Transp Porous Med (2010) 82:49–76 DOI 10.1007/s11242-009-9396-z



## Investigation of CO 2 

## Plume Behavior for a Large-Scale Pilot Test of Geologic Carbon Storage in a Saline Formation

Christine Doughty

Received: 15 December 2008 / Accepted: 9 April 2009 / Published online: 9 May 2009 © The Author(s) 2009. This article is published with open access at Springerlink.com

Abstract The hydrodynamic behavior of carbon dioxide (CO 2 ) injected into a deep saline formation is investigated, focusing on trapping mechanisms that lead to CO 2 plume stabilization. A numerical model of the subsurface at a proposed power plant with CO 2 capture is developed to simulate a planned pilot test, in which 1,000,000 metric tons of CO 2 is injected over a 4-year period, and the subsequent evolution of the CO 2 plume for hundreds of years. Key measures are plume migration distance and the time evolution of the partitioning of CO 2 between dissolved, immobile free-phase, and mobile free-phase forms. Model results indicate that the injected CO 2 plume is effectively immobilized at 25 years. At that time, 38% of the CO 2 is in dissolved form, 59% is immobile free phase, and 3% is mobile free phase. The plume footprint is roughly elliptical, and extends much farther up-dip of the injection well than down-dip. The pressure increase extends far beyond the plume footprint, but the pressure response decreases rapidly with distance from the injection well, and decays rapidly in time once injection ceases. Sensitivity studies that were carried out to investigate the effect of poorly constrained model parameters permeability, permeability anisotropy, and residual CO 2 saturation indicate that small changes in properties can have a large impact on plume evolution, causing significant trade-offs between different trapping mechanisms.

Keywords Geologic carbon storage

· CO 2 sequestration

· Multiphase flow modeling

· CO 2 trapping mechanisms

· Plume stabilization

1 Introduction

Understanding the hydrodynamic behavior of large-volume CO 2 plumes is critical for advancing the technology of geologic carbon storage in deep saline formations. This behavior is examined by developing a numerical model of the subsurface at the proposed Kimberlina

C. Doughty (

### B) Earth Sciences Division, Lawrence Berkeley National Laboratory, University of California, Berkeley, CA 94720, USA e-mail: cadoughty@lbl.gov


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Fig. 1 Map of California showing potential geologic carbon storage sites in sedimentary basins (light green shading), courtesy of the California Energy Commission. The Kimberlina pilot test is located in the Southern San Joaquin Valley (boxed red dot). The inset shows a satellite image of the Kimberlina power plant site. The power plant and the injection well will be located near one another in the southwestern corner of the property

advanced oxy-combustion power plant with CO 2 capture in the southern San Joaquin Valley, California (Fig. 1 ). For its first 4 years of operation, the power plant will provide 250,000 metric tons of CO 2 per year for a large-volume CO 2 geologic storage pilot. Thereafter, the captured CO 2 will be sold locally for enhanced oil recovery operations. As shown in Fig. 1
,the sedimentary basin that forms California’s Central Valley provides a huge potential capacity for geologic carbon storage; thus, lessons learned from the Kimberlina site may be widely applicable. The target storage formation is a high-permeability sand layer located at a depth of 2 km, which is over- and underlain by low-permeability shales. Within the formation itself, sands and shales are interleaved in a lenticular fashion. This geological setting provides an ideal situation for examining the interplay of buoyancy flow, capillary forces, CO 2 dissolution, and geologic heterogeneity in controlling the behavior of the injected CO 2 plume. The model simulates the 4-year injection period, in which a total of 1 million metric tons of CO 2 are injected, and the subsequent evolution of the CO 2 plume for hundreds of years. Because specific geologic information at the site of the proposed injection well is lacking (the nearest well penetrating the storage formation is 2.5 km away), the simulation results should not be taken as precise predictions, but rather general indications of the key features of CO 2 plume behavior. In the subsurface, CO 2 exists as an immiscible free phase and as a solute in the aqueousphase. For typical hydrostatic pressure gradients and geothermal temperature gradients, freephase CO 2 is supercritical at depths greater than about 800 m. The present study does not consider pressure/temperature conditions below the critical point of CO 2 (73.8 bars, 31 ◦ C), so CO 2 never exists as a free phase in liquid or gaseous form. Supercritical CO 2 is lighter


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and much less viscous than the native brine; hence, in a two-phase flow context, it is referred to as gas, whereas the aqueous phase is referred to as liquid. Trapping CO 2 is a significant challenge because the low density of free-phase CO 2 compared to native brine makes it strongly buoyant. Immobilizing CO 2 in the subsurface forlong-term geologic storage can be accomplished by four primary mechanisms. (1) Stratigraphic or structural trapping: buoyant free-phase CO 2 is trapped beneath low-permeability layers or faults or in anticline structures. (2) Residual CO 2 trapping (also known as capillary trapping, mobility trapping, or phase trapping): multiphase flow processes immobilize free-phase CO 2 . In the petroleum literature (e.g., Land 1968 ; Holtz 2002) it is commonly assumed that residual gas saturation (the saturation below which CO 2 is immobile) is historydependent, with a zero or small value during the drainage process (CO 2 displacing brine), and a potentially large value during imbibition (brine displacing CO 2 ), which increases as the maximum historical gas saturation increases. (3) Dissolution trapping (also known as solubility trapping): the CO 2 that dissolves in brine is no longer buoyant so there is no driving force toward the surface. In fact, CO 2 -saturated brine is denser than native brine. As CO 2 -laden brine sinks deeper into the formation, it can set up circulation patterns that enable more free-phase CO 2 to come into contact with native brine, enabling more dissolution to occur (Ennis-King and Paterson 2005 ; Pruess and Zhang 2008 ). (4) Mineral trapping: CO 2 reacts with rock minerals to form carbonate compounds, typically over very long time scales (Pruess et al. 2003 ; Xu et al. 2003
, 2005 ; Gherardi et al. 2007 ). The first three mechanisms, collectively referred to as hydrodynamic trapping by Bachu et al. ( 1994 ), dominate plume behavior over the hundred-year time scale and are the focus of the present paper. Because trapping mechanisms are scale-dependent, understanding large-volume pilots is a necessary step between existing studies involving small-scale CO 2 injection tests and actual commercial CO 2 storage operations. Additionally, predicting the spatial and temporal evolution of the CO 2 plume and the attendant pressure increase can help optimize design of the monitoring methods used for the pilot.

