Kentucky Geological SurveyUniversity of Kentucky, Lexington

Modeling Potential Impacts of SO2 Co-injected With CO2 on the

Knox Group, Western Kentucky

Junfeng Zhu and David C. Harris

Contract Report 85 Series XII, 2016

© 2006University of Kentucky

For further information contact:Technology Transfer OfficerKentucky Geological Survey

228 Mining and Mineral Resources BuildingUniversity of Kentucky

Lexington, KY 40506-0107

ISSN 0075-5591

Technical Level

General Intermediate Technical

Our MissionOur mission is to increase knowledge and understanding of the mineral, energy, and water resources, geologic hazards, and geology of Kentucky for the benefit of the Commonwealth and Nation.

Earth Resources—Our Common Wealth

www.uky.edu/kgs

Technical Level

General Intermediate Technical

ContentsAbstract .........................................................................................................................................................1Executive Summary ....................................................................................................................................1Introduction .................................................................................................................................................2The Knox Group ..........................................................................................................................................5Modeling Method .......................................................................................................................................5Model Setup .................................................................................................................................................5Model Results and Discussion ..................................................................................................................8Conclusions ................................................................................................................................................11Acknowledgments ....................................................................................................................................14References Cited ........................................................................................................................................14

Figures 1. (a) Location map and (b) stratigraphic column showing geology of the Precambrian–

Ordovician segment of the CO2 injection well ...........................................................................3 2. Graphs showing simulated changes in aqueous species along the radial distance at

different times using the 1-D model for the Beekmantown Dolomite: (a) pH, (b) Ca2+, (c) SO42–, (d) Mg2+, and (e) HCO3– .................................................................................................9

3. Graphs showing simulated changes in minerals along the radial distance at different times using the 1-D model for the Beekmantown Dolomite (in the Y axis, positive indicates precipitation and negative indicates dissolution): (a) dolomite, (b) anhydrite, (c) dawsonite, (d) quartz, (e) kaolinite, and (f) illite ...............................................................10

4. Graphs showing simulated changes in (a) permeability and (b) porosity along the radial distance at different times using the 1-D model for the Beekmantown Dolomite .11

5. Graphs showing simulated changes in aqueous species along the radial distance at different times using the 1-D model for the Gunter Sandstone: (a) pH, (b) Ca2+, (c) SO42–, (d) Mg+, and (e) HCO3– ................................................................................................12

6. Graph showing simulated changes in minerals along the radial distance at different times using the 1-D model for the Gunter Sandstone (in the Y axis, positive indicates precipitation and negative indicates dissolution): (a) dolomite, (b) anhydrite, (c) dawsonite, (d) quartz, (e) K-feldspar, (f) illite, and (g) calcite ..............................................13

7. Graphs showing simulated changes in (a) permeability and (b) porosity along the radial distance at different times using the 1-D model for the Gunter Sandstone .............14

8. Graphs comparing simulated changes in porosity with different initial porosity: (a) the Beekmantown model and (b) the Gunter model ..............................................................15

Tables 1. Water chemistry for the original and SO2-bearing brines ........................................................6 2. Hydrogeologic parameters for 1-D radial models ....................................................................6 3. Initial mineral assemblages and secondary minerals ...............................................................7 4. Kinetic parameters for minerals ..................................................................................................7

1

Modeling Potential Impacts of SO2 Co-injected With CO2 on the

Knox Group, Western Kentucky

Junfeng Zhu and David C. Harris

Executive SummaryThe Cambrian-Ordovician Knox Group, a

thick sequence of dolostone with minor dolomitic sandstone in western Kentucky, has been evalu-ated as a prospective CO2 sequestration target. The CO2 storage potential of the Knox Group was stud-ied through a field test site, where a 2,477-m-deep test well was drilled and 626 metric tons of CO2 was injected. Rock cores, brine samples, and geophysi-cal logs were also taken from the test well to study geology, brine chemistry, mineralogy, seal-rock in-tegrity, and long-term physical and chemical fate of injected CO2. As a part of the CO2 storage evalu-ation study, the potential long-term impacts of SO2

when co-injected with CO2 on the Knox deep saline reservoirs was evaluated.

Understanding potential long-term impacts of CO2 impurities, such as sulfur and nitrogen compounds, on deep carbon-storage reservoirs is of considerable interest because co-injection of the impurities with CO2 can bring significant economic and environmental benefits. In this study, a mod-eling approach was used to evaluate long-term chemical and physical interactions among forma-tion rocks, brines, and co-injected CO2 and SO2. TOUGHREACT, a simulation program, was used to build separate 1-D radial models for the Beek-mantown Dolomite and the Gunter Sandstone, two primary reservoirs identified in the Knox. The 1-D

