Near-surface soil carbon detection for monitoring CO<Subscript>2</Subscript> seepage from a geological reservoir

The promise of the Brookhaven National Laboratory (BNL) Inelastic Neutron Scattering (INS) System was evaluated for use as a long-term, in-field monitor to detect cumulative changes in belowground carbon resulting from the leakage of CO₂ stored in deep geological reservoirs. This system underwent tests at a facility constructed specifically for testing, under controlled conditions, various detection systems for monitoring near-surface transport and accumulations of CO₂ fluxes emanating from a shallow buried, slotted horizontal well. The INS System was assessed by comparing the results from placing it above the horizontal well at a spot with a known high CO₂ leak identified and quantified the previous years, with those obtained from background readings adjacent to the well. At two different “Hot Spots”, a suppression of about 14% in 2008 and about 7% in 2009 in carbon content above the well in comparison to the background signal was observed. An overview of these results is presented.     

Bayesian hierarchical models for soil CO<Subscript>2</Subscript> flux and leak detection at geologic sequestration sites

Proper characterizations of background soil CO₂ respiration rates are critical for interpreting CO₂ leakage monitoring results at geologic sequestration sites. In this paper, a method is developed for determining temperature-dependent critical values of soil CO₂ flux for preliminary leak detection inference. The method is illustrated using surface CO₂ flux measurements obtained from the AmeriFlux network fit with alternative models for the soil CO₂ flux versus soil temperature relationship. The models are fit first to determine pooled parameter estimates across the sites, then using a Bayesian hierarchical method to obtain both global and site-specific parameter estimates. Model comparisons are made using the deviance information criterion (DIC), which considers both goodness of fit and model complexity. The hierarchical models consistently outperform the corresponding pooled models, demonstrating the need for site-specific data and estimates when determining relationships for background soil respiration. A hierarchical model that relates the square root of the CO₂ flux to a quadratic function of soil temperature is found to provide the best fit for the AmeriFlux sites among the models tested. This model also yields effective prediction intervals, consistent with the upper envelope of the flux data across the modeled sites and temperature ranges. Calculation of upper prediction intervals using the proposed method can provide a basis for setting critical values in CO₂ leak detection monitoring at sequestration sites.     

Dynamics of CO<Subscript>2</Subscript> fluxes and concentrations during a shallow subsurface CO<Subscript>2</Subscript> release

A field facility located in Bozeman, Montana provides the opportunity to test methods to detect, locate, and quantify potential CO₂ leakage from geologic storage sites. From 9 July to 7 August 2008, 0.3 t CO₂ day⁻¹ were injected from a 100-m long, ~2.5-m deep horizontal well. Repeated measurements of soil CO₂ fluxes on a grid characterized the spatio-temporal evolution of the surface leakage signal and quantified the surface leakage rate. Infrared CO₂ concentration sensors installed in the soil at 30 cm depth at 0–10 m from the well and at 4 cm above the ground at 0 and 5 m from the well recorded surface breakthrough of CO₂ leakage and migration of CO₂ leakage through the soil. Temporal variations in CO₂ concentrations were correlated with atmospheric and soil temperature, wind speed, atmospheric pressure, rainfall, and CO₂ injection rate.     

The regional pressure impact of CO<Subscript>2</Subscript> storage: a showcase study from the North German Basin

A regional scale, showcase saline aquifer CO₂ storage model from the North German Basin is presented, predicting the regional pressure impact of a small industrial scale CO₂ storage operation on its surroundings. The intention of the model is to bridge the gap between generic and site-specific, studying the role of fluid flow boundary conditions and petrophysical parameters typically found in the North German Basin. The numerical simulation has been carried out using two different numerical simulators, whose results matched well. The most important system parameters proved to be the model’s hydrological boundary conditions, rock compressibility, and permeability. In open boundary aquifers, injection-induced overpressures dissipate back to hydrostatic level within a few years. If a geological flow barrier is present on at least one side of the aquifer, pressure dissipation is seriously retarded. In fully closed compartments, overpressures can never fully dissipate, but equilibrate to a compartment-wide remnant overpressure. At greater distances to the injection well, maximum fluid pressures are in the range of a few bar only, and reached several years to decades after the end of the actual injection period. This is important in terms of long-term safety and monitoring considerations. Regional pressure increase impacts the storage capacities of neighbouring sites within hydraulically connected units. It can be concluded that storage capacities may be seriously over- or underestimated when the focus is on a single individual storage site. It is thus necessary to assess the joint storage capacities and pressure limitations of potential sites within the same hydraulic unit.     