2 Model Development

2.1 Numerical Simulator

Numerical modeling is conducted using TOUGH2 (Pruess et al. 1999 ), a general-purposenumerical simulator for multiphase, multicomponent fluid and heat flow in porous and fractured media. TOUGH2 incorporates accurate phase-partitioning and thermophysical properties of all fluid phases and components and uses a multiphase extension of Darcy’s law that includes relative permeability and capillary-pressure effects. The present studies utilize an equation of state package called ECO2N (Pruess and Spycher 2007 ; Spycher and Pruess 2005 ), designed to treat a two-phase (liquid, gas), three-component (water, salt (NaCl), CO 2 ) system in pressure/temperature regimes above the critical point of CO 2 ( P = 73

. 8 bars, T = 31 ◦ C), and a hysteretic formulation for capillary pressure and relative permeability (Doughty 2007 ). Chemical reactions among CO 2 , brine, and rock minerals are not considered in TOUGH2, but a companion code, TOUGHREACT (Xu et al. 2006 ), is available for such studies. In TOUGH2, dissolution of both CO 2 and NaCl in the aqueous phase is modeled as an equilibrium process. That is, in any grid block where one or both of these components exist, there is instantaneous partitioning between the aqueous phase (dissolution) and the free phase (supercritical for CO 2 and solid for NaCl). Partitioning is controlled by the solubility of each


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Fig. 2 CO 2 solubility (plotted as mass fraction of CO 2 in the aqueous phase) as a function of salinity (plotted as mass fraction of NaCl in the aqueous phase) for various depths, assuming a hydrostatic pressure gradient P (z ) = 1 + 0.1 z and a geothermal temperature gradient T (z ) = 15 + 0

. 025 z

component in the aqueous phase. NaCl solubility depends only on temperature, whereas CO 2 solubility depends on temperature, pressure, and salinity, as illustrated in Fig. 2 for typical CO 2 storage conditions. CO 2 solubility increases with increasing pressure and decreases with increasing temperature and salinity. Because pressure and temperature are usually correlated, both increasing with depth, their effect on CO 2 solubility tends to cancel out, leaving salinity as the primary controlling factor. If the amounts of CO 2 and NaCl in a given grid block are each below their respective solubility, then no free phase exists. If the amount of NaCl exceeds its solubility (e.g., as the grid block dries out), then solid salt precipitates. If the amount of CO 2 exceeds its solubility (e.g., as CO 2 is injected), then a supercritical phase develops. An important distinction between these two free phases is that solid salt is always immobile, whereas supercritical CO 2 may be mobile or immobile. Additionally, a small amount of liquid water evaporates into the supercritical phase, whereas the solid phase is pure NaCl. The fraction of pore space occupied by each phase is the saturation S , with Sg denoting the supercritical phase (primarily CO 2 , with a small amount of water vapour), S l denoting the aqueous phase (primarily water, with dissolved CO 2 and NaCl), and S s denoting the solid salt precipitate. For each grid block, Sg + S l + S s = 1. Together, capillary pressure P c , liquid relative permeability krl , and gas relative permeability krg variation as a function of saturation are known as characteristic curves; they control the way the brine (the wetting phase, also called the liquid phase) and supercritical CO 2 (the non-wetting phase, also called the gas phase) interact. In a hysteretic formulation, P c , krl , and krg depend not only on the saturation of the grid block, but also on the history of the saturation of the grid block. When gas saturation Sg increases because more CO 2 enters a grid block than leaves it, the process is known as drainage. Alternatively, when liquid saturation S

l increases because more brine enters a grid block than leaves it, the process is known asimbibition. The most critical parameter of the characteristic curves is the residual gas saturation, denoted as S  gr , which is the saturation below which gas is immobile (i.e., the saturation below which immiscible CO 2 is trapped). TOUGH2 uses the conceptualization common in the petroleum literature (Land 1968 ) in which it is assumed that under drainage conditions,


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Fig. 3 Capillary pressure and relative permeabilities as a function of saturation for primary drainage and for imbibition when S  gr = Sgrmax . Smaller values of S  gr would produce curves within the envelope formed by these two curves. The curve labeled krg shows relative permeability for supercritical CO 2 and the curve labeled krl shows relative permeability for brine

S 

gr = 0, but for imbibition, S  gr increases as maximum historical gas saturation increases. Thus, grid blocks that once contained the most CO 2 are those which trap the most CO 2 . The maximum value of S  gr , known as Sgrmax , is a material property dependent on rock porosity (Holtz 2002). Figure 3 shows the capillary pressure and relative permeability curves under primary drainage conditions and for imbibition when S  gr = Sgrmax . Smaller values of S  gr would produce curves within the envelope formed by these two curves. Figure 3 illustrates that CO 2 mobility can be much smaller under imbibition than under drainage. During a CO 2 injection period, drainage is the dominant process because the CO 2 plume is growing in all directions; hence S  gr = 0 and no CO 2 is trapped as residual gas. After injection ends, the leading edge of the CO 2 plume may still undergo drainage as the plume moves upward and up-dip by buoyancy forces, but at the trailing edge of the plume imbibition
occurs, S  gr >> 0, and a significant fraction of the CO 2 plume may be trapped as residual
gas.Although TOUGH2 has the capability of solving fully coupled fluid and heat flow problems, temperature is assumed to remain constant for the present simulations, to increase computational efficiency. Previous studies (Doughty and Myer 2009 ) have shown that thermal effects of CO 2 injection are minor if the injected CO 2 is pre-heated to near in situ temperature. Additionally, the slow flow process of aqueous-phase diffusion of dissolved species is not included in these simulations. For a typical CO 2 diffusivity of D = 2

. 10

− 9 m2 /s (Pruess and Zhang 2008 ), the characteristic diffusion length ( Dt ) 1 / 2 is only 0. 5 m for 4 years, 2.5 m for 100 years, and 8 m for 1,000 years, all small compared to CO 2 plume dimensions. Finally, TOUGH2 has the capability to decrease intrinsic permeability due to salt precipitation, but it is not invoked for the present simulations because the amount of salt that precipitates is small.
2.2 Geologic and Facies Models

A geologic model of the Southern San Joaquin Valley surrounding the Kimberlina power plant (Wagoner 2009 ) is shown in Fig. 4 . The target CO 2 storage formation is the Vedder


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Fig. 4 Geologic model of the southern San Joaquin Valley (adapted from Wagoner 2009 ). The location of the Kimberlina power plant is shown by the red dot near the center

