CO2 Sequestration Sites Research Articles

Modeling CO2 saturation distribution in eolian systems

Eolian sandstone hydrocarbon-bearing reservoirs have been target of CO2 enhanced oil recovery as well as potential CO2 sequestration sites. These sandy reservoirs are compartmentalized by the presence of bounding surfaces, which can function as flow barriers. In this study, eolian packages of a specific outcrop are modeled and their bounding surfaces effects on multiphase flow in CO2 upward migration are simulated through adequate enforcement of capillary barriers in a compositional simulator. We investigate how two-scale dune foresets strike directions of the outcrop could hint on the choice of well direction to increase storage in this particular model. The genetic unit of eolian strata is small and therefore their corresponding heterogeneity features, such as bounding surfaces, require higher resolution than that available through well logs. We build a synthetic eolian simulation model with associated bounding surfaces, geometrically inspired by the Permian Cedar Mesa Sandstone in southern Utah, USA. Permeability values of sand bodies and bounding surfaces are taken from actual outcrop reported data and surface examples to produce a lower bound of absolute permeability contrast. Capillary pressure is parameterized by the gridblock permeability, which implies that the capillary pressure contrast also represents a lower bound on the basis of published information. Our results show that bounding surfaces markedly reduce accessibility ratio (sweep efficiency), up to 55%, compared with cases where bounding surfaces are ignored, resulting in a larger plume size beneath the caprock and also higher leakage risk. Interestingly, well direction with respect to foreset strike direction has negligible effects on trapping and accessibility ratio for the low inclination angle. The methodology developed in this study could be applied to study CO2 storage in other eolian formations.

FEASIBILITY TO DETECT SIGNS OF POTENTIAL CO2 LEAKAGE WITH MULTI-TEMPORAL SPOT SATELLITE VEGETATION IMAGERY IN OTWAY, VICTORIA

Abstract. This paper presents image processing results for the OtwayCO2storage site, a demonstration project of CO2 sequestration in south-western Victoria, Australia. These results were derived from SPOT-VGT S10 datasets of 2001 to mid 2011. Over 65,000 tonnes of CO2-rich gas stream was injected into a depleted gas reservoir at a depth of 2050 meters at the site since 2008. Over time, CO2 migration up-dip within the 31 m thick reservoir sandstone capped by the impervious thick seal rock has been recorded. But no top soil contamination has been discovered. This study has analysed the site vegetation growth using NDVI as a measure on a pixel by pixel basis. The multi-year time series result shows that NDVI values at the site regularly vary according to the seasons. Furthermore, precipitation levels were fluctuating in the past 10 years, especially in the years of 2002 and 2006, which correlated with low NDVI measuring results. But there are detected hot spots that cannot be linked with rainfall. Authors have found that some hot spots correspond with site well drilling and pipelines construction periods and locations. While others might be due to image data biased. Therefore, certain low NDVI spikes in the temporal evolution results cannot be attributed to only drought or pasture grazing. These subtle changes detected in the NDVI index prove the ability to use satellite image for providing valuable information to decision makers in relation to CO2 sequestration site environmental safety monitoring for searching CO2 leakage signals.

Fracture model of the Upper Freeport coal: Marshall County West Virginia pilot ECBMR and CO2 sequestration site

A model discrete fracture or cleat network was developed for the Pennsylvanian Upper Freeport coal seam at a carbon sequestration pilot site in southeastern Marshall Co., West Virginia, U. S. A. The model reservoir cleat network was developed using 3D seismic post-stack processing and interpretation workflows combined with observations of fracture systems in the surrounding region. The Upper Freeport coal is unminable in this area and served as a test for the feasibility of combined enhanced coalbed methane recovery (ECBMR) operations with CO2 storage in unminable coals. Well log-derived subsurface structure maps were used to calibrate 3D seismic time-to-depth conversion. Post-stack processing was used to enhance and identify subtle discontinuities in the seismic data that could be related to field-scale faults, fracture zones or stratigraphic heterogeneity. The cleat model was developed using power law fracture length and aperture distributions. Spatial variations of cleat intensity in the model were controlled using measures of localized structural discontinuity extracted from 3D seismic attribute workflows. The cleat model identifies a permeable fracture facies within the reservoir most likely to be impacted by CO2 injection and migration. Areas of concentrated seismic discontinuity bear some spatial association to areas of positive vertical deformation observed in a tiltmeter survey of the site and attributed to CO2 injection. The model could help focus time-lapse processing and interpretation in regions estimated to have higher permeability and porosity and higher probability for change of acoustic properties in response to CO2 injection and methane production. The approach developed here has general applicability to identification of fracture facies and development of unconventional naturally fractured reservoirs in other lithologies and basins.

