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.     

An integrative approach to robust design and probabilistic risk assessment for CO<Subscript>2</Subscript> storage in geological formations

CO₂ storage in geological formations is currently being discussed intensively as a technology with a high potential for mitigating CO₂ emissions. However, any large-scale application requires a thorough analysis of the potential risks. Current numerical simulation models are too expensive for probabilistic risk analysis or stochastic approaches based on a brute-force approach of repeated simulation. Even single deterministic simulations may require parallel high-performance computing. The multiphase flow processes involved are too non-linear for quasi-linear error propagation and other simplified stochastic tools. As an alternative approach, we propose a massive stochastic model reduction based on the probabilistic collocation method. The model response is projected onto a higher-order orthogonal basis of polynomials to approximate dependence on uncertain parameters (porosity, permeability, etc.) and design parameters (injection rate, depth, etc.). This allows for a non-linear propagation of model uncertainty affecting the predicted risk, ensures fast computation, and provides a powerful tool for combining design variables and uncertain variables into one approach based on an integrative response surface. Thus, the design task of finding optimal injection regimes explicitly includes uncertainty, which leads to robust designs with a minimum failure probability. We validate our proposed stochastic approach by Monte Carlo simulation using a common 3D benchmark problem (Class et al., Comput Geosci 13:451–467, 2009). A reasonable compromise between computational efforts and precision was reached already with second-order polynomials. In our case study, the proposed approach yields a significant computational speed-up by a factor of 100 compared with the Monte Carlo evaluation. We demonstrate that, due to the non-linearity of the flow and transport processes during CO₂ injection, including uncertainty in the analysis leads to a systematic and significant shift of the predicted leakage rates toward higher values compared with deterministic simulations, affecting both risk estimates and the design of injection scenarios.     

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.     

Feasibility of CO<Subscript>2</Subscript> migration detection using pressure and CO<Subscript>2</Subscript> saturation monitoring above an imperfect primary seal of a geologic CO<Subscript>2</Subscript> storage formation: a numerical investigation

A numerical model was developed to investigate the potential to detect fluid migration in a (homogeneous, isotropic, with constant pressure lateral boundaries) porous and permeable interval overlying an imperfect primary seal of a geologic CO₂ storage formation. The seal imperfection was modeled as a single higher-permeability zone in an otherwise low-permeability seal, with the center of that zone offset from the CO₂ injection well by 1400 m. Pressure response resulting from fluid migration through the high-permeability zone was detectable up to 1650 m from the centroid of that zone at the base of the monitored interval after 30 years of CO₂ injection (detection limit = 0.1 MPa pressure increase); no pressure response was detectable at the top of the monitored interval at the same point in time. CO₂ saturation response could be up to 774 m from the center of the high-permeability zone at the bottom of the monitored interval, and 1103 m at the top (saturation detection limit = 0.01). More than 6% of the injected CO₂, by mass, migrated out of primary containment after 130 years of site performance (including 30 years of active injection) in the case where the zone of seal imperfection had a moderately high permeability (10^??17 m² or 0.01 mD). Free-phase CO₂ saturation monitoring at the top of the overlying interval provides favorable spatial coverage for detecting fluid migration across the primary seal. Improved sensitivity of detection for pressure perturbation will benefit time of detection above an imperfect seal.     

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.     

Potential risks to freshwater resources as a result of leakage from CO<Subscript>2</Subscript> geological storage: a batch-reaction experiment

In assessing the feasibility of widespread deployment of CO₂ geological storage, it is prudent to first assess potential consequences of an error or accident that could lead to CO₂ leakage into groundwater resources above a sequestration interval. Information about the sensitivity of the groundwater system to introduction of CO₂ is needed in order to design groundwater monitoring program. A laboratory-batch experiment was conducted to explore the range of CO₂ impact on groundwater quality of a spectrum of representative aquifers, in the Gulf Coast region, USA. Results show that CO₂ elevated concentrations of many cations within hours or days. Two types of cations were recognized according to their concentration trends. Type I cations—Ca, Mg, Si, K, Sr, Mn, Ba, Co, B, Zn—rapidly increased following initial CO₂ flux and reached stable concentrations before the end of the experiment. Type II cations—Fe, Al, Mo, U, V, As, Cr, Cs, Rb, Ni and Cu—increased at the start of CO₂ flux, but declined, in most cases, to levels lower than pre-CO₂ concentrations. Dissolution of dolomite and calcite caused the largest increase in concentrations for Ca, Mg, Mn, Ba and Sr. Cation release rates decreased linearly as pH increased during mineral buffering. Experiment results suggest that carbonate minerals are the dominant contributor of changes in groundwater quality. Risk assessments of potential degradation of groundwater and monitoring strategies should focus on these fast-reacting minerals. Mobilization risk of Type II cations, however, may be self-mitigated because adsorption occurs when pH rebounds.     