Formation, a lower Miocene, fine- to coarse-grained massive marine sandstone with subordinate siltstone and shale. At the Kimberlina site, the Vedder Formation depth is 2 km, and its thickness is about 160 m. The overlying Freeman–Jewett Formation, a 100-m thick lower Miocene marine shale and siltstone, provides the upper seal.A facies model of the Vedder Formation surrounding the Kimberlina site (J. Wagoner, personal communication, 2007) provides the basis for the TOUGH2 model. The facies model (Fig. 5 ) is centered at the proposed Kimberlina power plant and covers an area of 125 km2

. Over the entire model area, Vedder Formation thickness ranges from 110 m to 187 m, but within the 2 km surrounding the power plant, thickness only ranges from 150 m to 164 m. The Vedder Formation dips 7 ◦ to the WSW. The facies model uses 180 layers, of equal thickness, to represent the Vedder Formation. Each layer contains 2,500 cells: 50 cells each 250 m wide in the E–W (x ) direction by 50 cells each 200 m long in the N–S ( y ) direction. A facies (either sand or shale) is assigned to each cell, by interpolating sand/shale picks obtained from eight well logs. Because of the limited information available from such a small number of wells, no attempt is made to represent heterogeneity within the individual facies. Overall, the facies model contains about 50% sand and 50% shale, interleaved in a lenticular fashion, with typical lens size 15 m thick and several kilometers in lateral extent. At the location of the proposed injection well, the Vedder Formation is 158 m thick and consists of five sand layers with total thickness 79 m, separated by four shale lenses with total thickness 79 m.

2.3 Numerical Model

The TOUGH2 model (Fig. 6 ) covers roughly the same spatial extent as the facies model. Because the formation dip and thickness are nearly uniform in the vicinity of the power plant


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Fig. 5 Three views of the facies model of the Vedder Formation. The perspective view (top) has no vertical exaggeration, whereas the two cross sections (bottom) have five times vertical exaggeration, to enable sand/shale layering to be seen. In the perspective view, the thick black line segments show the locations of the eight wells used to develop the facies model, the thin black lines are depth contours, and the intersection of the two cross sections marks the location of the injection well in the TOUGH2 simulations

(note that depth contour lines in the perspective view of Fig. 5 are essentially equidistant and linear), the TOUGH2 model is constructed as a tilted plane, with just a single value of thickness (157.5 m) and dip (7 ◦ ). The up-dip direction is 30 ◦ counter-clockwise from the

+x -axis (ENE), corresponding to the WSW down-dip direction. Each TOUGH2-model layer is formed by combining six facies-model layers, resulting in 30 layers, each 5.25 m thick. At the (x , y ) location of each facies-model cell, the facies of the TOUGH2-model layer is taken to be the facies that occurs the most times among the six facies-model layers that are combined to form it. As can be seen by comparing Figs. 5 and 6 , this combining scheme captures the essential features of the lenticular sand/shale structure of the facies model. The computational grid for the TOUGH2 model is shown in Fig. 7 . Laterally, the TOUGH2 model grid-block size varies, with finest grid blocks in the vicinity of the injection well (5 m × 5 m), increasing to 55 m × 55 m in the region where the CO 2 plume is expected to go (roughly an ellipse with a major axis <2 km), and gradually increasing further beyond that region. The lateral extent of the active portion of the TOUGH2 model is 11 km × 11 km, beyond which additional grid blocks are added to represent lateral boundary conditions. The vertical discretization of the TOUGH2 model into 30 layers results in at least two model layers per sand layer, to enable vertical flow arising from buoyancy forces to be resolved. The 5-m width of the grid-block used for the injection well is much greater than an actual well diameter, so the simulation is not expected to accurately reproduce all near-wellbore


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Fig. 6 Three views of the TOUGH2 model of the Vedder Formation. The perspective view (top) has no vertical exaggeration, whereas the two cross sections (bottom) have five times vertical exaggeration, to enablesand/shale layering to be seen. In the perspective view, the thin black lines are depth contours, and the intersection of the two cross sections marks the location of the injection well in the TOUGH2 simulations. Note that the coordinate system has been translated so that the origin is where the injection well intersects the top of the Vedder Formation

effects arising during CO 2 injection. For example, the modeled pressure increase will not bethe actual pressure increase in the wellbore, but an average over 5m of formation surrounding the well. However, the focus of the present paper is on plume-scale effects, and using a grid fine enough to represent an actual wellbore would greatly slow down the simulations. Two features that are not included in the present simulations, thermal effects and intrinsic permeability decrease due to salt precipitation, have their main effect within or close to the wellbore, so neglecting them is consistent with the use of the present grid. The top and bottom boundary of the TOUGH2 model are no-flow boundaries, to represent regionally extensive, continuous shale layers over- and underlying the Vedder Formation. In the x -direction, the lateral boundaries are constant pressure boundaries and in the y -direction the lateral boundaries are no-flow boundaries. These boundary conditions are chosen for numerical convenience rather than geological accuracy. The actual extent of the Vedder Formation is estimated to be 55 km in the east–west direction and 90 km in the north-south direction, far beyond the lateral extent of the TOUGH2 model. As shown in the “simulation results” section, the lateral boundaries are so far away from the injection well and the region the CO 2 plume occupies that they have little impact on the evolution of the CO 2 plume. Table 1 summarizes the geometric properties and boundary conditions of the TOUGH2 model.


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Fig. 7 Three views of the TOUGH2 model of the Vedder Formation showing the computational grid

The initial conditions for the CO 2 injection are a brine-saturated formation with a hydrostatic pressure distribution, and a pressure of 220 bars at the injection well location. Initial temperature and salinity are uniform at 81 ◦ C and 50,000 TDS, respectively. This temperature is calculated assuming a surface temperature of 15 ◦ C and a geothermal gradient of 30 ◦ C per km, both of which are rough estimates considered reasonable for Southern California. In the absence of specific information on salinity for the Vedder Formation, a moderate value of 50,000 TDS is chosen. The primary impact of the initial pressure and temperature is to define the density and viscosity of the CO 2 plume in the subsurface. Density controls not only the volume of the plume, but also the strength of the buoyancy force, which is proportional to the density difference between injected CO 2 and native brine. In conjunction with permeability, viscosity controls how mobile the CO 2 is. The effects of initial pressure and temperature on plume migration are examined elsewhere (Jordan and Doughty 2008 ). According to Fig. 2
, salinity is inversely related to CO 2 solubility. If actual salinity turns out to be lower than 50,000 TDS (values as low as 20,000 TDS have been proposed), a greater fraction of the