Numerical simulation and optimization of CO2 sequestration in saline aquifers

With heightened concerns on CO2 emissions from coal fired electricity generation plants, there has been major emphasis in recent years on the development of safe and economical Carbon Dioxide Capture and Sequestration (CCS) technology worldwide. Saline reservoirs are attractive geological sites for CO2 sequestration because of their huge capacity for long term sequestration. Over the last decade, numerical simulation codes have been developed in US, Europe and Japan to determine a priori the CO2 storage capacity of a saline aquifer and to provide risk assessment with reasonable confidence before the actual deployment of CO2 sequestration can proceed with enormous investment. In US, the 2nd version of Transport of Unsaturated Groundwater and Heat (TOUGH2) numerical simulator has been widely used for this purpose. However at present, it does not have the ability to determine optimal parameters such as injection rate, injection pressure, injection depth for vertical and horizontal wells, etc. for optimization of the CO2 storage capacity and for minimizing the leakage potential by confining the plume migration. This paper describes the development of a “Genetic Algorithm (GA)” based optimizer for TOUGH2 that can be used by the industry with good confidence to optimize the CO2 storage capacity in a saline aquifer of interest. This new code including the TOUGH2 and the GA optimizer is designated as “GATOUGH2”. It has been validated by conducting simulations of three widely used benchmark problems by the CCS researchers worldwide: (a) study of CO2 plume evolution and leakage through an abandoned well, (b) study of enhanced CH4 recovery in combination with CO2 storage in depleted gas reservoirs, and (c) study of CO2 injection into a heterogeneous geological formation. The results of these simulations are in excellent agreement with those of other researchers using different codes. The validated code has been employed to optimize the proposed water-alternating-gas (WAG) injection scheme for (a) a vertical CO2 injection well and (b) a horizontal CO2 injection well, in order to optimize the CO2 sequestration capacity of an aquifer. The optimized calculations from GATOUGH2 are compared with the brute force nearly optimized results obtained by performing a large number of calculations. These comparisons demonstrate the significant efficiency and accuracy of GATOUGH2 as an optimizer compared to using TOUGH2 in a brute force manner. This capability holds a great promise in studying a host of other problems in CO2 sequestration such as how to optimally accelerate the capillary trapping, accelerate the dissolution of CO2 in water or brine, and immobilize the CO2 plume.

Inversion of pressure anomaly data for detecting leakage at geologic carbon sequestration sites

Leakage from abandoned wells and geologic faults represents one of the greatest risks to the integrity of geologic CO2 sequestration sites. The ability to detect leakage in a timely manner is, therefore, crucial for mitigating the potential adverse impacts of leakage to the public and environment. We present an inversion approach for recovering both leakage locations and rates by using observed pressure anomaly data. The approach is based on formulation of a linear system of equations using the unit-step response method, which is applicable to both analytical and numerical models. Because the resulting system is often ill conditioned, we investigate the efficacy of regularization methods for stabilizing the solutions. Further, when prior information is insufficient to restrict the number of search locations, a global optimization algorithm is used to solve the challenging problem of joint location and leakage history inversion. The performance of several linear inversion solvers is compared while considering effects such as measurement error and spatial heterogeneity. The results are promising and suggest that our pressure-anomaly-based leakage detection algorithm can be used to identify leaky wells in practice. It can be deployed as an integrated component of CO2 risk management frameworks.