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.     

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.     

Seal integrity and feasibility of CO<Subscript>2</Subscript> sequestration in the Teapot Dome EOR pilot: geomechanical site characterization

This paper reports a preliminary investigation of CO₂ sequestration and seal integrity at Teapot Dome oil field, Wyoming, USA, with the objective of predicting the potential risk of CO₂ leakage along reservoir-bounding faults. CO₂ injection into reservoirs creates anomalously high pore pressure at the top of the reservoir that could potentially hydraulically fracture the caprock or trigger slip on reservoir-bounding faults. The Tensleep Formation, a Pennsylvanian age eolian sandstone is evaluated as the target horizon for a pilot CO₂ EOR-carbon storage experiment, in a three-way closure trap against a bounding fault, termed the S1 fault. A preliminary geomechanical model of the Tensleep Formation has been developed to evaluate the potential for CO₂ injection inducing slip on the S1 fault and thus threatening seal integrity. Uncertainties in the stress tensor and fault geometry have been incorporated into the analysis using Monte Carlo simulation. The authors find that even the most pessimistic risk scenario would require ∼10 MPa of excess pressure to cause the S1 fault to reactivate and provide a potential leakage pathway. This would correspond to a CO₂ column height of ∼1,500 m, whereas the structural closure of the Tensleep Formation in the pilot injection area does not exceed 100 m. It is therefore apparent that CO₂ injection is not likely to compromise the S1 fault stability. Better constraint of the least principal stress is needed to establish a more reliable estimate of the maximum reservoir pressure required to hydrofracture the caprock.     

Analytical model for screening potential CO<Subscript>2</Subscript> repositories

Assessing potential repositories for geologic sequestration of carbon dioxide using numerical models can be complicated, costly, and time-consuming, especially when faced with the challenge of selecting a repository from a multitude of potential repositories. This paper presents a set of simple analytical equations (model), based on the work of previous researchers, that could be used to evaluate the suitability of candidate repositories for subsurface sequestration of carbon dioxide. We considered the injection of carbon dioxide at a constant rate into a confined saline aquifer via a fully perforated vertical injection well. The validity of the analytical model was assessed via comparison with the TOUGH2 numerical model. The metrics used in comparing the two models include (1) spatial variations in formation pressure and (2) vertically integrated brine saturation profile. The analytical model and TOUGH2 show excellent agreement in their results when similar input conditions and assumptions are applied in both. The analytical model neglects capillary pressure and the pressure dependence of fluid properties. However, simulations in TOUGH2 indicate that little error is introduced by these simplifications. Sensitivity studies indicate that the agreement between the analytical model and TOUGH2 depends strongly on (1) the residual brine saturation, (2) the difference in density between carbon dioxide and resident brine (buoyancy), and (3) the relationship between relative permeability and brine saturation. The results achieved suggest that the analytical model is valid when the relationship between relative permeability and brine saturation is linear or quasi-linear and when the irreducible saturation of brine is zero or very small.     

Carbonate cements in Miller field of the UK North Sea: a natural analog for mineral trapping in CO<Subscript>2</Subscript> geological storage

Miller field of the North Sea has had high concentrations of natural CO₂ for ~70 Ma. It is an ideal analog for the long-term fate of CO₂ during engineered storage, particularly for formation of carbonate minerals that permanently lock up CO₂ in solid form. The Brae Formation reservoir sandstone contains an unusually high quantity of calcite concretions; however, C and O stable isotopic signatures suggest that these are not related to the present-day CO₂ charge. Margins of the concretions are corroded, probably because of reduced pH due to CO₂ influx. Dispersed calcite cements are also present, some of which postdate the CO₂ charge and, therefore, are the products of mineral trapping. It is calculated that only a minority of the reservoired CO₂ in Miller (6–24%) has been sequestrated in carbonates, even after 70 Ma of CO₂ emplacement. Most of the CO₂ accumulation is dissolved in pore fluids. Therefore, in a reservoir similar to the Brae Formation, engineered CO₂ storage must rely on physical retention mechanisms because mineral trapping is both incomplete and slow.     