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Table 1 Geometric properties and boundary conditions of the TOUGH2 model for the Vedder Formation at the Kimberlina power plant site

Parameter Value Comment

Depth at injection well (m) 2,200 Same as facies model Thickness (m) 157.5 Facies model thickness ranges from 110 m to 187 m Percent sand/shale 50/50 Sand occurs in five distinct layers, with interleaving shales Number of model layers 30 Each model layer 5.25 m thick, combines 6 facies-model layers Lateral extent (km) 11 × 11 Comparable to facies model Lateral grid spacing Varies 5 m × 5 m at injection well; maximum 55 m × 55 m within CO 2 plume footprint Formation dip 7 ◦ Up-dip direction is ENE, 30 ◦ counter-clockwise from + x -axis Boundary Conditions Top and bottom No flow Represent continuous, extensive shale layers Lateral, x -direction Constant pressure Lateral, y -direction No flow

Table 2 Initial conditions and flow properties of CO 2 and brine

Initial condition Value

Initial pressure Hydrostatic pressure distribution; average 220 bars at injection well Initial temperature 81 ◦ C Initial salinity 50,000 mg/L CO 2 solubility in brine 43,000 mg/L Flow property C O 2 Brine Density (kg/m3 ) 632 1,014 Viscosity (Pa-s) 5 · 10 − 5 4 · 10 − 4

injected CO 2 will dissolve and the free-phase plume will be correspondingly smaller. Additionally, lower salinity means smaller brine density, which decreases the driving force for buoyant flow of free-phase CO 2 . Thus, the present simulation results may be considered to be conservative in terms of predicting plume extent and migration. Table 2 summarizes the initial conditions used for the Kimberlina simulations, and the resulting density and viscosity of the injected CO 2 and the native brine. It shows that the injected plume will be strongly buoyant in the subsurface. The material properties used in the base-case TOUGH2 model are summarized in Table 3

.Porosity and permeability values are consistent with the geologic model, but relative permeability and capillary pressure parameters are not known for the Kimberlina site, so parameter values are adapted from other studies of CO 2 geologic storage in saline formations (Doughty 2007 ; Doughty et al. 2008 ). Sensitivity studies then examine the impact of varying permeability, permeability anisotropy (both vertical and lateral), and maximum residual gas saturation. Table 3 shows that the permeability contrast between the sand and shale facies is large; thus CO 2 , which is injected only into sand layers, is expected to remain in the sand layers. The functional forms of the hysteretic characteristic curves (Doughty 2007 ) are based on the van Genuchten ( 1980) formulation.


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Table 3 Material properties of the base-case TOUGH2 model
Property Sand Shale

Porosity 28% 15% Horizontal a permeability, kx , ky 200 md 0.1 md Vertical a permeability kz 20 md 0.01 md Relative permeability parameters Residual liquid saturation S lr 0.2 0.3 Maximum residual gas saturation Sb grmax 0.27 0.29 van Genuchten parameter m 0.917 0.917 Capillary pressure parameters (same for drainage and imbibition branches) Capillary pressure strength P c 0 1.88 · 104 Pa 8.41 · 10 5 Pa van Genuchten parameter m 0.412 0.412

a “Horizontal” means parallel to layering; “vertical” means perpendicular to layering b Residual gas saturation S  gr is zero during drainage and non-zero during imbibition, where it depends on saturation history and has a maximum value of Sgrmax

The CO 2 injection well is located at the center of the model and penetrates the entire Vedder Formation thickness. Because the TOUGH2 model does not include an actual wellbore model (recall that lateral grid spacing at the injection well location is 5m × 5m), injectionis modeled as a mass source distributed among the sand layers, with source strength proportional to layer thickness. Altogether, 250,000 T/year is injected for a period of 4 years, resulting in 1,000,000 metric tons of CO 2 injected.

3 Simulation Results

The TOUGH2 simulations cover the 4-year injection period and at least 100 years thereafter, when CO 2 is subject only to gravity and capillary forces. All simulations use the computational grid as shown in Fig. 6 and the properties shown in Tables 1 and 2 . Base-case simulations use the properties as shown in Table 3 , while sensitivity studies consider alternative values whose ranges reflect the uncertainty of our knowledge of actual properties.

3.1 Base Case

3.1.1 Supercritical CO 2
Figures 8 and 9 show snapshots of the supercritical CO 2 plume at various times. Figure 8 shows a plan view of the uppermost layer of the model, which is the layer in which the greatest lateral extent of CO 2 occurs. Figure 9 shows x

− z cross-sections through the model, and illustrates the formation of five sub-plumes in the five sand layers within the Vedder Formation. Note from Fig. 8 that the x

− z plane does not show the maximum lateral extent of CO 2 , which occurs in the up-dip direction. Together, Figs. 8 and 9 illustrate the strong buoyancy flow that moves CO 2 to the top of each sand layer, and from there moves the plume up-dip. Key measures of the CO 2 plume are its up-dip extent at stabilization and the time evolution of the partitioning of CO 2 between dissolved, immobile-gas, and mobile-gas forms. In the present study, plume stabilization is defined as occurring when two successive snapshots show no advance of the leading edge of the plume. Figure 8 shows that the base-case plume


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Fig. 8 Top view of the base-case supercritical CO 2 plume at a series of times, shown by plotting Sg , saturation of supercritical CO 2 , in the uppermost model layer. During injection, the rectilinear grid produces minor numerical artifacts in the plume distribution by enabling enhanced flow along the grid axis directions

Fig. 9 East–west cross section of the base-case supercritical CO 2 plume at a series of times, shown by plotting Sg , saturation of supercritical CO 2 , in the plane y = 0

has stabilized by 25 years, at which time it is about 1,500 m long, 900 m wide, and extends 1,300 m up-dip of the injection well. Quantification of the trapping and stabilization process is presented in Fig. 10 , which shows the time evolution of the CO 2 mass distribution for the entire model. The total amount of CO 2 injected is divided into two parts, i.e., a gas-like supercritical phase and a dissolved phase. The supercritical phase is further divided into mobile and immobile portions, with CO 2 immobile when its saturation is below residual gas saturation S  gr . Throughout the injection period, about 20% of the CO 2 dissolves, and essentially all the supercritical-phase