On CO<Subscript>2</Subscript> fluid flow and heat transfer behavior in the subsurface,following leakage from a geologic storage reservoir

Geologic storage of CO₂ is expected to produce plumes of large areal extent, and some leakage may occur along fractures, fault zones, or improperly plugged pre-existing wellbores. A review of physical and chemical processes accompanying leakage suggests a potential for self-enhancement. The numerical simulations presented here confirm this expectation, but reveal self-limiting features as well. It seems unlikely that CO₂ leakage could trigger a high-energy run-away discharge, a so-called “pneumatic eruption,” but present understanding is insufficient to rule out this possibility. The most promising avenue for increasing understanding of CO₂ leakage behavior is the study of natural analogues.     

A comparative review of hydrologic issues involved in geologic storage of CO<Subscript>2</Subscript> and injection disposal of liquid waste

The paper presents a comparison of hydrologic issues and technical approaches used in deep-well injection and disposal of liquid wastes, and those issues and approaches associated with injection and storage of CO₂ in deep brine formations. These comparisons have been discussed in nine areas: injection well integrity; abandoned well problems; buoyancy effects; multiphase flow effects; heterogeneity and flow channeling; multilayer isolation effects; caprock effectiveness and hydromechanics; site characterization and monitoring; effects of CO₂ storage on groundwater resources. There are considerable similarities, as well as significant differences. Scientifically and technically, these two fields can learn much from each other. The discussions presented in this paper should help to focus on the key scientific issues facing deep injection of fluids. A substantial but by no means exhaustive reference list has been provided for further studies into the subject.     

Sealing efficiency analysis for shallow-layer caprocks in CO<Subscript>2</Subscript> geological storage

The CO₂ migrated from deeper to shallower layers may change its phase state from supercritical state to gaseous state (called phase transition). This phase transition makes both viscosity and density of CO₂ experience a sharp variation, which may induce the CO₂ further penetration into shallow layers. This is a critical and dangerous situation for the security of CO₂ geological storage. However, the assessment of caprock sealing efficiency with a fully coupled multi-physical model is still missing on this phase transition effect. This study extends our previous fully coupled multi-physical model to include this phase transition effect. The dramatic changes of CO₂ viscosity and density are incorporated into the model. The impacts of temperature and pressure on caprock sealing efficiency (expressed by CO₂ penetration depth) are then numerically investigated for a caprock layer at the depth of 800 m. The changes of CO₂ physical properties with gas partial pressure and formation temperature in the phase transition zone are explored. It is observed that phase transition revises the linear relationship of CO₂ penetration depth and time square root as well as penetration depth. The real physical properties of CO₂ in the phase transition zone are critical to the safety of CO₂ sequestration. Pressure and temperature have different impact mechanisms on the security of CO₂ geological storage.     

Feasibility of CO<Subscript>2</Subscript> adsorption by solid adsorbents: a review on low-temperature systems

In the last few decades of industrialization, the concentration of CO₂ in the atmosphere had increased rapidly. Different organizations have invested considerable funds in research activities worldwide for CO₂ capture and storage. To date, significant work has been done and various technologies have been proposed for CO₂ capture and storage. Both adsorption and absorption are promising techniques for CO₂ capture, but low-temperature adsorption processes using solid adsorbents are the prevailing technique nowadays. In this review paper, a variety of adsorbents such as carbonaceous materials, dry alkali metal-based sorbents, zeolites, metal–organic frameworks (MOFs) and microporous organic polymers (MOPs) have been studied. Various methods of chemical or physical modification and the effects of supporting materials have been discussed to enhance CO₂ capture capacity of these adsorbents. Low-temperature (<100 °C) adsorption processes for CO₂ capture are critically analyzed and concluded on the basis of information available so far in the literature. All the information in CO₂ adsorption using different routes has been discussed, summarized and thoroughly presented in this review article. The most important comparative study of relatively new material MOFs and MOPs is carried out between the groups and with other sorbent as well.     