Capturing and storage of CO<Subscript>2</Subscript> by micron-nano minerals: Evidence from the nature

The increase of CO2 in atmosphere is a main factor leading to "greenhouse effect", which causes more and more serious global environmental problems. The reduction of CO2 is a challenge for the survival of human beings, and it is also a big technical problem. CO2 fluid-rock interaction is a key scientific problem involved in geo-logical storage. The CO2 fluid-rock interaction has a variety of multi-scale changes. Due to great differences in the quantity of surface atoms and surface energy between micron-nano-sized minerals, and ions and crystals, the speed and efficiency of CO2 fluid-rock interaction on a micron-nano scale are much higher than those on other scales. As is known from the natural world, the micron-nano structures of pores and the surface chemical modification of natural porous minerals (zeolite, diatomite, sepiolite, palygorskite, halloysite, etc.) should be further investigated, which can be used as the micron-nano -mineral porous materials with high capacity and high efficiency for capturing CO2. Through simulating the adsorption capacity and process of CO2 by minerals in the natural world, the micron-nano technology is applied to calcium- and magnesium-based minerals (olivine, pyroxene, feldspar, clay, etc.) so as to improve the activity of calcium and magnesium and enlarge the reaction contact area. In this way, the efficiency of capturing and storage of CO2 by calcium- and magnesium-based minerals can be greatly improved. These minerals can also be used as the micron-nano-mineral materials with large capacity and high efficiency for capturing and storing CO2.     

Pressure transient technique to constrain CO<Subscript>2</Subscript> plume boundaries

Carbon dioxide (CO₂) has been injected in the subsurface permeable formations as a means to cut atmospheric CO₂ emissions and/or enhance oil recovery (EOR). It is important to constrain the boundaries of the CO₂ plume in the target formation and/or other formations hosting the CO₂ migrated from the target formation. Monitoring methods and technologies to assess the CO₂ plume boundaries over time within a reservoir of interest are required. Previously introduced methods and technologies on pressure monitoring to detect the extent of the CO₂ plume require at least two wells, i.e. pulser and observation wells. We introduce pressure transient technique requiring single well only. Single well pressure transient testing (drawdown/buildup/injection/falloff) is widely used to determine reservoir properties and wellbore conditions. Pressure diagnostic plots are used to identify different flow regimes and determine the reservoir/well characteristics. We propose a method to determine the plume extent for a constant rate pressure transient test at a single well outside the CO₂ plume. Due to the significant contrast between mobility and storativity of the CO₂ and native fluids (oil or brine), the CO₂ boundary causes deviation in the pressure diagnostic response from that corresponding to previously identified heterogeneities. Using the superposition principle, we develop a relationship between the deviation time and the plume boundary. We demonstrate the applicability of the proposed method using numerically generated synthetic data corresponding to homogeneous, heterogeneous, and anisotropic cases to evaluate its potential and limitations. We discuss ways to identify and overcome the potential limitations for application of the method in the field.     

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.     

Screening and ranking of sedimentary basins for sequestration of CO<Subscript>2</Subscript> in geological media in response to climate change

Sedimentary basins are suitable to different degrees for CO ₂ geological sequestration as a result of various intrinsic and extrinsic characteristics, of which the geothermal regime is one of the most important. Warm basins are less favorable for CO ₂ sequestration than cold basins because of reduced capacity in terms of CO ₂ mass, and because of higher CO ₂ buoyancy, which drives the upward CO ₂ migration. A set of 15 criteria, with several classes each, has been developed for the assessment and ranking of sedimentary basins in terms of their suitability for CO ₂ sequestration. Using a parametric normalization procedure, a basin's individual scores are summed to a total score using weights that express the relative importance of different criteria. The total score is ranked to determine the most suitable basin or region thereof for the geological sequestration of CO ₂. The method is extremely flexible in that it allows changes in the functions that express the importance of various classes for any given criterion, and in the weights that express the relative importance of various criteria. Examples of application are given for Canada's case and for the Alberta basin in Canada.