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Fig. 10 Time evolution of the CO 2 mass distribution for the entire model for the base-case (thick lines) and sensitivity-study case SH4, which models the Vedder Formation as a homogeneous, isotropic sand (thin lines)

CO 2 is mobile. After injection ends, the dissolved fraction increases gradually to 38% as the plume moves up-dip and encounters new under-saturated brine. This up-dip movement is accompanied by residual CO 2 trapping, and Fig. 10 shows how the mobile fraction of supercritical CO 2 decreases concurrent with the increase of the immobile fraction. By 25 years the supercritical CO 2 is largely immobile, coinciding with the stabilization of the plume as shown in Fig. 8 . Thereafter, the plume does not move as a whole, but subtle redistributions of the immiscible phase further decrease the mobile fraction and dissolution of supercritical CO 2 continues, slowly increasing the dissolved fraction. The supercritical plume has nearly completely dissolved by 10,000 years. Insight into residual CO 2 trapping can be obtained by examining the spatial distribution of drainage and imbibition at a series of times during and after injection. Figure 11 displaysICURV, the variable identifying which branch of the capillary pressure curve is being followed, for each grid block in the uppermost model layer. Recall that residual CO 2 trapping requires a non-zero value of residual gas saturation, which only occurs during imbibition. Nearly the entire plume is undergoing drainage just after the injection period ends, except for a narrow imbibition zone at the trailing (down-dip) edge of the plume. The imbibition zone grows steadily until 25 years, when drainage is limited to a few grid blocks at the leading (up-dip) edge of the plume, at which time the plume has stabilized. Thereafter, the zone of drainage gradually shrinks further, until it has disappeared by 100 years. Because imbibition dominates the plume for most of the post-injection period, the residual gas saturation S  gr is non-zero over much of the plume (Fig. 12), enabling significant residual CO 2 trapping. The S  gr distribution does not change after the plume stabilizes at 25 years. Figure 13 shows the spatial distribution of ( Sg − S  gr ), the difference between gas saturation and residual gas saturation. The larger the value of ( Sg − S  gr ), the more mobile the plume is (Fig. 3 ). There is a sharp decrease in mobility at the transition from drainage ( S  gr = 0) to imbibition ( S  gr > 0) at 4, 5, and 7 years (compare to Figs. 11 and 12). From 10 years on, ( Sg − S  gr ) is very small throughout the plume. Beginning at 20 years, negative values of ( Sg − S  gr ) develop, which can only happen if immobile free-phase CO 2 is dissolving. Continued dissolution of immobile CO 2 implies that the brine must be moving, because quiescent brine adjacent to immobile free-phase CO 2 would quickly saturate, precluding further


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Fig. 11 Top view of base-case distribution of drainage and imbibition at a series of times: ICURV = 0—singlephase liquid, 1—primary drainage, 2—first-order imbibition, 3—second-order drainage, and 4—third-order imbibition

dissolution. The present simulations do not include regional groundwater flow, so the only driving force for brine movement is natural convection, arising from the small brine density increase that occurs when CO 2 dissolves. The banded character of the negative ( Sg − S  gr ) values evident at 500 and 1,000 years suggests the formation of convection cells in the brine underlying the free-phase CO 2 , with the top of each cell (where lighter CO 2 -free native brine up-wells) coincident with a band of enhanced dissolution.

3.1.2 Dissolved CO 2
Before investigating the natural convection of CO 2 -laden brine, it is worthwhile to examine further how the free-phase CO 2 and dissolved CO 2 interact. Figure 14 shows a vertical cross-section of the storage formation in the vicinity of the injection well at 4 years, the end of the injection period. The top frame shows free-phase CO 2 , the second frame shows CO 2 dissolved in the brine, the third frame shows the NaCl dissolved in the brine, and the bottom frame shows precipitated NaCl. Dissolved species are shown as mass fractions in


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Fig. 12 Top view of base-case distribution of residual gas saturation S  gr at a series of times (colors). Contour lines show supercritical CO 2 saturation Sg , illustrating the spatial distribution of the plume itself the aqueous phase, whereas precipitated NaCl is shown as solid saturation S s (i.e., the pore volume fraction of precipitated NaCl). For the most part, the spatial distribution of dissolved CO 2 coincides with that of freephase CO 2 . The one exception is close to the injection intervals where Sg is large. In these locations, strong capillary forces arising from large values of Sg draw brine toward the well. Near the well, some of the water evaporates into the supercritical CO 2 phase, increasing dissolved NaCl content in the remaining brine. There is an inverse correlation between NaCl content and CO 2 solubility (Fig. 2), resulting in the regions of low dissolved CO 2 near theinjection intervals. Otherwise, the close correspondence between the spatial extents of freephase and dissolved CO 2 indicates that natural convection of brine is negligible at this time. Recall that aqueous-phase diffusion is not included in these simulations. The slight extension of the dissolved-CO 2 plume beyond the free-phase plume visible in Fig. 14 is likely due to numerical dispersion. Figure 15 shows dissolved CO 2 distributions at 25, 100, and 500 years. With time, spatial distributions of dissolved and free-phase CO 2 increasingly differ, confirming that natural convection of CO 2 -laden brine is significant, and the convection cells themselves are illustrated by the irregular distribution of dissolved CO 2 in the up-dip region of the top sand layer at 100 and 500 years. The low-permeability shales separating each of the five sub-plumes, constrain the bulk of the brine flow to the sand layers. Flow is greater down-dip, but up-dip flow into the deeper parts of each sand layer is also evident. At times beyond 500 years (not shown), down-dip migration of dissolved CO 2 continues, but its up-dip extent does not change appreciably. At the final simulation time (10,000 years) the dissolved CO 2 plume extends about 4 km down-dip from the injection well.