Full waveform inversion in the time lapse mode applied to CO2 storage at Sleipner

ABSTRACTCarbon capture and storage is a viable greenhouse gas mitigation technology and the Sleipner CO2 sequestration site in the North Sea is an excellent example. Storage of CO2 at the Sleipner site requires monitoring over large areas, which can successfully be accomplished with time lapse seismic imaging. One of the main goals of CO2 storage monitoring is to be able to estimate the volume of the stored CO2 in the reservoir. This requires a parametrization of the subsurface as exact as possible. Here we use elastic 2D time‐domain full waveform inversion in a time lapse manner to obtain a P‐wave velocity constrain directly in the depth domain for a base line survey in 1994 and two post‐injection surveys in 1999 and 2006. By relating velocity change to free CO2 saturation, using a rock physics model, we find that at the considered location the aquifer may have been fully saturated in some places in 1999 and 2006.

Modeling of CBM production, CO2 injection, and tracer movement at a field CO2 sequestration site

Sequestration of carbon dioxide in unmineable coal seams is a potential technology mainly because of the potential for simultaneous enhanced coalbed methane production (ECBM). Several pilot tests have been performed around the globe leading to mixed results. Numerous modeling efforts have been carried out successfully to model methane production and carbon dioxide (CO{sub 2}) injection. Sensitivity analyses and history matching along with several optimization tools were used to estimate reservoir properties and to investigate reservoir performance. Geological and geophysical techniques have also been used to characterize field sequestration sites and to inspect reservoir heterogeneity. The fate and movement of injected CO{sub 2} can be determined by using several monitoring techniques. Monitoring of perfluorocarbon (PFC) tracers is one of these monitoring technologies. As a part of this monitoring technique, a small fraction of a traceable fluid is added to the injection wellhead along with the CO{sub 2} stream at different times to monitor the timing and location of the breakthrough in nearby monitoring wells or offset production wells. A reservoir modeling study was performed to simulate a pilot sequestration site located in the San Juan coal basin of northern New Mexico. Several unknown reservoir properties at the field site were estimatedmore » by modeling the coal seam as a dual porosity formation and by history matching the methane production and CO{sub 2} injection. In addition to reservoir modeling of methane production and CO{sub 2} injection, tracer injection was modeled. Tracers serve as a surrogate for determining potential leakage of CO{sub 2}. The tracer was modeled as a non-reactive gas and was injected into the reservoir as a mixture along with CO{sub 2}. Geologic and geometric details of the field site, numerical modeling details of methane production, CO{sub 2} injection, and tracer injection are presented in this paper. Moreover, the numerical predictions of the tracer arrival times were compared with the measured field data. Results show that tracer modeling is useful in investigating movement of injected CO{sub 2} into the coal seam at the field site. Also, such new modeling techniques can be utilized to determine potential leakage pathways, and to investigate reservoir anisotropy and heterogeneity.« less

Modeling of Rocks and Cement Alteration due to CO2 Injection in an Exploited Gas Reservoir

The injection of CO2 in exploited natural gas reservoirs as a means to reduce greenhouse gas (GHG) emissions is highly attractive as it takes place in well-known geological structures of proven integrity with respect to gas leakage. The injection of a reactive gas such as CO2 puts emphasis on the possible alteration of reservoir and caprock formations and especially of the wells’ cement sheaths induced by the modification of chemical equilibria. Such studies are important for injectivity assurance, wellbore integrity, and risk assessment required for CO2 sequestration site qualification. Within a R&D project funded by Eni, we set up a numerical model to investigate the rock–cement alterations driven by the injection of CO2 into a depleted sweet natural gas pool. The simulations are performed with the TOUGHREACT simulator (Xu et al. in Comput Geosci 32:145–165, 2006) coupled to the TMGAS EOS module (Battistelli and Marcolini in Int J Greenh Gas Control 3:481–493, 2009) developed for the TOUGH2 family of reservoir simulators (Pruess et al. in TOUGH2 User’s Guide, Version 2.0, 1999). On the basis of field data, the system is considered in isothermal (50°C) and isobaric (128.5 bar) conditions. The effects of the evolving reservoir gas composition are taken into account before, during, and after CO2 injection. Fully water-saturated conditions were assumed for the cement sheath and caprock domains. The gas phase does not flow by advection from the reservoir into the interacting domains so that molecular diffusion in the aqueous phase is the most important process controlling the mass transport occurring in the system under study.