Using hyperspectral plant signatures for CO<Subscript>2</Subscript> leak detection during the 2008 ZERT CO<Subscript>2</Subscript> sequestration field experiment in Bozeman,Montana

Hyperspectral plant signatures can be used as a short-term, as well as long-term (100-year timescale) monitoring technique to verify that CO₂ sequestration fields have not been compromised. An influx of CO₂ gas into the soil can stress vegetation, which causes changes in the visible to near-infrared reflectance spectral signature of the vegetation. For 29 days, beginning on July 9, 2008, pure carbon dioxide gas was released through a 100-m long horizontal injection well, at a flow rate of 300 kg day⁻¹. Spectral signatures were recorded almost daily from an unmown patch of plants over the injection with a “FieldSpec Pro” spectrometer by Analytical Spectral Devices, Inc. Measurements were taken both inside and outside of the CO₂ leak zone to normalize observations for other environmental factors affecting the plants. Four to five days after the injection began, stress was observed in the spectral signatures of plants within 1 m of the well. After approximately 10 days, moderate to high amounts of stress were measured out to 2.5 m from the well. This spatial distribution corresponded to areas of high CO₂ flux from the injection. Airborne hyperspectral imagery, acquired by Resonon, Inc. of Bozeman, MT using their hyperspectral camera, also showed the same pattern of plant stress. Spectral signatures of the plants were also compared to the CO₂ concentrations in the soil, which indicated that the lower limit of soil CO₂ needed to stress vegetation is between 4 and 8% by volume.     

Time-lapse crosswell seismic and VSP monitoring of injected CO<Subscript>2</Subscript> in a brine aquifer

Seismic surveys successfully imaged a small scale CO₂ injection (1,600 ton) conducted in a brine aquifer of the Frio Formation near Houston, Texas. These time-lapse borehole seismic surveys, crosswell and vertical seismic profile (VSP), were acquired to monitor the CO₂ distribution using two boreholes (the new injection well and a pre-existing well used for monitoring) which are 30 m apart at a depth of 1,500 m. The crosswell survey provided a high-resolution image of the CO₂ distribution between the wells via tomographic imaging of the P-wave velocity decrease (up to 500 m/s). The simultaneously acquired S-wave tomography showed little change in S-wave velocity, as expected for fluid substitution. A rock physics model was used to estimate CO₂ saturations of 10–20% from the P-wave velocity change. The VSP survey resolved a large (∼70%) change in reflection amplitude for the Frio horizon. This CO₂ induced reflection amplitude change allowed estimation of the CO₂ extent beyond the monitor well and on three azimuths. The VSP result is compared with numerical modeling of CO₂ saturations and is seismically modeled using the velocity change estimated in the crosswell survey.     

Ammonia emission from CO<Subscript>2</Subscript> capture pilot plant using aminoethylethanolamine

Amine post-combustion carbon capture technology is based on washing the flue gas with a solvent that captures CO₂. Thus, a small fraction of this solvent can be released together with the cleaned flue gas. This release may cause environmental concerns, both directly and indirectly through subsequent solvent degradation into other substances in the atmosphere. The paper presents the ammonia emission from CO₂ capture pilot plant (1 tonne CO₂ per day) using 40 wt% aminoethylethanolamine solvent, along with the efficiency of the water wash unit. In addition, the temperature effect of lean amine entering the absorber on ammonia emission was studied. Furthermore, the concentrations of other compounds such as SO₂, SO₃, NO₂, CS₂ and formaldehyde were monitored. The literature review on the NH₃ emission from a pilot plant using aminoethylethanolamine solvent has not been published. The results show that the main source of ammonia emission is the absorber and that emission (in the range 27–50 ppm) corresponds to typical NH₃ release from CO₂ capture pilot plant using an amine solvent. The emission of amines and amine degradation products is a complex phenomenon which is difficult to predict in novel solvents, and for this reason the significance of new solvents testing in a pilot scale has been highlighted.     

