Elsevier

Chemical Geology

Volume 217, Issues 3–4, 25 April 2005, Pages 295-318
Chemical Geology

Mineral sequestration of carbon dioxide in a sandstone–shale system

https://doi.org/10.1016/j.chemgeo.2004.12.015Get rights and content

Abstract

A conceptual model of CO2 injection in bedded sandstone–shale sequences has been developed using hydrogeologic properties and mineral compositions commonly encountered in Gulf Coast sediments. Numerical simulations were performed with the reactive fluid flow and geochemical transport code TOUGHREACT to analyze mass transfer between sandstone and shale layers and CO2 immobilization through carbonate precipitation. Results indicate that most CO2 sequestration occurs in the sandstone. The major CO2 trapping minerals are dawsonite and ankerite. The CO2 mineral-trapping capacity after 100,000 years reaches about 90 kg/m3 of the medium. The CO2 trapping capacity depends on primary mineral composition. Precipitation of siderite and ankerite requires Fe+2 supplied mainly by chlorite and some by hematite dissolution and reduction. Precipitation of dawsonite requires Na+ provided by oligoclase dissolution. The initial abundance of chlorite and oligoclase therefore affects the CO2 mineral-trapping capacity. The sequestration time required depends on the kinetic rate of mineral dissolution and precipitation. Dawsonite reaction kinetics is not well understood, and sensitivity regarding the precipitation rate was examined. The addition of CO2 as secondary carbonates results in decreased porosity. The leaching of chemical constituents from the interior of the shale causes slightly increased porosity. The limited information currently available for the mineralogy of natural high-pressure CO2 gas reservoirs is also generally consistent with our simulation. The “numerical experiments” give a detailed understanding of the dynamic evolution of a sandstone–shale geochemical system.

Introduction

A possible means of reducing carbon dioxide (CO2) emissions to the atmosphere is injection of CO2 into structural reservoirs in deep permeable geologic formations (Holloway, 1997). Such formations could include aquifers, oil and gas fields, and coal seams. Aquifers are the most abundant fluid reservoirs in the subsurface. The deepest aquifers in the United States commonly contain brackish or saline water. Aquifers with salinities exceeding 10,000 mg/L total dissolved solids are excluded by the U.S. Environmental Protection Agency as underground sources of drinking water. Hence, they are logical targets for the eventual disposal of CO2. The feasibility of storing CO2 in aquifers has been discussed in the technical literature over the last decade. These include an evaluation of the feasibility of CO2 aquifer storage in The Netherlands (Lohuis, 1993) and in the Alberta Basin, Canada (Gunter et al., 1993, Bachu et al., 1994, Perkins and Gunter, 1995, Law and Bachu, 1996, Gunter et al., 1996, Gunter et al., 1997). Furthermore, large-scale CO2 disposal in an aquifer is already being practiced in the Norwegian sector of the North Sea (Korbol and Kaddour, 1995). Recently, extensive experimental, field, and modeling studies of geological carbon sequestration have been conducted (Pearce et al., 1996, Rochelle et al., 1996, Gunter et al., 1997, Ortoleva et al., 1998, Johnson et al., 2001, White et al., 2001, McPherson and Lichtner, 2001, Oelkers et al., 2002, Rosenbauer and Koksalan, 2002, Kaszuba et al., 2002, Boram et al., 2002, Matter et al., 2002, Giammar et al., 2002, Jones et al., 2002, Goodman et al., 2002, Hedges et al., 2002, Hovorka et al., 2002, Horita, 2002, Knauss et al., 2002, Solano-Acosta et al., 2002, Palandri and Kharaka, 2002, Strazisar and Zhu, 2002, Perkins et al., 2002, Pruess et al., 2003).

Numerical modeling of geochemical processes is necessary to investigate long-term CO2 injection in deep aquifers, because aluminosilicate mineral alteration is very slow under ambient deep-aquifer conditions and is not amenable to experimental study. Xu et al. (2004) present a geochemical modeling analysis of the interaction of aqueous solutions under high CO2 partial pressures with three different rock types. The first rock is a glauconitic sandstone from the Alberta Sedimentary Basin. The second rock type evaluated is a proxy for a sediment from the United States Gulf Coast. The third rock type is a dunite, an essentially monomineralic rock consisting of olivine.