AbstractUnderstanding potential long-term impacts of CO2 impurities, such as sulfur and

nitrogen compounds, on deep carbon-storage reservoirs is of considerable interest be-cause co-injection of the impurities with CO2 can bring significant economic and environ-mental benefits. The Cambrian-Ordovician Knox Group, a thick sequence of dolostone (Beekmantown Dolomite) with minor dolomitic sandstone (Gunter Sandstone), in west-ern Kentucky, has been evaluated as a prospective CO2 sequestration target. In this study, TOUGHREACT was used to build 1-D radial models to simulate the potential impacts of co-injected CO2 and SO2 on minerals, pore fluids, and porosity and permeability in the Beekmantown Dolomite and the Gunter Sandstone. Co-injection of a mass ratio of 2.5 percent SO2 and 97.5 percent CO2, representative of flue gas from coal-fired plants, was simulated, and the co-injection simulations were compared to models with CO2-only in-jections. The model results suggest that the major impacts of added SO2 for both the Beek-mantown and the Gunter rocks were significant enhancement of dissolution of dolomite and precipitation of anhydrite, leading to noticeable increases in porosity and permeabil-ity. The Gunter Sandstone appeared to be more active with SO2 than the Beekmantown Dolomite was. More dolomite was dissolved in the Gunter than in the Beekmantown with the same SO2 impurity. Consequently, porosity was raised more in the Gunter than in the Beekmantown. On the other hand, the impacts on aluminosilicate minerals appeared to be insignificant in both reservoirs, slightly changing the rates of precipitation/dissolu-tion, but the overall reaction paths remained the same.

2 Introduction

models were built mostly on field data collected from the test well. Co-injection of a mass ratio of 2.5 percent SO2 and 97.5 percent CO2, representa-tive of flue gas from coal-fired plants, was simulat-ed, and the co-injection models were compared to models with CO2-only injections. To accommodate co-injection of CO2 and SO2 in TOUGHREACT, 0.8 mol/kg of water of SO2 was dissolved in the original formation brines, and the SO2-containing brines were then co-injected with CO2. Each model simulated an injection period of 16 hr and subse-quent reaction period of 10,000 yr.

The model results suggest that added SO2 cre-ated an acidic zone near the injection well in both reservoirs through a disproportionation reaction, and the acidic zone enhanced dissolution of do-lomite and precipitation of anhydrite, leading to noticeable increases in porosity and permeability. The added SO2 changed brine chemistry, decreas-ing concentration of Ca+ and increasing concentra-tions of SO42– and Mg2+. The acidic zones appeared to be buffered rather quickly, but the changes in aqueous species remained for a long time. On the other hand, the impacts on aluminosilicate miner-als appeared to be insignificant in both reservoirs, slightly changing the rates of precipitation/disso-lution, but the overall reaction paths remained the same.

The Gunter Sandstone appeared to be more active with SO2 than the Beekmantown Dolomite was. With the same SO2 impurity, more dolomite was dissolved in the Gunter than in the Beekman-town. Consequently, porosity was raised more in the Gunter than in the Beekmantown. Additional comparison model runs with different inputs in reservoir physical properties suggested that the difference in reservoir response to SO2 was likely controlled by geochemical characteristics rather than physical properties of the reservoirs.

Although a representative SO2 impurity was used in this study, the degree of interactions among SO2, the formation brines, and the reservoir rocks should be considered a rough approximation. The handling of SO2 impurity in TOUGHREACT required the SO2 to be totally dissolved in brine, which exaggerated the amount of SO2 available for interacting with the reservoirs. The exaggeration would be especially high for large-scale injection

scenarios in which injected SO2 would be expected to remain in gas phases for a long period of time.

The model results presented here should be considered explanatory, aiming to illustrate pos-sible major physical/geochemical alterations in the two deep carbon reservoirs because of the added SO2. The 1-D radial models were highly simplified, treating both reservoirs as homogeneous in physi-cal and geochemical properties. Field conditions are certainly more complex, which may greatly change physical flow and chemical reaction path. Because of the highly simplified assumptions used in these 1-D models and limitations of TOUGHRE-ACT, the results should be considered qualitative.

IntroductionThe Cambrian-Ordovician Knox Group in

parts of the southern Illinois Basin is considered a potential target for CO2 geologic sequestration. The Knox Group consists of predominantly dolo-mite with a thin section of dolomitic sandstone and is generally assessed as a part of the seal rocks for the underlying Mount Simon Sandstone, a leading CO2 sequestration target in the Midwest Region. However, the Mount Simon Sandstone is either too thin, too deep, or has limited porosity and perme-ability in the southern Illinois Basin in Kentucky. Porous and permeable zones have developed in the interbedded sandstones, vuggy dolomite, and fractured dolomites in the Knox Group (Greb and others, 2009). The CO2 storage potential of the Knox Group in western Kentucky was evaluated through a field test site, where a 2,477-m-deep test well was drilled and 626 metric tons of CO2 was injected (Fig. 1). Rock cores, brine samples, and geophysical logs were also taken from the test well to study geology, brine chemistry, mineralogy, and seal-rock integrity (Bowersox, 2013, in press; Bow-ersox and Williams, 2014).

In particular, Zhu and others (2013) mod-eled long-term chemical and physical interactions among injected CO2, brine, and the Knox Group rocks for the CO2 injection test and for a hypotheti-cal long-term injection, in which the injected CO2 was considered 100 percent pure. However, one of the major CO2 sources for deep geologic storage is coal-fired power plants, which also emit small quantities of impurities such as SOx, NOx, and H2S in the flue gas. Injecting CO2 with impurities is an

3Introduction

Figu

re 1

. (a)

Loc

atio

n an

d (b

) geo

logy

of t

he P

reca

mbr

ian–

Ord

ovic

ian

segm

ent o

f the

CO

2 inj

ectio

n w

ell.

