Critical Review pubs.acs.org/est
Comprehensive Review of Caprock-Sealing Mechanisms for Geologic Carbon Sequestration Juan Song† and Dongxiao Zhang*,‡ †
ERE, College of Engineering, Peking University, Beijing 100871, China ERE & SKLTCS, College of Engineering, Peking University, Beijing 100871, China
‡
ABSTRACT: CO2 capture and geologic sequestration is one of the most promising options for reducing atmospheric emissions of CO2. Its viability and long-term safety, which depends on the caprock’s sealing capacity and integrity, is crucial for implementing CO2 geologic storage on a commercial scale. In terms of risk, CO2 leakage mechanisms are classified as follows: diffusive loss of dissolved gas through the caprock, leakage through the pore spaces after breakthrough pressure has been exceeded, leakage through faults or fractures, and well leakage. An overview is presented in which the problems relating to CO2 leakage are defined, dominant factors are considered, and the main results are given for these mechanisms, with the exception of well leakage. The overview includes the properties of the CO2−water/brine system, and the hydromechanics, geophysics, and geochemistry of the caprock-fluid system. In regard to leakage processes, leakage through faults or fracture networks can be rapid and catastrophic, whereas diffusive loss is usually low. The review identifies major research gaps and areas in need of additional study in regard to the mechanisms for geologic carbon sequestration and the effects of complicated processes on sealing capacity of caprock under reservoir conditions.
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INTRODUCTION CO2 capture and geologic sequestration is considered as one of the most promising options and the only technology available to mitigate atmospheric emissions of CO2 from large-scale fossil fuel usage.1,2 Deep saline aquifers, depleted oil and gas fields, and unminable coal seams are the primary targets for the geologic storage of CO2. It has been suggested that any technology used to geologically store CO2 underground should store it for a minimum of 1,000 years with a leakage rate of less than 0.1% per year.1,3,4 That the leakage rate should be low is of the utmost importance, as leakage could harm the environment and even cause loss of life.4,5 The presence of caprock is a prerequisite to considering any environment for geologic storage of CO2. Caprock’s sealing capacity, i.e., its ability to prevent leakage, is a critical consideration in gaining site approval and evaluating the economic feasibility of a CO2 storage project.6 Likewise, issues pertaining to safety and economic feasibility are critical to gaining public acceptance.7 Argillaceous rocks (mudstones, clays, and shales) and evaporites (salts and anhydrite) are commonly identified caprocks for CO2 storage.8 Michael et al.9 compared the seal lithology of existing saline aquifer storage sites and projects and found that out of seventeen projects, ten are shale, three mudstone, two limestone, one dolomite, and one mixed. Argillaceous rocks have important properties that determine their sealing ability, i.e., high capillary entry pressure, low permeability, high sorption capacity, high iron exchange capacity, and high swelling ability.10,11 Evaporites are © 2012 American Chemical Society
remarkably good seals, i.e., high capillary entry pressure and low permeability; however, they can exhibit brittleness at shallow depths. Brittle lithologies develop fractures, whereas ductile lithologies tend to behave plastically under deformation. Seal lithologies can be arranged by ductility as follows: salt > anhydrite > kerogen-rich shales > clay shales > silty shales.12 In terms of the pore space utilization, CO2 is preferably injected in a supercritical state (scCO2). This is because scCO2 is denser than gaseous CO2.13 scCO2 may undergo a phase change due to changes in reservoir pressure and/or in temperature. Depending on the reservoir pressure and temperature, CO2 can be stored as compressed gas, as liquid, or in a supercritical phase. Subsurface CO2 is always associated with excess pressure arising from the buoyancy force and injection-related overpressure. In terms of risk, four ways in which caprock can fail have been identified: diffusive loss through the caprock, leakage through pore spaces when capillary breakthrough pressure has been exceeded, leakage through faults or fractures, and well leakage when wells are degraded or inappropriately abandoned. In addition, any of these processes can occur in combination with others. Special Issue: Carbon Sequestration Received: Revised: Accepted: Published: 9
May 2, 2012 September 26, 2012 September 28, 2012 September 28, 2012 dx.doi.org/10.1021/es301610p | Environ. Sci. Technol. 2013, 47, 9−22
Environmental Science & Technology
Critical Review
Extensive research into the sealing properties of caprock, the sealing behaviors of faults, and the causes of caprock failure in the petroleum industry has been conducted (e.g. refs 14, 15, and 16). However, literature on caprock for CO2 storage is rather limited. The existing literature on this subject covers both experiments (e.g. refs 17, 18, and 19) and numerical models (e.g. refs 20, 21, 22, 23, and 24). Caprocks in the presence of CO2 and hydrocarbon have differences in wettability and chemical propertiesall of which are likely to impact sealing capacity. Thus, it is necessary to investigate the sealing behaviors of caprock when CO2 is present. This review focuses on the first three leakage modes: diffusive loss, leakage through pore spaces, and leakage through faults or fractures. In doing so, it both highlights key research findings and critical gaps in the current literature. For each mode, a brief introduction, a description of the main mechanisms or dominant factors, and the magnitude of CO2 migration/leakage are presented. After that, a comprehensive conclusion as well as a summary of research gaps and needs is given in regard to caprock sealing in CO2 sequestration.