Xu et al. (2003) performed reactive transport simulations of a 1-D radial well region under CO2 injection conditions in order to analyze CO2 immobilization through carbonate precipitation, using Gulf Coast sandstones of the Frio formation of Texas. Most of the simulated mineral alteration pattern is consistent with the observations. Some inconsistencies with field observations are noted. For example, quartz abundance declines over the course of the simulation, while quartz overgrowths are observed during diagenesis due to the release of SiO2 during replacement of smectite by illite in adjacent shales (Land, 1984). The formation of pyrite in the field is not reproduced by the previous simulation, because sulfur (S) was not included in the kerogen composition.

The previous modeling (Xu et al., 2003, Xu et al., 2004) was simplified and approximated many of the complexities of actual diagenesis in the field. Major simplifications and limitations include, (1) treating the sandstone aquifer as if it were a closed system isolated from the enclosing shales, and (2) not adequately representing the extremely complex process of kerogen decomposition (or petroleum maturation) in deeply buried sediments. The proportions of reactant minerals in the simulation therefore differ from that of the total system in the field. The long-term interaction of injected carbon dioxide into sandstone aquifers with shale confining layers has not yet been investigated.

Here we present simulation results on mass transfer, mineral alteration, and consequent CO2 sequestration by carbonate precipitation in a sandstone–shale system. The mineral compositions of sandstone and shale were taken from Gulf Coast sediments. The mineralogy, thermodynamic database and kinetic data are refined from previous studies (Xu et al., 2003, Xu et al., 2004).

Section snippets

Simulation method

The present simulations were carried out using the non-isothermal reactive geochemical transport code TOUGHREACT (Xu and Pruess, 1998, Xu and Pruess, 2001). This code was developed by introducing reactive chemistry into the framework of the existing multi-phase fluid and heat flow code TOUGH2 (Pruess et al., 1999). Our modeling of flow and transport in geologic media is based on space discretization by means of integral finite differences (Narasimhan and Witherspoon, 1976). An implicit

Sandstone–shale configuration and properties

Much specific and detailed information will be required to assess the feasibility of disposing of CO2 in a sandstone–shale formation at any particular site, and to develop engineering designs for CO2 disposal systems. Before moving into site-specific investigations, general features and issues relating to the formation injection of CO2 should be explored. This can be done by investigating a sandstone–shale system that abstracts site-specific features representing characteristics that are common

Base case

Concentrations of aqueous chemical components through the sandstone–shale transect are presented in Fig. 2. To track diffusive transport fronts, a non-reactive tracer concentration of 1 was applied initially to the sandstone grid block. Fig. 2a shows tracer concentration distribution at different times. The initial pH in the sandstone is 7.34, and that in shale is 6.69. The imposition of a high CO2 pressure of 201 bar lowers the pH in the sandstone (Fig. 2b), and H+ diffuses from the sandstone

Summary and conclusions

A reactive geochemical transport model for a sandstone–shale system under high CO2 pressure conditions has been developed. The model has been used to analyze mass transfer of aqueous chemical components, the alteration pattern of minerals, sequestration of CO2 by secondary carbonates, and changes of porosity for a Gulf Coast aquifer.

CO2 diffuses from the sandstone (where CO2 is initially injected), lowering pH. Fe+2 from chlorite dissolution and Ca+2 from oligoclase dissolution diffuses from

Acknowledgement

We thank Curtis Oldenburg and Guoxiang Zhang for the internal reviews of the manuscript. We acknowledge Jacques Schott, Sigurdur Reynir Gislason, and two anonymous reviewers for their detailed helpful suggestions and comments during the review process that significantly improved the quality of the paper. This work was supported by the Director, Office of Science, Office of Basic Energy Sciences, of the U.S. Department of Energy, under Contract No. DE-AC03-76SF00098 with Lawrence Berkeley

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