Bre

ckin

ridge

4 Introduction

attractive option for power plants because of the economic and environmental benefits. Separating CO2 from the flue gas is expensive and could lead to a 20 to 35 percent reduction in power-plant ef-ficiency (Nsakala and others, 2001). Emitting those impurities into the atmosphere causes air and wa-ter pollution such as particulate matter, acid rain, and ground-level ozone. On the other hand, when injected into deep geologic reservoirs, these impu-rities can react with brine and formation rocks and may compromise reservoir and seal-rock integrity. Among the common CO2 impurities, SO2 is poten-tially the most active in the deep saline reservoir. Knauss and others (2005) suggested that co-injec-tion of SO2 with CO2 could lead to very low pH and formation of anhydrite. Xu and others (2007) further suggested that SO2 created a strongly acidi-fied zone, in which porosity increased significant-ly, when co-injected with CO2 into a deep arkose formation. SO2 is primarily produced from conven-tional coal-fired power plants, whose share of elec-tric generation has declined in recent years because of fuel-switching to lower-priced natural gas. Nev-ertheless, coal is predicted to still produce 32 per-cent of electricity in 2040 for the United States (U.S. Energy Information Administration, 2014). Under-standing potential long-term impacts of SO2 when co-injected with CO2 in different saline reservoirs is therefore an important aspect of assessments for many CO2 deep storage reservoirs.

Most research on understanding the impacts of injecting CO2 with impurities into CO2 storage reservoirs focused on two methods: laboratory experiments and numerical simulations. Bachu and others (2009) injected an H2S-containing CO2 stream through a 24-m-long tube filled with silica sand and brine. They found that H2S traveled slow-er than CO2 because of the higher solubility of H2S compared to that of CO2. Gunter and others (2005) conducted autoclave batch experiments in which CO2, H2S, and siderite were mixed under 5.15 bars and at 54°C for 14 days. Their experiments showed that H2S led to precipitation of pyrite. More recent-ly, to study the effects of SO2 on physical properties of reservoir rocks, Kummerow and Spangenberg (2011) injected pure CO2 and CO2 with 1 percent SO2 through a sandstone core saturated with brine. They found that the pure CO2 caused little change in the petrophysical properties, such as wave ve-

locity, electrical resistivity, and permeability. In contrast, CO2 containing SO2 increased electri-cal resistivity by 16.26 percent and decreased P-wave velocity by 7.67 percent and permeability by 45.97 percent. Renard and others (2011) performed 1-mo-long laboratory experiments using batch re-actors to compare the interactions of a dolostone with a pure CO2 stream and with a gas mixture with a mole ratio of 82 percent CO2, 4 percent SO2, 4 percent O2, 4 percent N2, and 6 percent Ar under 100 bars and at 150°C. They observed that the gas mixture had much higher reactivity than the pure CO2 gas did, enhancing carbonate dissolution and anhydrite precipitation. At the end of their experi-ment, the gas mixture dissolved 5 to 10 percent of the initial rock, but the pure CO2 dissolved less than 1 percent of the same rock.

Laboratory experiments often have limited durations, ranging from days to months. But the reactions between CO2 and aluminosilicate miner-als are slow, taking hundreds to thousands of years to reach equilibrium. Consequently, studying the long-term fate of injected CO2 containing impuri-ties in a deep geologic reservoir typically relies on numerical modeling. Xu and others (2007) modeled impacts of SO2 and H2S in a sandstone reservoir for a 10,000-yr period. They suggested that co-injection of H2S did not significantly affect pH distribution, mineral alteration, or CO2 mineral sequestration, but co-injection of SO2 caused a strongly acidified zone and led to a significant increase in porosity in the acidified zones. Bacon and others (2009) sim-ulated the impact of SO2 impurity in a dolomitic sandstone. They indicated that adding SO2 result-ed in precipitation of anhydrite near the injection well, but caused no substantial changes in poros-ity and permeability in a 100-yr period. Andre and others (2012) modeled impacts of a small amount of SO2 and O2 in CO2 for a sandstone, and their re-sults suggest that adding SO2 and O2 resulted in dissolution of calcite, precipitation of anhydrite, and an increase in porosity.

The purpose of this study was to simulate the potential impacts of SO2 impurity on the Beekman-town Dolomite and the Gunter Sandstone reser-voirs in the Knox Group. Specifically, we focused on comparing the model results of the co-injection of SO2 and CO2 with that from CO2-only injection. The same brine chemistry, reservoir temperature

5Model Setup

and pressure, mineral analysis, and core data used in Zhu and others (2013) were used to build the models.

The Knox GroupThe Knox Group is a thick interval of dolo-

stone with minor sandstone and shale present in the subsurface of the Appalachian and Illinois Ba-sins and the Cincinnati Arch in the eastern Unit-ed States (Mussman and Read, 1986; Read, 1989; Greb and others, 2009). It is equivalent to the Ar-buckle Group of Oklahoma and the Ellenburger Group of Texas. The Knox was deposited during the Late Cambrian and Early Ordovician on an ex-tensive carbonate ramp prior to uplift of the Cin-cinnati Arch and subsidence of the flanking Appa-lachian and Illinois Basins. In Kentucky, the Knox is divided into two formations: the Ordovician Beekmantown Dolomite and the Cambrian Cop-per Ridge Dolomite. In much of eastern Kentucky, these thick dolostone intervals are separated by a sandstone and sandy dolostone unit, the Rose Run Sandstone. In western Kentucky, a similar clastic unit, the Gunter Sandstone, separates the two do-lostone packages, but may not be age-equivalent to the Rose Run. Recent work by Harris and others (2014) suggests the sandstone-dominated interval referred to in this report may be equivalent to the younger New Richmond Sandstone of Illinois rath-er than the Gunter Sandstone. The name “Gunter” is used in this report for consistency with previous work related to the KGS No. 1 Marvin Blan well. The top of the Knox Group is a regional subaerial unconformity, where significant erosion resulted in truncation of the upper Knox prior to deposi-tion of the overlying St. Peter Sandstone and Wells Creek Dolomite/Dutchtown Formation.

