Optimizing Permanent CO2 Sequestrationin Brine Aquifers: Example from theUpper Frio, Gulf of Mexico

Mark H. Holtz

Praxair, Inc., Worldwide Headquarters, 39 Old Ridgebury Road, Danbury, Connecticut, U.S.A.

ABSTRACT

Geologic sequestration of CO2 in brine-saturated formations has been proposedas a possible method to reduce emissions of this greenhouse gas to the atmo-sphere. To optimize the effectiveness of this method, the largest possible vol-

ume of CO2 should be sequestered over geologic time. Sequestration over geologic timecanbe thought of as permanent for the purposes of relieving climate-changing increases inatmospheric CO2 concentration. The least riskyway to achieve permanent sequestrationis to store the CO2 as a residual phase within a brine aquifer. Geologic conditions thatimpact the volume of CO2 stored as a residual phase include petrophysics, burial effects,temperature and pressure gradients, and CO2 pressure-volume-temperature character.Analyzing and integrating all of these parameters result in an optimal CO2 sequestrationdepth for a given geologic subprovince.

The integrated sequestration optimizationmodel was constructed using petrophys-ical, geological, and CO2 characteristics. Sequestering CO2 as a residual nonwetting phaseis one way to ensure its residency in rock over geologic time. Thus, residual saturation andporosity were pivotal modeling characteristics. Sediment burial depth affects porosity,temperature, and pressure; thus depth is a key input variable that integrates the otherparameters. Finally,CO2density as a functionof temperature andpressurewas accountedfor, resulting in amodel that combines all the salient properties that affect the amountof CO2 that can reside within buried rock.

A model for predicting residual nonwetting-phase saturation and a sequestrationoptimization curve (SOC) was developed. Results indicate that a sandstone porosity of0.23 is optimal for CO2 sequestration. The SOC for the Frio Formation, upper Texas GulfCoast, indicates that the largest volume of CO2 could be trapped as a residual phase atabout 3048–3657 m (10,000–12,000 ft). The SOC of depth versus CO2 residual-phasebulk volume is a concave-down parabolic shape with a broad maximum indicating the

25Holtz, M. H., 2008, Optimizing permanent CO2 sequestration in brine aquifers:

Example from the Upper Frio, Gulf of Mexico, in M. Grobe, J. C. Pashin, andR. L. Dodge, eds., Carbon dioxide sequestration in geological media—Stateof the science: AAPG Studies 59, p. 1–9.

1

1Present address: Praxair, Inc., International Business Development, EOR, 2803 Lawrence Dr., Austin, Texas, U.S.A.

Copyright n2008 by The American Association of Petroleum Geologists.

DOI:_______________________________________

optimal sequestration depth. Additionally, greater depth decreases the risk of surfaceleakage and increases the pressure differential between hydrostatic and lithostatic sothat higher injection pressures and, thus, higher injection rates can be obtained.

INTRODUCTION

With ever-increasing global usage of coal and hydro-carbons as energy sources and their subsequent emis-sions, all possiblemethods of CO2 sequestrationmay beneeded to curb the rise in atmospheric CO2 concentra-tion. Of the major sequestration options currently un-der investigation, including terrestrial and oceanic, geo-logic sequestration shows the greatest promise in termsof storage capacity and permanence. Geologic seques-tration can take many forms, including storage in coalbeds, salt caverns, oil and gas fields, and brine-bearingaquifers. Although all of these forms show promise andindeedwill likely be needed, brine-bearing aquifersmaybe themost important class of sites because of their wide-spread location and greater potential storage volumes(Bergman et al., 1995).

Several technical issues must be addressed to makesequestering CO2 in brine-bearing aquifers a viable op-tion. The most critical issue is to have the CO2 seques-tered in such a way that it reaches permanent residencywithin the subsurface rock in which it is injected. Per-meable strata and leaky faults could allow CO2 to mi-grate back to the surface if the CO2 resides in the rock as amobile phase. Mineral trapping and solution into brineare two mechanisms that show promise in achievingpermanent sequestration. However, if the CO2 was toreside within the rock as an immobile (residual) phase,permanent sequestration couldbe achievedmorequicklyand at greater volumes.

