate. In addition, a comparison of CT images with gas flow and temperature measurements reveals that the CT scanner is able to resolve accurately and spatially the advancing dissociation front. Future experiments designed to better understand the thermodynamics of hydrate dissociation are planned to take advantage of the temporal and spatial resolution that the CT scanner provides.

LBNL-39525 UC-000 E R N E S T O R L A N D O LAWRENCE B E R K E L E Y NATIONAL LABORATORY Vadose Zone Monitoring System Installation Report for McClellan AFB P. Zawislanski, B. Faybishenko, A. James, B. Freifeld, and R. Salve Earth Sciences Division October 1996 !4M U ua« Q ST i

Various geophysical and hydrologic tests were conducted in a cluster of nine wells to image the hydrologic connections of a fractured rock mass. Results of intra-borehole flow surveys and cross-hole radar and seismic tomography surveys correlated very well, and indicated that there is a major feature at a depth of 30m. Systematic injection tests were conducted in all nine wells. Three to four intervals in each well were isolated using pneumatic packers. Each interval was equipped with a high resolution pressure transducer. Some 130 injection tests were conducted, and more than 4,100 cross-hole transient pressure measurements were obtained. A computer algorithm was developed to analyze such massive interference data systematically. As a result of the analysis, an image of the fracture connections emerged which is consistent with the geophysical data.

The CO2CRC Otway Project is an Australian-first, demonstration-scale CO2 geosequestration experiment. It incorporates a wide-ranging monitoring and verification operation, including the injection of chemical tracers and the geochemical characterisation of the subsurface fluids sampled from the Naylor—1 monitoring well multi-zone U-tube system. Following the successful collection of baseline gas and fluid samples, injection began in April 2008 and by September 2008 over 20,000 tonnes of the projected total of ∼100,000 tonnes of supercritical CO2 has been injected into the depleted Waarre C unit of the Naylor gas reservoir in the Otway Basin. Critical operational issues revolved around the timing of the chemical tracer injection at the CRC—1 injection well and the on-going maintenance and modifications to the U-tube sampling assembly. The latter resulted from two things:a hazard and operability study (HAZOP), which specifically addressed the continued integrity of the U-tube assembly and the safe collection and disposal of pressurised gases and formation waters, and the need for an innovative solution to mitigate against hydrocarbon wax precipitaton inside the U-tubes that would have jeopardise retrieval of sub-surface samples. A solvent delivery and retrieval system involving Solvesso—100TM was deployed following a mini-HAZOP. Breakthrough was initially confirmed by tracer detection at Naylor—1 approximately four months after injection began, whereas changes in the inorganic geochemical signatures were observed a few weeks later. This has validated the sub-surface monitoring strategy and resulted in refinements to fluid flow models and expanded our understanding of geochemical processes. Furthermore, supercritical CO2 injection has resulted in the lowering of the gas-water contact at Naylor—1 and the progressive gassing out of the deeper U-tubes. Weekly to fortnightly U-tube sampling will continue until supercritical CO2 is established at Naylor—1 following which the frequency of sampling will be reviewed for the rest of the injection period.

Sampling of fluids in deep boreholes is challenging becauseof the necessity to minimize external contamination and maintain sampleintegrity during recovery. The U-tube sampling methodology was developedto collect large volume, multiphase samples at in situ pressures. As apermanent or semi-permanent installation, the U-tube can be used forrapidly acquiring multiple samples or it may be installed for long-termmonitoring applications. The U-tube was first deployed in Liberty County,TX to monitor crosswell CO2 injection as part of the Frio CO2sequestration experiment. Analysis of gases (dissolved or separate phase)was performed in the field using a quadrupole mass spectrometer, whichserved as the basis for determining the arrival of the CO2 plume. Thepresence of oxygen and argon in elevated concentrations, along withreduced methane concentration, indicate sample alteration caused by theintroduction of surface fluids during borehole completion. Despiteproducing the well to eliminate non-native fluids, measurementsdemonstrate that contamination persists until the immiscible CO2injection swept formation fluid into the observationwellbore.

To investigate the potential for the geologic storage of CO2 in saline sedimentary aquifers, 1600 t of CO2 were injected at 1500 m depth into a 24-m-thick sandstone section of the Frio Formation, a regional brine and oil reservoir in the U.S. Gulf Coast. Fluid samples obtained from the injection and observation wells before CO2 injection showed a Na-CaCl‐type brine with 93,000 mg/L total dissolved solids (TDS) at near saturation with CH4 at reservoir conditions. Following CO2 breakthrough, samples showed sharp drops in pH (6.5‐5.7), pronounced increases in alkalinity (100‐3000 mg/L as HCO3) and Fe (30‐1100 mg/L), and significant shifts in the isotopic compositions of H2O, dissolved inorganic carbon (DIC), and CH4. Geochemical modeling indicates that brine pH would have dropped lower but for the buffering by dissolution of carbonate and iron oxyhydroxides. This rapid dissolution of carbonate and other minerals could ultimately create pathways in the rock seals or well cements for CO2 and brine leakage. Dissolution of minerals, especially iron oxyhydroxides, could mobilize toxic trace metals and, where residual oil or suitable organics are present, the injected CO2 could also mobilize toxic organic compounds. Environmental impacts could be major if large brine volumes with mobilized toxic metals and organics migrated into potable groundwater. The d 18 O values for brine and CO2 samples indicate that supercritical CO2 comprises ;50% of pore-fluid volume ;6 mo after the end of injection. Postinjection sampling, coupled with geochemical modeling, indicates that the brine gradually will return to its preinjection composition.