Modeling MethodSeveral different computer codes have been

applied in modeling impacts of CO2 impurities, including TOUGHREACT (Xu and others, 2007; Zhang and others, 2011; Andre and others, 2012), STOMP (Bacon and others, 2009), and PHREEQC (Koenen and others, 2011). Previous work by Zhu and others (2013) used the ECO2N (Pruess, 2005) module in TOUGHREACT. In this study, we chose to use the same modeling code for simulating co-injection of SO2 and CO2. The ECO2N module was

developed to handle mixtures of water, NaCl, and CO2. The only way to simulate co-injection of CO2 and SO2 in ECO2N is to incorporate SO2 into the aqueous phase (i.e., dissolve SO2 in brine) and then co-inject CO2 and the brine (Xu and others, 2007; Andre and others, 2012). However, as pointed out in Crandell and others (2010), this method repre-sents an extreme scenario in which SO2 has unlim-ited contact with reservoir brine. In reality, parts of the injected gas phase SO2 will stay with super-critical CO2. Crandell and others (2010) simulated a different scenario on the other extreme in which SO2 only contacted brine through diffusion. Their simulation suggested that 65 to 75 percent of in-jected SO2 remained in the CO2 phase after 1,000 yr.

Model SetupThe SO2 impurity in CO2 from flue gas of

coal-fired power plants typically ranges from 1 to 5 percent in mass ratio (Apps, 2006; Crandell and others, 2010; Renard and others, 2011). To simulate a reasonable SO2 impurity, we used a 2.5 percent SO2 mass impurity in ECO2N. To create SO2-con-taining brines, we used PHREEQC (Parkhurst and Appelo, 1999) to fully dissolve a certain amount of SO2 into the original formation brines. The amount of SO2 to be dissolved in brines was determined to be 0.8 mol/kg of water by an arbitrarily chosen CO2/brine injection ratio of 2 to 1. The same ratio was used by Xu and others (2007) and Andre and others (2012). Table 1 shows the major aqueous species of brines of the Beekmantown Dolomite and the Gunter Sandstone with and without SO2. The SO2-bearing brines had very low pH compared to the original brines. The brine chemistry data for the Beekmantown Dolomite were from a different deep well, approximately 142 km from the CO2 injection well, because the reservoir conditions in the CO2 injection well precluded the collection of a representative brine sample from the Beekman-town Dolomite section (Zhu and others, 2013).

To simulate the co-injection of CO2 and SO2, we used 1-D radial models over batch models to allow injection of both CO2 and SO2-bearing brine. Because of the different physical and geochemical characteristics between the Beekmantown Dolo-mite and the Gunter Sandstone, we built two sepa-rate 1-D radial models, one for each rock reservoir. A 1-D radial model domain was centered at the

6 Model Setup

CO2 injection well and covered a 10,000-m-radius distance with grid spacing gradually increasing away from the well. Vertically, the model domain covered 478.5 m, representing the entire thickness of the Beekmantown Dolomite observed in the CO2 injection well. The outer boundary of the model was assumed to be at constant pressure. No flow conditions were imposed on the top and bottom boundaries, which reflected the assumption of per-fect sealing capacity of caprocks. The same domain was used for both reservoirs, but physical and geo-chemical parameters were different. Table 2 lists the physical and hydrogeologic parameters. Al-though the Gunter Sandstone in the well is approx-

Table 2. Hydrogeologic parameters for 1-D radial models.

ParameterValue

Beekmantown GunterPermeability (m2) 9.2 × 10–15 1.2 × 10–14

Porosity 0.064 0.09Compressibility (Pa–1) 4.5 × 10–10 4.5 × 10 –10

Temperature (°C) 36.2 44.0Pressure (bar) 113 152Relative permeabilityIrreducible water saturationVan Genuchten model exponent (λ)Irreducible gas saturation

0.300.750.01

0.300.870.01

Capillary pressureIrreducible water saturationVan Genuchten model exponent (λ)Strength coefficient (kPa)

0.000.75

19.61

0.000.87

19.61

Table 1. Water chemistry for the original and SO2-bearing brines.