3.1.3 Pressure Response

Figure 16 compares the lateral extent of the pressure response to CO 2 injection with the lateral extent of the CO 2 plume itself. The profiles show pressure change and gas saturation in the


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Fig. 13 Top view of base-case distribution of ( Sg − S  gr ) at a series of times (colors). Contour lines show Sg , saturation of supercritical CO 2 , illustrating the spatial distribution of the plume itself. Note that different color maps are used for the first four frames and for the final eight frames, where all negative values of ( Sg − S  gr ) are shown in dark blue

uppermost layer in the model, along a transect beginning at the injection well and extending in the up-dip direction. During the injection period, pressure close to the injection well does not increase monotonically with time. This occurs because the viscosity of injected CO 2 is much lower than that of the native brine (Table 2), and as the CO 2 plume grows there is less resistance to flow, so less pressure increase in response to the constant CO 2 injection rate. After injection ends, CO 2 saturation decreases as the plume stretches out, with the leading edge of the CO 2 plume moving up-dip and the maximum pressure increase moving along with it. Although the pressure response extends far beyond the CO 2 plume, the pressure response


# 123Investigation of CO 2 Plume Behavior for a Large-Scale Pilot Test of Geologic Carbon 65

Fig. 14 East–west cross-section of the base-case plume in the plane y = 0 at 4 years: a Sg shows saturation of supercritical CO 2 ; b XCO 2 L shows the mass fraction of CO 2 dissolved in the aqueous phase; c XNaCl shows the mass fraction of NaCl dissolved in the aqueous phase; d S s shows saturation of precipitated NaCl. The black contour lines show Sg = 0, illustrating the maximum extent of the supercritical plume

beyond the CO 2 footprint is small (<1.5 bars). Moreover, pressure response decreases as distance from the injection well increases, and quickly dissipates after injection ceases (<1 bar everywhere 1 year after injection ends). Recall that the base-case model assumes partially open (constant-P), partially closed(no flow) boundary conditions. Two additional simulations, assuming either all-open or allclosed lateral boundary conditions, produce identical CO 2 plumes, and only slightly different pressure responses. During the injection period, pressure responses are similar for all the cases. Only near the lateral boundary does the all-closed case differ significantly, with a pressure increase of just over 0.2 bars (the pressure response at the open boundaries is guaranteed to be zero). After injection ceases, the pressure change at all distances decreases to near zero for the base case (Figure 16 ) and the all-open case (not shown) within 20 years. In contrast, for the closed case, the pressure change becomes uniform in space at a value just below 0.3 bars.


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Fig. 15 Late-time (i.e., post-stabilization) distributions of base-case dissolved CO 2 , shown by plotting XCO 2 L , the mass fraction of CO 2 dissolved in the aqueous phase, in the plane y = 0. The black contour lines show Sg = 0, illustrating the maximum extent of the supercritical plume 3.2 Sensitivity Studies

Most of the material properties used as input to the base-case numerical simulation are not well known. To assess the impact of parameter uncertainty on plume evolution and trapping mechanisms, sensitivity studies are carried out using alternative parameter choices for poorly known parameters. Table 4 summarizes the cases and the key performance measures for each. Figure 17 shows a plan view of the top of the stabilized plume for each case. The time variation of the mass of mobile CO 2 (Fig. 10) shows an initial rapid decrease after injection ends followed by a very slow approach to zero, which does not provide a convenient means for determining when a plume has stabilized. It is clear from the time series of CO 2 distributions (Fig. 8 ) that the plume does not move perceptibly after 25 years, even though mobile CO 2 remains. Rather than trying to find a threshold mass of mobile CO 2 that defines stabilization, the CO 2 distributions are used directly, and stabilization is defined as occurring when two successive distributions are indistinguishable. However, it is also useful to compare among cases how long it takes to reach a given amount of mobile CO 2 . The “time to 3% mobile CO 2 ” entry in Table 4 serves this purpose. The value of 3% is used because all the cases reach it within the simulation period (typically 100 years). Table 4 indicates that there is generally a good correlation between the “time to 3% mobile CO 2 ” and “time of plume stabilization” entries; therefore, they are often referred to collectively as time measures for plume mobility.

3.2.1 Sand Anisotropy Studies

The base-case model assumes that vertical permeability is 1/10th of horizontal permeability, a common assumption for sands with permeability in the hundred millidarcy range. Assuming


# 123Investigation of CO 2 Plume Behavior for a Large-Scale Pilot Test of Geologic Carbon 67

Fig. 16 Pressure change and supercritical CO 2 saturation Sg versus up-dip distance from the injection well at a series of times, for the base-case

an isotropic medium (Case AN1) produces only subtly different plume evolutions: comparable time measures for plume mobility, only 50 m more up-dip migration, and similar percent dissolved CO 2 . This insensitivity largely arises from the sand/shale layering, which creates five sub-plumes in the sand layers, and thereby limits the amount of buoyancy flow that can occur. A change by a factor of ten in permeability anisotropy has a much greater effect for a homogeneous sand formation (see Cases SH3 and SH4 below).The region surrounding the Kimberlina site contains numerous small faults trending generally north–south. Whether these faults act as conduits or barriers to flow, their net effect is likely to be a lateral (x : y ) anisotropy in sand permeability with a greater permeability in the north–south ( y ) direction. Cases AN2 and AN3, with a 3:1 and 10:1 y : x anisotropy ratio, respectively, show that the direction of plume migration shifts dramatically from the up-dip direction (30 ◦ north of due east) toward the north. For the 10:1 anisotropy ratio, the time measures for plume mobility are shorter and up-dip plume extent and percent dissolved


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Table 4 Summary of sensitivity studies
Case Key Features Time to 3% mobile CO 2 (years) Time ofplume stabilization (years) Up-dip migration distance atstabilization (km) Percent dissolvedat stabilization

Base-case kx = ky = 200 md, 23 25 1.30 38 kz = 20 md, Sgrmax = 0.27 Sand anisotropy studies AN1 Isotropic 22 25 1.35 39 permeability kx = ky = kz = 200 md AN2 Lateral permeability 23 25 1.50 39 anisotropy kx = ky /3,

< kx ky > g = 200 md, kz = 20 md AN3 Lateral permeability 21 20 2.50 41 anisotropy kx = ky /10,

< kx ky > g = 200 md, kz = 20 md Sand permeability studies a SA1 Very low 94 85 0.70 32 permeability kx = ky = 20 md, kz = 2 md SA2 Low 37 50 1.00 34 permeability kx = ky = 66 md, kz = 6.6 md SA3 High 16 20 2.00 45 permeability kx = ky = 500 md, kz = 250 md SA4 Very high 12 15 2.50 52 permeability kx = ky = kz = 1,000 md Shale permeability studies a SH1 Medium-permeability 29 25 1.30 39 shale kx = ky = 2 md, kz = 0.2 md SH2 High-permeability 20 40 1.50 38 shale kx = ky = 20 md, kz =2 md SH3 No shale 27 25 1.80 33 kx = ky = 200 md, kz =20 md SH4 No shale 32 40 2.20 33 kx = ky = kz = 200 md



# 123Investigation of CO 2 Plume Behavior for a Large-Scale Pilot Test of Geologic Carbon 69

Table 4 continued Case Key Features Time to 3% mobile CO 2 (years) Time ofplume stabilization (years) Up-dip migration distance atstabilization (km) Percent dissolvedat stabilization

Residual gas saturation studiesb SG1 High residual gas saturation 10 15 1.05 32 Sgrmax = 0.40 SG2 Medium-high residual gas saturation 19 25 1.20 37 Sgrmax = 0.30 SG3 Medium-low residual gas saturation 45 25 1.45 43 Sgrmax = 0.20 SG4 Low residual gas saturation 114 30 1.80 53 Sgrmax = 0.10

a When permeability decreases, capillary pressure strength P c 0 and Sgrmax increase b Here, only Sgrmax is varied

CO 2 are greater, which are features common to the high sand permeability cases described below.