Residual CO 2 trapping (Sgr-CO 2 ) is a key mechanism for geological CO 2 storage. The CO2CRC undertook a sequence of field tests with the aim of comparing different ways of determining Sgr-CO 2 including a dissolution test. Dissolution test results show an unexpectedly early breakthrough and low maximum CO 2 concentrations in the back- produced water making the data inconclusive when using traditional data interpretation. Here, we consider two conditions to explain the observations: Firstly, residual CO 2 is vertically unevenly distributed and, secondly, the fluid and residual CO 2 are not in equilibrium. Furthermore, we postulate localised flow channels have formed during the 3- month test period caused by advective flow of CO 2 -saturated, low pH water leading to transport-controlled mineral dissolution.

The first stage of the CO2CRC Otway Project, located in south-eastern Australia, has stored 65,445 tonnes of CO 2 -rich gas in the depleted Naylor Gas Field. Comparisons have been made between simulations using the non-isothermal multi-phase flow simulator TOUGH2/EOS7C and the accumulated field data up to and beyond the end of injection. The geological models and the derived simulation models have been able to fit most of the key features of the field data, including the downhole pressure measurements and the arrival time at the observation well. When fitting to the downhole pressure only, the observed arrival time was in the range of uncertainty of the model predictions. The use of multiple geostatistical realisations of heterogeneity demonstrates the importance of capturing the range of uncertainty in the geology and the consequent scatter in forward predictions. Thus the storage of CO 2 in the Naylor depleted gas field is shown to be adequately modelled by numerical simulation, and this increases confidence in the suitability of similar depleted gas fields for underground storage.

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.

Summary We have deployed a novel permanent monitoring system at the Australian CO2CRC Otway Site that includes a surface and borehole distributed acoustic sensing (DAS) network with orbital vibrator (rotary) surface seismic sources. DAS is an emerging technology for performing seismic acquisition based on optical interferometric techniques, which allows for data collection with a wide spatial aperture and high temporal resolution using commercially available telecommunications fibres. DAS sensitivity currently lags behind conventional discrete geophone and hydrophone sensor technologies. Our implementation of surface rotary seismic sources is based on open-loop controlled asynchronous motors. This avoids the complexity of feedback loops for phase control, instead using deconvolution of the source function as measured by a shallow source-monitor sensor. Initial data analysis shows that the amount of energy available from long source sweeps overcomes limitations in DAS sensitivity. The combination of relatively inexpensive but powerful permanent surface sources with permanent DAS deployment in an areal array provides a new paradigm for time-lapse seismic monitoring. The methodology we describe has broad applicability for long-term reservoir surveillance, with time-lapse change sensitive to many subsurface properties.

CO2CRC Otway project was the first Australian of CO2 geosequestration project. The project site is located 240 km away from Melbourne, Victoria. During the Stage 1 of this project ~66 thousand tons of supercritical CO2/CH4 gas mixture was injected into a depleted gas reservoir at approximately 2 km depth in 2008-2010 to prove that gas can be safely transported and stored in a geological formation. The ongoing Stage 2C of the project is focusing seismic monitoring capabilities and, also, on proving that the injected gas plume plume will stabilize over the period of time. A very limited amount of the same gas mixture (15 000 tonnes) was injected into a saline aquifer at ~1500 m. In order to monitor the gas injection a comprehensive 4D seismic program was rolled out. In this presentation we outline the monitoring program and show the time-lapse seismic results obtained after the first four monitor surveys, acquired at 5 000 t, 10 000 t, 15 000 t of the injection and, also, 9 months after completion of the injection.

Reservoir monitoring usually involves a combination of seismic surveys acquired using a large array of seismic receivers and mobile sources to image the subsurface changes. Such surveys rely on accurate positioning of both source points and receivers. Permanent reservoir monitoring seeks to overcome the limitations of the conventional approach, such as poor repitability and high survey costs, by fixing either the seismic receivers, sources or both. At the CO2CRC Otway Research Facility, we are exploring the use of distributed acoustic sensing (DAS) combined with permanent surface orbital vibrators (SOVs) to acquire high quality time-lapse seismic data at relatively low cost, while significantly reducing the land access issues. To study the feasibility of using such monitoring method, we present the analysis of a series of Vertical Seismic Profile (VSP) acquisitions acquired with a cemented fibre-optic cable. We test different SOV sweep designs, and evaluate DAS ability to record the acoustic signal. The results show that the DAS/SOV configuration was able to deliver high quality VSP datasets, sufficient to image the target interval.

A constant head permeameter system has been developed for use in small-diameter boreholes with any orientation. It is based upon the original Guelph permeameter concept of using a Mariotte siphon reservoir to control the applied head. The new tool, called a Restricted Interval Guelph (RIG) permeameter uses either a single pneumatic packer or straddle packer to restrict the area through which water is allowed to flow so that the borehole wetted area is independent of the applied head. The RIG permeameter has been used at Yucca Mountain, Nevada, in the nonwelded rhyolitic Paintbrush Tuff. Analysis of the acquired data is based upon saturated-unsaturated flow theory that relies upon the quasi-linear approximation to estimate field-saturated hydraulic conductivity (K fs) and the α parameter (sorptive number) of the exponential relative hydraulic conductivity–pressure head relationship. These results are compared with a numerical model based upon the solution of the Richards equation using a van Genuchten capillary pressure-saturation formulation. The numerical model incorporates laboratory capillary pressure versus saturation functions measured from cores taken from nearby boreholes. Comparison between the analytical and numerical approaches shows that the simple analytic model is valid for analyzing the data collected. Sensitivity analysis performed with the numerical model shows that the RIG permeameter is an effective tool for estimating permeability and sorptive number for the nonwelded Paintbrush Tuff.