SpeciesConcentration (mol/kg H2O)

Gunter SandstoneConcentration (mol/kg H2O)

Beekmantown DolomiteInitial Brine Brine With SO2 Initial Brine Brine With SO2

Ca2+ 0.1495E + 00 0.1495E + 00 0.2088E + 00 0.2088E + 00Cl– 0.1896E + 01 0.1896E + 01 0.1717E + 01 0.1717E + 01K+ 0.2974E – 01 0.2974E –01 0.6923E – 07 0.6923E – 07Mg2+ 0.5614E – 01 0.5614E – 01 0.8560E – 01 0.8560E – 01Na+ 0.1269E + 01 0.1269E + 01 0.1180E + 01 0.1180E + 01HCO3

– 0.1037E – 02 0.1224E – 02 0.1540E – 03 0.1401E – 03SiO2(aq) 0.2801E – 03 0.2801E – 03 0.2657E – 03 0.2657E – 03SO4

2– 0.2075E – 01 8.2075E – 01 0.2565E – 01 8.2565E – 01AlO 2

– 0.4022E – 08 0.4022E – 08 0.2307E – 07 0.2307E – 07pH 6.4 0.28 7.1 0.26Ionic strength (molal) 1.77 2.39 1.80 2.42

imately 80 m thick, using the same model domain for both reservoirs allowed a direct comparison of the results with the same amount of SO2 impurity.

The geochemistry and mineralogy inputs were largely based on Zhu and others (2013) and were modified slightly to account for the SO2 im-purity. Aqueous species are listed in Table 1. Min-eral assemblages, including those presented in the reservoir and secondary minerals that might form in response to the injection, are listed in Table 3. The choices of secondary minerals were based on existing modeling studies with similar initial min-eral assemblages ( Andre and others, 2007; Audi-gane and others, 2007).

Precipitation and dissolution of all minerals were considered to be kinetic, although carbonate rocks such as do-lomite and calcite interact with CO2 at a faster rate than clay minerals do. Pa-rameters for kinetic rate law and surface areas are required to simulate kinetic chemical reactions. These parameters (Table 4) were taken from Zhu and oth-ers (2013), which were in turn based on Xu and others (2004) and Marini (2007).

Potential impacts of CO2 impurities on integrity of deep carbon reservoirs is a major concern. TOUGHREACT ac-counts for changes of porosity (φ) that result from mineral precipitation and dissolution using

7Model Setup

Σnm

m = 1φ = 1 – frm – fru

(1)from Xu and others (2004) where nm is the number of minerals, frm is the volume fraction of mineral m in the rock, and fru is the volume fractions of non-reactive rock. The porosity was recalculated when the volume fraction of any mineral changed.

Although several options are provided in TOUGHREACT to account for permeability chang-es, we used an option that modifies permeability

Table 3. Initial mineral assemblages and secondary minerals.Gunter Model Beekmantown Model

Mineral Volume Fraction Mineral Volume FractionPrimary Primary

Dolomite 0.25 Dolomite 0.80Quartz 0.70 Quartz 0.10

K-feldspar 0.05 Anhydrite 0.05Secondary Illite 0.04

Anhydrite Kaolinite 0.01Illite Secondary

Kaolinite K-feldsparCalcite Calcite

Magnesite MagnesiteDawsonite Dawsonite

Albite Albite

Table 4. Kinetic parameters for minerals.

Mineral An (cm2/g)

Kinetic Rate Law ParametersNeutral Mechanism Acid Mechanism Base Mechanism

K nu25 (mol/m2/s)

E nua (kJ/mol)

K H25 (mol/m2/s)

E Ha (kJ/mol)

nHK OH25

(mol/m2/s)

E OHa (kJ/mol)

nOH

Dolomite 9.8 2.512 × 10–9 95.3 6.459 × 10–4 56.7 0.5 4.267 × 10–6 45.7 0.5Quartz 9.8 1.023 × 10–14 87.7K-feldspar 9.8 3.891 × 10–13 38.0 8.710 × 10–11 51.7 0.5 6.310 × 10–22 94.1 –0.823Kaolinite 151.6 6.918 × 10–14 22.2 4.898 × 10–12 65.7 0.777 8.913 × 10–18 17.9 –0.472Illite 151.6 1.660 × 10–13 35.0 1.047 × 10–11 23.6 0.34 3.020 × 10–17 58.9 –0.40Anhydrite 9.8 6.457 × 10–4 14.3Calcite 9.8 1.549 × 10–6 23.5 5.012 × 10–1 14.4 1.00 3.311 × 10–4 35.1 1.00Dawsonite 9.8 1.260 × 10–9 62.76 6.457 × 10–4 36.1 0.5Magnesite 9.8 4.571 × 10–10 23.5 4.169 × 10–7 14.4 1.0Albite 9.8 2.754 × 10–13 69.8 6.918 × 10–11 65.0 0.457 2.512 × 10–16 71.0 –0.572

(k) of fractured media according to changes of po-rosity using a cubic law:

φφi

( )3k = ki, (2)

where ki is the initial permeability and φi is the ini-tial porosity.

Each model was simulated for two scenarios: with SO2 and without SO2. The field injection of 16 hr with a rate of 12 kg/s of CO2 was adopted for these models. For the CO2-only scenario, CO2 was injected without brine. For the co-injection case, SO2-bearing brine of 6 kg/s was co-injected along

8 Model Results and Discussion

with CO2 at 12 kg/s. These models were simulated for a period of 10,000 yr.