3.2.2 Sand Permeability Studies

Sand horizontal permeability values ranging from 20 md to 1000 md are considered here (Cases SA1, SA2, SA3, and SA4). In our conceptual model, when sand permeability k increases, the vertical to horizontal permeability ratio kz / kx increases, capillary pressure strength P c 0 decreases as P c 0 ∼ k

− 1 / 2 , and maximum residual gas saturation Sgrmax decreases as Sgrmax = 0

. 48

− 0

. 04 ln(k), with k in md, which is adapted from correlations developed by (Holtz
, 2002 , personal communication, 2003), based on Gulf Coast sandstone literature. Increasing sand permeability has a strong effect on the plume performance measures shown in Table 4 , with up-dip plume extent and percentage of dissolved CO 2 increasing, whereas time measures for plume stability and maximum CO 2 saturation decrease. All these effects are a consequence of the greater buoyancy flow enabled by larger permeability. Larger up-dip plume extent means more brine is encountered by the plume, and so more dissolution occurs. Since the trailing (down-dip) edge of the plume is trapped, larger up-dip extent means the plume is stretched out more, and hence CO 2 saturation is lower, leading to greater residual CO 2 trapping, less mobile CO 2 , and earlier stabilization. It should be noted that while well logs from the Kimberlina region do show sand permeabilities even higher than 1000 md and even lower than 20 md, it is not known how regionally extensive such extreme features are.

3.2.3 Shale Vertical Permeability Studies

Shale vertical permeability largely controls the vertical distribution of CO 2 within the storage formation, as shown in Fig. 18 . In the base case (Fig. 9 ), shale permeability is so low and capillary pressure strength is so high that supercritical CO 2 is effectively excluded from shale lenses. Cases SH1, SH2, SH3, and SH4 consider larger shale permeabilities, which are intended to represent sub-grid-scale heterogeneity in which sand and shale interfinger at


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Fig. 17 Top view of stabilized supercritical CO 2 plumes for all cases, shown by plotting Sg , saturation of supercritical CO 2 , in the uppermost model layer. The time to stabilization is shown for each case

scales that are less than the 55-m grid size. P c 0 and Sgrmax values are correlated to permeability using the same relations given for sand above. In the limiting case (Cases SH3 and SH4), shale lenses are assigned pure sand properties; therefore, shale is actually absent, and the Vedder Formation is modeled as a homogeneous sand layer. In these cases, buoyancy flow is much stronger, resulting in much greater upward migration of CO 2 . This is especially true for Case SH4, in which the vertical permeability equals the horizontal permeability. For Case SH2, with shale permeability ten times smaller than that of sand permeability, supercritical CO 2 preferentially flows into sand layers, but does move into shale lenses as well. The Case SH2 plume shows more buoyancy flow than the base case, but not nearly as much as when the shale lenses are absent. For Case SH1, with a shale permeability 100 times smaller than that of sand permeability, the CO 2 distribution is indistinguishable from that of the base case, which has a shale permeability 2000 times smaller than that of sand permeability. Increasing shale permeability has a strong effect on the plume performance measures shown in Table 4 , with up-dip plume extent increasing and percent dissolved CO 2 decreas
# 123Investigation of CO 2 Plume Behavior for a Large-Scale Pilot Test of Geologic Carbon 71

Fig. 18 East–west cross-section of the supercritical CO 2 plume at two times for sensitivity-study cases with different values of shale vertical permeability, shown by plotting Sg , saturation of supercritical CO 2 , in the plane y = 0. Compare to base-case cross sections in Fig. 9

ing. Both these effects are a consequence of the more localized flow that occurs when the shale lenses do not divide the CO 2 into multiple plumes. CO 2 saturation in the single plume is higher than that in the five individual plumes, and so residual CO 2 trapping is diminished and up-dip migration is enhanced. Dissolution trapping also decreases, which is a consequence of the smaller CO 2 /brine contact area. Since the presence or absence of shale lenses so strongly impacts the evolution of the supercritical CO 2 plume, it is useful to examine the behavior of dissolved CO 2 , in the noshale case as well. Figure 19 shows dissolved CO 2 distributions for the Case SH4, in which the Vedder Formation is modeled as a homogeneous isotropic sand layer. As for the base case (Fig. 14 ), at the end of the injection period, the dissolved CO 2 distribution correlates closely with the supercritical CO 2 distribution. Thereafter, the two distributions differ significantly, as natural convection of the brine begins. Comparing Fig. 19 with Fig. 15 shows that the absence of shale lenses greatly enhances natural convection compared to the base case, which in turn enhances late-time dissolution. The integrated mass distribution in Fig. 10 illustrates how the Case-SH4 dissolved fraction, which is less than the base-case dissolvedfraction when the plumes stabilize, later becomes significantly greater than it. The supercritical plume has nearly completely dissolved by 1,300 years, far sooner than the base-case dissolution time of 10,000 years. Numerical studies of brine convection (Pruess and Zhang 2008 ) using much finer grid resolution than this study indicate that the details of convection (e.g., how many convection


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Fig. 19 East–west cross-section of the dissolved CO 2 plume at a series of times for sensitivity-study Case SH4, shown by plotting X CO 2 L , mass fraction of CO 2 in the aqueous phase, in the plane y = 0. Case SH4 models the storage formation as a homogeneous isotropic sand layer. The black contour lines show Sg = 0, illustrating the maximum extent of the supercritical plume

cells, individual cell locations) are quite sensitive to grid spacing, but integrated measures, such as how much CO 2 crosses a given horizontal interface, are not. Since the lateral grid resolution (55 m over most of the plume) is so coarse, the results shown in Fig. 19 should not be considered as precise predictions of dissolved CO 2 movement, but rather provide an indication of the overall magnitude of convective transport.