Changes in caprock integrity due to vertical migration of CO2 -enriched brine

In geologic carbon sequestration, caprock fractures may act as leakage pathways, threatening the long term sealing ability of the formation. A flow-through experiment was performed to investigate fracture evolution of a fractured carbonate caprock during simulated leakage of CO2-acidified brine. The initial brine composition represented that of a CO2-saturated brine having previously reacted with the injection formation minerals resulting in a starting pH of 4.9. Experimental temperature and pressure conditions were 40 °C and 10 MPa, corresponding to injection at a depth of 1 km. A combination of X-ray computed tomography and scanning electron microscopy was used to observe fracture evolution and investigate the mineralogical changes that occurred along the fracture wall. After one week of brine flow, the cross-sectional fracture area increased by an average of 2.7 times that of the initial fracture. The fracture surface was not eroded uniformly, with the largest areas of aperture growth corresponding to direct contact between the acidified brine and calcite. This preferential dissolution of calcite led to a large increase in fracture surface roughness and in some instances, created a silicate mineral-rich microporous coating along the fracture wall. Results from this study suggest that the clay content of low permeability carbonate formations may be an important factor in controlling their long term integrity while in contact with acidified brine and should be considered when selecting appropriate injection sites for geologic CO2 sequestration.

Site assessment update at Weyburn-Midale CO2 sequestration project, Saskatchewan, Canada: New results at an active CO2 sequestration site.

Abstract The Weyburn Field, operated by Cenovus Energy, currently contains the largest amount of anthropogenic CO 2 injected and geologically stored in the world, with over 16 million tonnes of CO 2 sequestered as of June 2010. The IEA GHG Weyburn-Midale CO 2 Monitoring and Storage Project is in its Final Stage of research and is focussed on building on the results developed in Phase 1 of this study to provide a further understanding of parameters required to develop, implement and regulate carbon storage sites. One aspect of geological characterization of the storage site in this phase of research is to further develop the geological model used in Phase 1 by adding more wells and including several geological units not incorporated into the geological model of Phase 1. Additionally, improvements into the quantification of regional flow directions in and around the active CO 2 injection site by using hydrologic data (pressure tests and hydrochemistry analyses) not included in the original model. These stratigraphic, pressure, hydrochemical and temperature data of flow units in a 1865 km 2 area around the Weyburn Field will better define fluid movement in the injection site and assist with long-term modeling of the fate of injected CO 2 . Stratigraphic data from more than 900 wells are included in the current geological model including 200 newly picked wells. The Final Phase geological model includes: 1) an “altered zone” of anhydrite and dolostone at the up dip edge of the Weyburn-Midale reservoir that forms the caprock to the reservoir subjacent the regional seal formed by the Watrous Formation; 2) the Frobisher Evaporite, a variably thick anhydrite unit present at the base of the reservoir beneath the northern portion of the field; and 3) the Oungre Evaporite, an anhydrite/dolomite unit within the Ratcliffe beds present above the majority of the reservoir, all of which were not included in the Phase 1 model. Adding these units into the model required closely delineating the zero edges using isopach values, and then stacking the isopach thicknesses to proportionately fill the 3D grid while maintaining their complex morphology and accurately representing the hydrogeological flow units above and below the Midale aquifer. Core derived porosity and permeability was included in the model for the Midale and Frobisher aquifer units only as beyond these beds very little core exist. Pressure and hydrochemistry maps for the targeted aquifers (Midale, Frobisher and Ratcliffe) contain straddle tests and new wells drilled since Phase I was completed. Hydrogeological results from this study include; 1) Hydrochemistry maps which indicate large variations in total dissolved solids (TDS) within the target aquifers. The observed chemical and density variations have an influence on fluid movement; 2) Porosity and permeability models for the Midale, Frobisher, and Ratcliffe which will be used in conjunction will structure, chemistry and pressure maps help to elucidate fluid movement within the aquifers for long-term CO 2 storage modeling. The permeability model for the Midale aquifer is composed of data from DSTs and core to examine the geologic variations and preferential flow paths within the injection aquifer; 3) Driving force ratio (DFR) maps forces acting on fluid movement within an aquifer and incorporate aquifer structure, TDS, temperature and pressure.