Model Results and DiscussionThe model results (Figs. 2–7) indicate that the

major impacts of adding SO2 in a CO2 stream into both reservoirs were enhancing dissolution of do-lomite and precipitation of anhydrite, changing brine chemistry, and increasing reservoir porosity and permeability. The added SO2 created an acidi-fied zone surrounding the injection well (Figs. 2a, 5a) through a disproportionation reaction (Xu and others, 2007):

4SO2 + 4H2O → 3H2SO4 + H2S. (3)

The more acidic brine increased dissolution of do-lomite significantly near the injection well (Figs. 3a, 6a). The co-injected SO2 also added additional SO42– into the aqueous phase, resulting in substantial pre-cipitation of anhydrite (Figs. 3b, 6b). The enhanced dissolution of dolomite and precipitation of anhy-drite were accompanied by changes in the brine chemistry, mainly a decrease in concentration of Ca+ (Figs. 2b, 5b) and increases in concentrations of SO42– (Figs. 2c, 5c) and Mg2+ (Figs. 2d, 5d). The acidic zones appeared to be buffered rather quickly (i.e., quick rebound of pH value), but the changes in aqueous species remained for a long time. Total carbon (HCO3–) in brine was less affected (Figs. 2e, 5e). The impacts on aluminosilicate minerals ap-peared to be insignificant (Figs. 3c–f, 6c–g). The rates of precipitation/dissolution of these miner-als were slightly altered, but the overall reaction paths remained the same (i.e., the precipitating minerals under CO2-only injection still precipitated under co-injection of SO2 and CO2 and vice versa). The significant changes in reaction intensity of do-lomite and anhydrite due to added SO2 also led to noticeable increases in porosity and permeability for both reservoirs (Figs. 4, 7).

Although the added SO2 affected similar physical and geochemical properties for the two reservoirs, model results suggest that the degrees of impact were different. The same amount of in-jected SO2 lowered pH value more in the Gunter than in the Beekmantown (Figs. 2a, 5a), conse-quently resulting in a higher rate of dolomite dis-solution. The precipitation of anhydrite is lower

in the Gunter than in the Beekmantown, however, which we consider to be attributable to Ca2+ avail-ability in the brine because the Beekmantown brine has higher Ca2+ concentration than the Gunter brine (Table 1). The combined higher dissolution of dolomite and lower precipitation of anhydrite in the Gunter resulted in higher increases of porosity and permeability in the Gunter than in the Beek-mantown (Figs. 4, 7). The geochemical character-istics of the reservoirs are the more likely factors responsible for the differences in degree of changes than reservoir physical properties are. We ran the Beekmantown model with increased porosity and permeability, the same as that of the Gunter model, and ran the Gunter model with decreased poros-ity and permeability, the same as that of the Beek-mantown model. The results (Fig. 8) show that the changes in porosity in both reservoirs were almost the same, given two different reservoir porosity and permeability inputs.

Although a representative SO2 impurity was used in this study, the degree of interactions among SO2, the formation brines, and the reservoir rocks should be considered a rough approximation. The handling of SO2 impurity in TOUGHREACT required the SO2 to be totally dissolved in brine, which exaggerated the amount of SO2 available for interacting with the reservoir. The exaggeration would be especially higher for large-scale injection scenarios in which injected SO2 would be expected to remain in gas phases for a long period of time (Crandell and others, 2010).

The model results presented here should be considered explanatory, aiming to illustrate pos-sible major physical/geochemical alterations in the two deep carbon reservoirs because of added SO2. The 1-D radial models were highly simplified, treating both reservoirs as homogeneous in physi-cal and geochemical properties. Field conditions are certainly more complex, which may greatly change physical flow and chemical reaction path. The modeling software, TOUGHREACT, has its own limitations in handling this type of problem. Xu and others (2007) cautioned that their modeling results using TOUGHREACT to simulate co-injec-tion of H2S or SO2 with CO2 should be treated as preliminary, and they discussed these limitations at length.

9Model Results and Discussion

Figure 2. Simulated changes in aqueous species along the radial distance at different times using the 1-D model for the Beek-mantown Dolomite: (a) pH, (b) Ca2+, (c) SO4

2–, (d) Mg+, and (e) HCO3–.

10 Model Results and Discussion

Figure 3. Simulated changes in minerals along the radial distance at different times using the 1-D model for the Beekmantown Dolomite (in the Y axis, positive indicates precipitation and negative indicates dissolution): (a) dolomite, (b) anhydrite, (c) daw-sonite, (d) quartz, (e) kaolinite, and (f) illite.

11Conclusions

Figure 4. Simulated changes in (a) permeability and (b) porosity along the radial distance at different times using the 1-D model for the Beekmantown Dolomite.

ConclusionsBased on our previous research efforts using

TOUGHREACT/ECO2N to model long-term in-teractions between CO2 and two potential carbon reservoirs, the Beekmantown Dolomite and the Gunter Sandstone in the Knox Group, we modeled co-injection of SO2 and CO2 to evaluate possible impacts of the small amount of SO2 on the two res-ervoirs. We built 1-D radial models using the same modeling code and compared the results from co-injection of SO2 with CO2 to the results from CO2-only injection. Because of the highly simplified assumptions used in these 1-D models and limita-tions of TOUGHREACT, the results should be con-sidered qualitative. The model results suggest that:

(1) The major impacts of added SO2 for both the Beekmantown Dolomite and the Gunt-er Sandstone were on carbonate minerals, significantly enhancing dissolution of do-lomite and precipitation of anhydrite. The impacts on aluminosilicate minerals ap-pear to be insignificant, slightly changing the rates of precipitation/dissolution, but

the overall reaction paths remained the same.