Table 1. Overview of Effective Diffusion Coefficients for CO2 in Water-Saturated Caprocks and Water reference 17, 18 19 31
35 36 37 38
50 °C, 6−7 MPa; Muderong Shale 45 °C, tensile potential; failure occurs along shallowly (30°) dipping fractures under C and along steeply (60°) dipping fractures under E. Large change of stress in the first caprock layer; upward leakage rate and HM effects remain small. Shear slip occurs in the lower part of the caprock in C;a shear slip occurs near the ground surface and the overburden in E;b the maximum injection pressure is 24 MPa and 28 MPa in C and E, respectively. Uplift can be explained in reference to the poro-elastic expansion and pressure change of the caprock; it can be used to detect faults. CO2 leakage through the fractures and faults is small; the caprock provides an effective seal. Activation of sealing faults occurs during exploitation; shear failure may generate large deformations around the injection wells; uplift is mainly related to in situ rock properties. Shear-slip is first activated; at a low confinement (ratioc0.8), vertical cracks are possible. Lower parts of the caprock present the largest HM changes; pressure increases once influence of CO2 reaches the low permeability boundary.
C-compressional stress regime. bE-extensional stress regime. cRatio = horizontal stress/vertical stress.
authors’ knowledge, no single simulator can solve the problem. HM failure analysis calls for the cross-coupling of geomechanics, geochemistry, and transport. Rutqvist and Tsang129 were the first to couple TOUGH2 with FLAC3D in thermal-hydrological-mechanical (THM) analysis for CO2 storage. Recent advances in and applications of TOUGHFLAC are presented by Rutqvist.130 Other coupled simulators, including TOUGH2 and Code_Asteris have been used in other studies (Table 4).131−133 Such coupled simulators calculate the pore pressure with the flow code first. Then the pressure is transferred to the mechanical code, which gives a value to the effect of the pore pressure on stress in order to assess the hydraulic properties, which are input for the next step. Another method found in caprock HM failure analysis is response surface methodology. Rohmer and Bouc used a linear regression model to study the caprock failure of the Paris Basin.127,137 Their studies indicated that the initial stress state is the most sensitive parameter and that storage sites with the lowest initial stress state present the highest risk of caprock failure. The Poisson’s ratios of caprock and reservoir rocks are the second and third sources of uncertainty, respectively. Geochemically Induced/Reactivated Faults or Fractures. In general, three types of reactions can be identified in the caprock: aqueous phase reactions, dry scCO2 or gaseous reactions, and water-saturated scCO2 reactions. Aqueous Phase Reactions. Reactions that occur in an aqueous context are commonly assumed in CO2 storage. First, CO2 dissolves in brine to form the acid H2CO3, from which H+ dissociates and then causes a drop in pH. This is the main trigger of geochemical reactions, which are determined by sitespecific conditions such as the pressure and temperature, the mineralogy of the rock, and the composition of the brine. Thus reactions should be assessed on a case-by-case basis. It should be pointed out that shale caprock is the main caprock type such that its reactions have been investigated in several studies.39,101,113,138 The main minerals in shale caprock are clay minerals (such as Illite and smectite), quartz, feldspar, and calcite. Other main minerals of caprock include carbonate minerals (carbonate caprock) and gypsum (evaporites). The constitutive minerals have been studied in WP4 of the Géocarbone-Integrité project.139
are derived from the effective stress law and the Coulomb criterion.24,118,124 Extreme increases in pore fluid pressures in the vicinity of faults cause new fractures instead of fault reactivation when the faults do not favor reactivation. Deformation of such faults can be identified from failure plots if the differential stresses and relative strengths of the adjacent faults are known. The failure plot of a Berea sandstone sample,124 for example, suggests that at a differential stress of 20 MPa (a realistic assumption for sequestration projects125), a fault reactivation is possible at angles of