The key to commercial-scale geological CO2 sequestration: Displaced fluid management

The Wyoming State Geological Survey has completed a thorough inventory and prioritization of all Wyoming stratigraphic units and geologic sites capable of sequestering commercial quantities of CO2 (5–15 Mt CO2/year). This multi-year study identified the Paleozoic Tensleep/Weber Sandstone and Madison Limestone (and stratigraphic equivalent units) as the leading clastic and carbonate reservoir candidates for commercial-scale geological CO2 sequestration in Wyoming. This conclusion was based on unit thickness, overlying low permeability lithofacies, reservoir storage and continuity properties, regional distribution patterns, formation fluid chemistry characteristics, and preliminary fluid-flow modeling. This study also identified the Rock Springs Uplift in southwestern Wyoming as the most promising geological CO2 sequestration site in Wyoming and probably in any Rocky Mountain basin. The results of the WSGS CO2 geological sequestration inventory led the agency and colleagues at the UW School of Energy Resources Carbon Management Institute (CMI) to collect available geologic, petrophysical, geochemical, and geophysical data on the Rock Springs Uplift, and to build a regional 3-D geologic framework model of the Uplift. From the results of these tasks and using the FutureGen protocol, the WSGS showed that on the Rock Springs Uplift, the Weber Sandstone has sufficient pore space to sequester 18 billion tons (Gt) of CO2, and the Madison Limestone has sufficient pore space to sequester 8 Gt of CO2.

Large-Scale Source Localization with a Wireless Sensor Network Application

AbstractThis paper concerns the problem of large-scale source localization arising when many potential sources must be classified as either active or inactive such that the probability of missing an active source is bounded. A new iterative heuristic called the Iterative Source Localization Procedure (ISLoP) is introduced that reduces the complexity of a source localization problem with J potential sources from 2J to J per iteration, while also providing a local bounds on the maximum probability of a missed source. The ISLoP separates the source localization problem into a likelihood maximization problem followed by an active source localization problem. A diffusion example is used to demonstrate the performance of the ISLoP when compared to an estimation-based approach, where the heuristic is shown to have increasingly better performance as the bound on the maximum probability of a missed source is decreased. An experimental evaluation of the heuristic with respect to common wireless sensor networking errors is provided using a test bed implementation for a CO2 sequestration site monitoring problem.

Monitoring CO2 response on surface seismic data; a rock physics and seismic modeling feasibility study at the CO2 sequestration site, Ketzin, Germany

An important component of any CO2 sequestration project is seismic monitoring for tracking changes in subsurface physical properties such as velocity and density. Reservoir conditions and CO2 injection quantities govern whether such changes may be observable as a function of time. Here we investigate surface seismic response to CO2 injection at the Ketzin site, the first European onshore CO2 sequestration pilot study dealing with research on geological storage of CO2. First, a rock-physics model was built to evaluate the effect of injected CO2 on the seismic velocity. On the basis of this model, the seismic response for different CO2 injection geometries and saturation was studied using 1D elastic modeling and 2D acoustic finite difference modeling. Rock-physics models show that CO2 injected in a gaseous state, rather than in a supercritical state, will have a more pronounced effect on seismic velocity, resulting in a stronger CO2 response. However, reservoir heterogeneity and seismic resolution, as well as random and coherent seismic noise, are negative factors that need to be considered in a seismic monitoring program. In spite of these potential difficulties, our seismic modeling results indicate that the CO2 seismic response should be strong enough to allow tracking on surface seismic data. Amplitude-related attributes (i.e., acoustic impedance versus Poisson's ratio cross-plots) and time-shift measurements are shown to be suitable methods for CO2 monitoring.