(2) The major impacts of added SO2 on brine chemistry for both reservoirs were creat-ing an acidic zone near the injection well, decreasing concentration of Ca+ and in-creasing concentrations of SO42– and Mg2+. The acidic zones appeared to have been buffered rather quickly, but the changes in aqueous species remained for a long time.

(3) The added SO2 also led to noticeable in-creases in porosity and permeability for both reservoirs, which mainly resulted from the combination of enhanced dis-solution of dolomite and precipitation of anhydrite.

(4) The Gunter Sandstone appeared to be more reactive with SO2 than the Beek-mantown Dolomite. More dolomite was dissolved in the Gunter than in the Beek-mantown with the same SO2 impurity. Consequently, porosity was raised more in the Gunter than in the Beekmantown.

12 Conclusions

Figure 5. Simulated changes in aqueous species along the radial distance at different times using the 1-D model for the Gunter Sandstone: (a) pH, (b) Ca2+, (c) SO4

2–, (d) Mg+, and (e) HCO3–.

13Conclusions

Figure 6. Simulated changes in minerals along the radial distance at different times using the 1-D model for the Gunter Sand-stone (in the Y axis, positive indicates precipitation and negative indicates dissolution): (a) dolomite, (b) anhydrite, (c) dawsonite, (d) quartz, (e) K-feldspar, (f) illite, and (g) calcite.

14

Figure 7. Simulated changes in (a) permeability and (b) porosity along the radial distance at different times using the 1-D model for the Gunter Sandstone.

AcknowledgmentsThe study was supported by U.S. Department

of Energy grant DE-FE0002068 in collaboration with the Illinois State Geological Survey (princi-pal investigator, Dr. Hannes Leetaru). This project took place from Dec. 8, 2009, to Sept. 30, 2014. This research was part of the U.S. Department of Energy project, An Evaluation of the Carbon Sequestration Potential of the Cambro-Ordovician Strata of the Illinois and Michigan Basins. We are grateful to Dr. Marty Parris for his constructive review of this re-port.

References CitedAndre, L., Audigane, P., Azaroual, M., and Men-

joz, A., 2007, Numerical modelling of fluid-rock chemical interactions at the supercritical CO2-liquid interface during supercritical CO2 injection into a carbonate reservoir, the Dog-ger aquifer (Paris Basin, France): Energy Con-version and Management, v. 48, p. 1782–1797.

Andre, L., Azaroual, M., Bernstone, C., and Wit-tek, A., 2012, Modeling the geochemical im-pact of an injection of CO2 and associated reactive impurities into a saline reservoir: Proceedings, TOUGH Symposium 2012, Lawrence Berkeley National Laboratory, Berkeley, Calif., Sept. 17–19, 2012, 8 p., hal.archives- ouvertes.fr/hal-00755058/document [accessed 12/14/2015].

Apps, J.A., 2006, A review of hazardous chemi-cal species associated with CO2 capture from coal-fired power plants and their potential fate during CO2 geologic storage: Lawrence Berkeley National Laboratory Report LBNL-59731, 60 p.

Audigane, P., Gaus, I., Czernichowski-Lauriol, I., Pruess, K., and Xu, T., 2007, Two dimensional reactive transport modelling of CO2 injection in a saline aquifer at the Sleipner site, North Sea: American Journal of Science, v. 307, p. 974–1008.

Bacon, D.H., Sass, B.M., Bhargava, M., Sminchak, J., and Gupta, N., 2009, Reactive transport modeling of CO(2) and SO(2) injection into deep saline formations and their effect on the hydraulic properties of host rocks: Energy Procedia, v. 1, no. 1, p. 3283–3290.

Bachu, S., Bennion, D.B., Pooladi-Darvish, M., and Hong, H., 2009, Factors affecting the chro-matographic partitioning of CO2 and H2S injected into a water-saturated porous medi-um: Energy Procedia, v. 1, p. 3165–3172, doi: 10.1016/j.egypro.2009.02.099.

Bowersox, J.R., 2013, Evaluation of phase 2 CO2 in-jection testing in the deep saline Gunter Sand-stone reservoir (Cambrian-Ordovician Knox Group), Marvin Blan No. 1 well, Hancock County, Kentucky: Kentucky Geological Sur-vey, ser. 12, Contract Report 53, 43 p.

Acknowledgments

15References Cited

Figure 8. Comparison of simulated changes in porosity with different initial porosity: (a) the Beekmantown model and (b) the Gunter model.

16 References Cited

Bowersox, J.R., in press, Phase 1 geologic evalua-tion of the Kentucky Geological Survey Mar-vin Blan No. 1 deep saline reservoir CO2 in-jection test well, Hancock County, Kentucky: Kentucky Geological Survey, ser. 12, Contract Report 63.

Bowersox, J.R., and Williams, D.A., 2014, Geology of the Kentucky Geological Survey Marvin Blan No. 1 well, east-central Hancock Coun-ty, Kentucky: Kentucky Geological Survey, ser. 12, Report of Investigations 25, 22 p.

Crandell, L.E., Ellis, B.R., and Peters, C.A., 2010, Dissolution potential of SO2 co-injected with CO2 in geologic sequestration: Environmental Science & Technology, v. 44, p. 349–355, doi: 10.1021/es902612m.