3.2.4 Residual Gas Saturation Studies

Unlike permeability sensitivity studies, in which a range of property values are used because of limited knowledge of subsurface property distributions, for residual gas saturation, thereis even significant uncertainty in our conceptual model. To a large extent, we rely on experience with other multiphase systems, primarily from the petroleum literature, in which maximum residual gas saturation Sgrmax is significantly above zero. The relatively few studies of CO 2 /brine systems (e.g., Bachu and Bennion 2008 ; Benson et al. 2007 ; Doughty et al. 2008 ) support this approach, but residual CO 2 trapping is such an important process for immobilizing plumes in the absence of structural traps that further study is needed. Therefore, Sgrmax is treated as an independent parameter, and the effect of decreasing it from the base-case value is examined (Cases SG1, SG2, SG3, and SG4). Decreasing Sgrmax has a strong effect on the plume performance measures shown in Table 4 , producing greater up-dip migration and increased time measures for plume mobility because of the diminished residual CO 2 trapping ability. In contrast, the additional up-dip migration enables more dissolution to occur.


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4 Conclusions

The evolution of the CO 2 plume formed during a large-scale pilot test for geologic CO 2 storage in a moderately dipping saline aquifer has been modeled using the numerical simulator TOUGH2. Simulation results show that for the base-case, about 20% of the 1,000,000 metric tons of injected CO 2 is in dissolved form at the end of the 4-year injection period, and this percent increases to 38% by the time the CO 2 plume stabilizes at 25 years. At stabilization, of the 62% of the plume that exists as supercritical free phase, only 3% is mobile. From thistime onward, plume evolution consists solely of slow dissolution, aided by natural convection of dissolved-CO 2 -laden brine. The stabilized plume footprint is roughly elliptical, and is strongly asymmetric about the injection well, extending 1,300 m in the up-dip direction and 200 m in the down-dip direction. The pressure increase in response to CO 2 injection extends far beyond the plume footprint, reaching the model boundaries 8 km away from the injection well. However, the pressure response decreases rapidly with distance from the injection well, and decays rapidly in time once injection ceases.Sensitivity studies show that uncertain model parameters permeability anisotropy, permeability itself, and maximum residual gas saturation strongly affect the direction and extent of CO 2 plume movement, demonstrating the importance of site characterization efforts to better constrain these parameters prior to CO 2 injection. Even a subtle sand lateral permeability anisotropy strongly affects plume migration direction. Sand vertical permeability anisotropy does not have much effect on plume shape when shale lenses are present, but the opposite is true for a storage formation composed solely of sand, where vertical anisotropy plays a dominant role controlling buoyancy flow of both light free-phase CO 2 and heavy dissolvedCO 2 -laden brine. Even the presence of a small amount of shale, as represented by shale lenses with permeability only ten times smaller than that of sand, greatly diminishes upward buoyancy flow of free-phase CO 2
. Figure 20 summarizes the results shown in Table 4 graphically, demonstrating the tradeoffs in trapping mechanisms that occur as sand permeability, shale permeability, and residual gas saturation are varied. As sand permeability increases (Fig. 20 a), up-dip buoyancy flow is enhanced so up-dip plume migration increases. Dissolution trapping increases as more brine is exposed to free-phase CO 2 . Residual CO 2 trapping ability decreases insofar as Sgrmax decreases with increasing permeability, but the two time measures for plume mobility—time to 3% mobile CO 2 and time to plume stabilization—decrease significantly as sand permeability increases. This indicates that the lower CO 2 saturation resulting from greater spreading of the plume leads to more rapid residual CO 2 trapping, despite the lower Sgrmax values. As shale permeability increases (Fig. 20b), enhanced upward flow enables the five individual plumes to coalesce into a single plume that rises to the top of the formation, and thereafter spreads up-dip (Fig. 18 ). This more localized flow enables CO 2 saturation in the single plume to remain higher than in the five individual plumes, and so residual CO 2 trapping is diminished and up-dip migration is enhanced. Dissolution trapping also decreases slightly in response to the coalescence into a single plume, as the higher CO 2 saturation results in a more compact plume and thus smaller CO 2 /brine contact area. The time measures for plume mobility still roughly track together, and show only a slight increase with shale permeability. Finally, if Sgrmax values are typically smaller than the presently-accepted ones (Fig. 20c), residual CO 2 trapping decreases, leading to greater up-dip migration, increased time measures for plume mobility, and more dissolution trapping. For small values of Sgrmax , time to 3% mobile CO 2 becomes much longer than time to plume stabilization, because the threshold for absolute immobility ( Sgrmax ) becomes much harder to reach even though the relative permeability of the plume as a whole is small enough for the plume to stabilize.


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Fig. 20 Summary of the sensitivity study results for (a) sand horizontal permeability when low-permeability shale layers are present; (b) shale vertical permeability; and (c) residual gas saturation Sgrmax



# 123Investigation of CO 2 Plume Behavior for a Large-Scale Pilot Test of Geologic Carbon 75

The sedimentary basin that forms California’s Central Valley provides a huge potential capacity for geologic carbon storage, and the geologic stratigraphy suggests that the dipping planar structure of interleaved sands and shales that characterizes the Kimberlina model is likely very common. For the longer injection periods and much greater CO 2 volumes associated with full-scale CO 2 storage, plume migration distance will be greater and time to stabilization will be longer, but the conclusions about the interaction of trapping mechanisms drawn from this study may still be widely useful for storage locations with limited knowledge of reservoir flow parameters.

Acknowledgements Thanks are due to Jeff Wagoner of Lawrence Livermore National Laboratory for providing the geological and facies models of the Kimberlina site, to Preston Jordan for additional information on faulting, and to Larry Myer and Curt Oldenburg for insightful discussions. The careful review of this article by Kenzi Karasaki and two anonymous reviewers is appreciated. This study was supported in part by WESTCARB through the Assistant Secretary for Fossil Energy, Office of Sequestration, Hydrogen, and Clean Coal Fuels, National Energy Technology Laboratory (NETL), and by Lawrence Berkeley National Laboratory under U.S. Department of Energy Contract No. DE-AC02-05CH11231.

Open Access This article is distributed under the terms of the Creative Commons Attribution Noncommercial License which permits any noncommercial use, distribution, and reproduction in any medium, provided the original author(s) and source are credited.

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