Onset of Convection in CO2 Sequestration in Deep Inclined Saline Aquifers

Abstract CO2 sequestration in deep geological formations has been suggested as an option to reduce greenhouse gas emissions. Saline aquifers are one of the most promising options for carbon dioxide storage. It has been shown that the dissolution of CO2 into brine causes the density of the mixture to increase. If the corresponding Rayleigh number of the porous medium is enough to initiate convection currents, the rate of dissolution will increase. Early time dissolution of CO2 in brine is mainly dominated by molecular diffusion, while late time dissolution is predominantly governed by a convective mixing mechanism. In this paper, linear stability analysis of density-driven miscible flow for carbon dioxide sequestration in deep inclined and homogeneous saline aquifers is presented. The effect of inclination and its influence on the pattern of convection cells has been investigated and the results are compared with the horizontal layer. The current analysis provides approximations for the initial wavelength of the convective instabilities and the onset of convection that helps in selecting suitable candidates for geological CO2 sequestration sites. Introduction Carbon dioxide sequestration is the capture and safe storage of carbon dioxide that would otherwise emit to the atmosphere. Sequestration refers to any storage scheme that can keep CO2 out of the atmosphere(1). In general, proposed storage sites of carbon dioxide can be divided into two categories: geological sites and marine sites. Carbon dioxide sequestration in deep geological formations has been suggested as a way of reducing greenhouse gas emissions. Geologic sequestration of CO2 is the capture of CO2 from major sources, transporting it usually by pipeline, and injecting it into underground formations such as oil and gas reservoirs, saline aquifers and unmineable coal seams for a significant period of time(2, 3). Unlike coalbed methane reserves and oil reservoirs, sequestration of CO2 in deep saline aquifers does not produce value-added by-products, but it has other advantages. While there are uncertainties regarding the scope, the world's total capacity to store CO2 deep underground is large(4). Underground formations are generally unused and are available in many parts of the world(5). It has been estimated that deep saline formations in the United States could potentially store up to 500 billion tonnes of CO2. Most existing large CO2 point sources are within easy access to a saline formation injection point and, therefore, sequestration in saline formations is compatible with a strategy of transforming large portions of the existing energy and industrial assets to near-zero carbon emissions via low-cost carbon sequestration retrofits(3). However, it is important to investigate the behaviour of CO2 injected into aquifers for effective and safe use of storage. Geological storage of CO2 as a greenhouse gas mitigation option was proposed in the 1970s(6), but little research was done until the early 1990s when the idea gained credibility through the work of individual research groups(7–10). When CO2 is injected into the formation above its critical temperature and pressure, the density of supercritical carbon dioxide is usually less than brine. This density difference causes CO2 to migrate upwards to the top of the formation under an impermeable caprock.

Feasibility Investigation and Modeling Analysis of CO2 Sequestration in Arbuckle Formation Utilizing Salt Water Disposal Wells

The rate of CO2 production in many states, primarily from coal-fired power plants, is such that it only takes a few years to fill up any depleted oil and gas reservoirs. In order to reduce the level of CO2 in the atmosphere and to minimize the cost of sequestration, the injection of CO2 into aquifers utilizing disposal wells has been targeted. In this paper, an analysis of one particular case, namely, the Arbuckle formation in Oklahoma, was carried out to demonstrate its feasibility for CO2 sequestration. First, a general review for CO2 sequestration into aquifers utilizing existing disposal wells is presented. The limiting criteria for CO2 sequestration in terms of the geology of the aquifer, lithology of the host rock, cost of operation, impact on reservoir properties, depth of the completed interval to maintain supercritical conditions for CO2, injection pressure and rate to minimize gravity segregation, mobility ratio to prevent viscous fingering, and chemical interaction of aqueous and solid phases are discussed. Then, the existence of residual oil in the aquifer and its effect on reaction chemistry concerning the potential CO2 sequestration applications in the Arbuckle formation are evaluated. This investigation was conducted by means of simulation of the prevailing processes. The cutoff points from dissolution to precipitation for each constituent in terms of different CO2 injection rates were obtained by utilizing the simulation models GEM-GHG and PHREEQC and were supported by a database of 150 disposal wells from which 25 wells were completed in the Arbuckle formation. We critically evaluate the current state of knowledge, identify areas needing research, and offer practical approaches for the evaluation of potential CO2 sequestration sites using commercial disposal wells.

Numerical Simulation of CO2 Leakage through Abandoned Wells: Model for an Abandoned Site with Observed Gas Migration in Alberta, Canada