Greb, S.F., Harris, D.C., Solis, M.P., Anderson, W.H., Drahovzal, J.A., Nuttall, B.C., Riley, R.A., Solano-Acosta, W., Rupp, J.A., and Gupta, N., 2009, Cambrian-Ordovician Knox carbonate section as integrated reservoirs and seals for carbon sequestration in the eastern Midcontinent United States, in Grobe, M., Pashin, J.C., and Dodge, R.L., eds., Carbon dioxide sequestration in geological media—State of the science: American Association of Petroleum Geologists, Studies in Geology, v. 59, p. 241–259.

Gunter, W.D., Pratt, A., Buschkuehle, B.E., and Perkins, E.H., 2005, Acid gas injection in the Brazeau Nisku Q carbonate reservoir: Geo-chemical reactions as a result of the injection of an H2S-CO2 waste stream: Proceedings of the 7th International Conference on Green-house Gas Control Technologies, p. 469–477.

Harris, D.C., Ellet, K., Rupp, J., and Leetaru, H., 2014, Geologic characterization and car-bon storage resource estimates for the Knox Group, Illinois Basin, Illinois, Indiana, and Kentucky: U.S. Department of Energy Topical Report DOE/FE0002068-13, [96] p.

Knauss, K.G., Johnson, J.W., and Steefel, C.I., 2005, Evaluation of the impact of CO2, co-contam-inant gas, aqueous fluid and reservoir rock interactions on the geologic sequestration of CO2: Chemical Geology, v. 217, p. 339–350, doi:10.1016/j.chemgeo.2004.12.017.

Koenen, M., Tambach, T.J., and Neele, F.P., 2011, Geochemical effects of impurities in CO2 on a

sandstone reservoir: Energy Procedia, v. 4, p. 5343–5349.

Kummerow, J., and Spangenberg, E., 2011, Experi-mental evaluation of the impact of the interac-tions of CO2-SO2, brine, and reservoir rock on petrophysical properties: A case study from the Ketzin test site, Germany: Geochemistry, Geophysics, Geosystems, v. 12, no. 5, 10 p., doi:10.1029/2010GC003469.

Marini, L., 2007, Geological sequestration of car-bon dioxide: Thermodynamics, kinetics, and reaction path modeling: Amsterdam, Elsevier, 453 p.

Mussman, W.J., and Read, J.F., 1986, Sedimentology and development of a passive- to convergent-margin unconformity: Middle Ordovician Knox unconformity, Virginia, Appalachians: Geological Society of America Bulletin, v. 97, p. 282–295.

Nsakala, N.Y., Marion, J., Bozzuto, C., Liljedahl, G., Palkes, M., Vogel, D., Gupta, J.C., Guha, M., Johnson, H., and Plasynski, S., 2001, Engineer-ing feasibility of CO2 capture on an existing US coal-fired power plant: Journal of Energy & Environmental Research, v. 2, no. 1, p. 87–98.

Parkhurst, D.L., and Appelo, C.A.J., 1999, User’s guide to PHREEQC (version 2)—A computer program for speciation, batch-reaction, one-dimensional transport, and inverse geochemi-cal calculations: U.S. Geological Survey Wa-ter-Resources Investigations Report 99-4259, 312 p.

Pruess, K., 2005, ECO2N: A TOUGH2 fluid prop-erty module for mixtures of water, NaCl, and CO2: Lawrence Berkeley National Laboratory Report LBNL-57952, 66 p.

Read, J.F., 1989, Controls on evolution of Cam-brian-Ordovician passive margins, U.S. Ap-palachians, in Crevello, P.S., ed., Controls on carbonate platform and basin development: SEPM Special Publication 44, p. 147–162.

Renard, S., Sterpenich, J., Pironon, J., Chiquet, P., Lescanne, M., and Randi, A., 2011, Geochemi-cal study of the reactivity of a carbonate rock in a geological storage of CO2: Implications of co-injected gases: Energy Procedia, v. 4, p. 5364–5369.

17References Cited

U.S. Energy Information Administration, 2014, An-nual energy outlook 2014 with projections to 2040: www.eia.gov/forecasts/aeo [accessed 12/10/2015].

Xu, T., Apps, J.A., Pruess, K., and Yamamoto, H., 2007, Numerical modeling of injec-tion and mineral trapping of CO2 with H2S and SO2 in sandstone formation: Chemical Geology, v. 242, p. 319–346, doi:10.1016/j. chemgeo.2007.03.022.

Xu, T., Sonnenthal, E., Spycher, N., and Pruess, K., 2004, TOUGHREACT user’s guide: A simula-tion program for non-isothermal multiphase reactive geochemical transport in variable

saturated geologic media: Lawrence Berke-ley National Laboratory Report LBNL-55460, 192 p.

Zhang, W., Xu, T., and Li, Y., 2011, Modeling of fate and transport of coinjection of H2S with CO2 in deep saline formations: Journal of Geophysical Research, v. 116, p. B02202, doi:10.1029/2010JB007652.

Zhu, J., Parris, T.M., Bowersox, J.R., and Harris, D.C., 2013, Modeling CO2-brine-rock inter-actions in the Knox Group: Implications of a deep carbon storage field test in western Ken-tucky: Applied Geochemistry, v. 37, p. 29–42, dx.doi.org/10.1016/j.apgeochem.2013.07.007.