Simulation of CO<Subscript>2</Subscript> hydrate formation in cold aquifers: nonequilibrium approach

In this paper, we focus on the geological storage of CO₂ in reservoirs with zones that are cold enough to facilitate CO₂ hydrate formation at local pressures. A 2D hydro-chemical mechanical model which has five layers (three layers with aquifers and two layers with cap rock in which we introduced two fractures) is created. We apply a reactive transport reservoir simulator, RetrasoCodeBright (RCB), in which hydrate is treated as a pseudo mineral. Following the recent modifications to account for hydrate dynamics in the code through a kinetic approach (Kvamme et al., Proceedings of the 7th International Conference on Gas Hydrates (ICGH 2011), 2011b), we have further improved the simulator to implement the nonequilibrium thermodynamic calculations. In the present study, we spot the light on the hydrate formation effects on porosity in different regions, as well as on the flow pattern. These simulations are based on classical relationships between porosity and permeability, but the outline of ongoing modifications is presented as well. A critical question in such systems is whether hydrate formation can contribute to stabilizing the storage, given that hydrates are pore filling and cannot be stable toward mineral surfaces. The implications of hydrate formation on the geo-mechanical properties of the model reservoir are other aspects addressed in this study.     

CO<Subscript>2</Subscript> leakage through an abandoned well: problem-oriented benchmarks

The efficiency and sustainability of carbon dioxide (CO₂) storage in deep geological formations crucially depends on the integrity of the overlying cap-rocks. Existing oil and gas wells, which penetrate the formations, are potential leakage pathways. This problem has been discussed in the literature, and a number of investigations using semi-analytical mathematical approaches have been carried out by other authors to quantify leakage rates. The semi-analytical results are based on a number of simplifying assumptions. Thus, it is of great interest to assess the influence of these assumptions. We use a numerical model to compare the results with those of the semi-analytical model. Then we ease the simplifying restrictions and include more complex thermodynamic processes including sub- and supercritical fluid properties of CO₂ and non-isothermal as well as compositional effects. The aim is to set up problem-oriented benchmark examples that allow a comparison of different modeling approaches to the problem of CO₂ leakage.     

Site characterization for CO<Subscript>2</Subscript> geologic storage and vice versa: the Frio brine pilot,Texas, USA as a case study

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.     

Screening and ranking framework for geologic CO<Subscript>2</Subscript> storage site selection on the basis of health,safety, and environmental risk

A screening and ranking framework (SRF) has been developed to evaluate potential geologic carbon dioxide (CO₂) storage sites on the basis of health, safety, and environmental (HSE) risk arising from CO₂ leakage. The approach is based on the assumption that CO₂ leakage risk is dependent on three basic characteristics of a geologic CO₂ storage site: (1) the potential for primary containment by the target formation; (2) the potential for secondary containment if the primary formation leaks; and (3) the potential for attenuation and dispersion of leaking CO₂ if the primary formation leaks and secondary containment fails. The framework is implemented in a spreadsheet in which users enter numerical scores representing expert opinions or published information along with estimates of uncertainty. Applications to three sites in California demonstrate the approach. Refinements and extensions are possible through the use of more detailed data or model results in place of property proxies.     

Site characterisation of a basin-scale CO<Subscript>2</Subscript> geological storage system: Gippsland Basin,southeast Australia

Geological storage of CO₂ in the offshore Gippsland Basin, Australia, is being investigated by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) as a possible method for storing the very large volumes of CO₂ emissions from the nearby Latrobe Valley area. A storage capacity of about 50 million tonnes of CO₂ per annum for a 40-year injection period is required, which will necessitate several individual storage sites to be used both sequentially and simultaneously, but timed such that existing hydrocarbon assets will not be compromised. Detailed characterisation focussed on the Kingfish Field area as the first site to be potentially used, in the anticipation that this oil field will be depleted within the period 2015–2025. The potential injection targets are the interbedded sandstones of the Paleocene-Eocene upper Latrobe Group, regionally sealed by the Lakes Entrance Formation. The research identified several features to the offshore Gippsland Basin that make it particularly favourable for CO₂ storage. These include: a complex stratigraphic architecture that provides baffles which slow vertical migration and increase residual gas trapping and dissolution; non-reactive reservoir units that have high injectivity; a thin, suitably reactive, lower permeability marginal reservoir just below the regional seal providing mineral trapping; several depleted oil fields that provide storage capacity coupled with a transient production-induced flow regime that enhances containment; and long migration pathways beneath a competent regional seal. This study has shown that the Gippsland Basin has sufficient capacity to store very large volumes of CO₂. It may provide a solution to the problem of substantially reducing greenhouse gas emissions from future coal developments in the Latrobe Valley.