This paper will present results of a numerical modelling study on CO2 migration through abandoned wells. Leakage of CO2 through plugged and abandoned wellbores is one of the major concerns for long-term safety and effectiveness of geologic CO2 sequestration. For risk assessment and mitigation, it is not only important to understand and characterize the potential for CO2 leakage through wellbores but also subsequent CO2 migration beyond the primary sequestration reservoir. Subsequent to the leak, CO2 may take a direct path towards the accessible environment or it may migrate in an indirect stair-stepping manner through wellbores/fractures across multiple, shallow permeable strata. In the later case, identification of leak source and application of mitigation strategies may become a challenge. For this study we use data from a site in Alberta, Canada which has reported natural gas leak at surface. Investigations on origin of the gas and potential gas migration path from the original source to the surface at the analog site show that the gas could be moving through multiple wells and across multiple formations. There are multiple wells at the site which were drilled and abandoned without production casing and are completely open between two hydrocarbon bearing zones creating cross-flow across zones through open wellbores. Our study focuses on the deeper formations and potential for leakage for CO2 injected in deeper formation. A complex numerical fluid-flow model is developed for the site in FEHM, LANL’s porous media fluid-flow simulator. The model explicitly accounts for wellbore details such as abandonment plugs, casing, annulus cement, etc. The model was used to perform long-term simulations of CO2 injection and potential migration through abandoned wells. Numerical simulation results show limited migration of CO2 through abandoned wells. Such detailed simulation would be valuable to develop effective abandonment practices as well as mitigation strategies at CO2 sequestration sites.

Understanding the impact of the level of characterization on long-term performance predictions at geologic CO2 sequestration sites

This article was submitted without an abstract, please refer to the full-text PDF file.

Stability of a fluid in a horizontal saturated porous layer: effect of non-linear concentration profile, initial, and boundary conditions

Carbon dioxide injected into saline aquifers dissolves in the resident brines increasing their density, which might lead to convective mixing. Understanding the factors that drive convection in aquifers is important for assessing geological CO2 storage sites. A hydrodynamic stability analysis is performed for non-linear, transient concentration fields in a saturated, homogenous, porous medium under various boundary conditions. The onset of convection is predicted using linear stability analysis based on the amplification of the initial perturbations. The difficulty with such stability analysis is the choice of the initial conditions used to define the imposed perturbations. We use different noises to find the fastest growing noise as initial conditions for the stability analysis. The stability equations are solved using a Galerkin technique. The resulting coupled ordinary differential equations are integrated numerically using a fourth-order Runge–Kutta method. The upper and lower bounds of convection instabilities are obtained. We find that at high Rayleigh numbers, based on the fastest growing noise for all boundary conditions, both the instability time and the initial wavelength of the convective instabilities are independent of the porous layer thickness. The current analysis provides approximations that help in screening suitable candidates for homogenous geological CO2 sequestration sites.

The Atzbach-Schwanenstadt gas field—a potential site for onshore CO2 storage and EGR

As a part of the EU-supported CASTOR project, four sites for potential or actual underground CO2 sequestration in Europe are being investigated. One of these sites is Atzbach-Schwanenstadt gas field in Upper Austria, operated by Rohol-Aufsuchungs AG. The CASTOR project is a feasibility study which aims:

Geomechanical aspects of CO2 sequestration in a deep saline reservoir in the Ohio River Valley region

The Ohio River Valley CO2 Storage Project is an ongoing characterization of deep saline formations being considered as potential sites for geological CO2 sequestration. We completed a geomechanical analysis of the Rose Run Sandstone, a potential injection zone, and its adjacent formations at the American Electric Power's 1.3-GW Mountaineer Power Plant in New Haven, West Virginia. The results of this analysis were then applied to three investigations used to evaluate the feasibility of anthropogenic CO2 sequestration in the potential injection zone. First, we incorporated the results of the geomechanical analysis with a geostatistical aquifer model in CO2 injection-flow simulations to test the effects of introducing a hydraulic fracture to increase injectivity. We observed a nearly fourfold increase of injection rate caused by the introduction of a hydraulic fracture in the injection zone. The flow simulations predict that a single vertical well with a hydraulic fracture could inject a maximum of 300–400 kt of CO2/yr. In the second investigation, we determined that horizontal injection wells at the Mountaineer site are feasible because the high rock strength ensures that such wells would be stable in the local stress state. The third investigation used the geomechanical analysis results to evaluate the potential for injection-induced seismicity. If preexisting, but undetected, nearly vertical faults striking north-northeast or east-northeast are present, the increased pore pressure from CO2 injection would raise their reactivation potential. Geomechanical analysis of potential CO2 sequestration sites provides critical information required to evaluate its sequestration potential and associated risks.