Trapping CO2 as a residual phase to achieve perma-nent storage was first suggested by Holtz (2003). WhenCO2 is stored as a residual phase, the risk of leaky struc-tural seals or leaky faults is averted. Kumar et al. (2004)gave evidence that trapping CO2 as a residual phase re-sults in a much greater volume of CO2 sequestered thaneither solution into water or mineralization. Hovorkaet al. (2004) applied two different residual nonwetting-phase saturation scenarios in simulation studies andshowed that the shape and movement of a subsurfaceCO2 plume are quite dependent on residual saturation.

The approach of this article is to characterize therelevant petrophysical characteristics of sandstones forstorage of CO2 as a residual phase with empirical andtheoretical models. Additionally, the pressure-volume-temperature character of CO2 is integrated with deptheffects. With these results, the optimal storage depthsof CO2 are determined for the Frio Formation, a repre-sentative Gulf Coast sandstone that is a significant tar-get for CO2 sequestration.

RESIDUAL-PHASE TRAPPINGFROM CAPILLARY FORCES

Capillary forces are known to be an integral factorin the petrophysical character of porous media. One ofthe most important phenomena that capillary forcescause to occur is a residual nonwetting phase in rocks.This phase has long been known and researched in theoil industry because it reduces the amount of oil and gasthat can be extracted from discovered reservoirs (Lake,1989; Holtz, 2002).

With water acting as the wetting phase and CO2

acting as the nonwetting phase, CO2 as a residual phase(Sgrm) results from pore-scale capillary forces. The resid-ual phase is the trapped nonwetting phase when the wet-ting phase has been imbibed into the rock from a stateof irreduciblewater saturation to a state of zero capillarypressure and is expressed as the fraction of the porosityoccupied by the nonwetting phase. The models that de-scribe how this trapping occurs are pore geometry de-pendent. Three trapping models are possible (Figure 1).The pore doublet model proposed byMoore and Slobod(1956) consists of parallel pores of varying size. The vary-ing pore size results in a differing capillary pressure thattraps the nonwetting phase. This trapping mechanismismore likely to occur in rocksmade up of poorly sortedgrains or rocks having dual porosity (intergranular andleached grains).

The pore-snap-off model proposed by Oh and Slat-tery (1976) traps the nonwetting phase in pores that areconnected to pore throats much smaller than them-selves.Whenhigh, the ratio of pore-body radius to pore-throat radius (aspect ratio) affects the fluid interface cur-vature such that the wetting phase moves around theouter surface of the pore and then into the pore throat,effectively trapping the nonwetting phase in the pore(Wardlaw, 1982). Wardlaw (1982) displayed how a non-wetting phase will be increasingly trapped by snap-offas the pore body/pore throat aspect ratio increases.He also showed that viscosity and interfacial tensionvariation only had small effects on nonwetting-phasetrapping.

The dead-endmodel proposed herein is a pore-scalemicrotrap. Buoyancy forces of a nonwetting phase cancause it to dead-end into amicrotrap. As awetting phaseencroaches around the trapped nonwetting phase, thewetting phase will move around instead of displace thenonwettingphase, thus leaving it as residual. All of thesetrapping models are more likely to occur in lower po-rosity and more highly cemented rocks. The trapping

2 Holtz

models thus suggest that porosity is inversely related toresidual-phase saturation.

The pore-doublet and snap-off models depend oncapillary forces to trap the nonwetting phase. A mea-sure of the ratio between viscous and capillary forcescalled the capillary number (equation 1) displays a rela-tionship in a capillary desaturation curve (CDC) withnonwetting-phase saturation. The typical relationshipof a CDC curve (Figure 2) is that as capillary number de-creases, nonwetting-phase residual saturation increases.Residual saturation increases until it reaches a plateauin the curve that corresponds to themaximum residual-phase saturation.

Nvc !nm

s cos"y#"1#

where Nvc is the capillary number, n is the nonwettingfluid velocity, m is the nonwetting fluid viscosity, s isthe surface tension, and u is the contact angle.

Note that the relationship between capillary num-ber and residual nonwetting-phase saturation is not thesame for all rocks. As the rock pore character becomesmore complex, the capillary number at which themax-imum residual nonwetting-phase saturation occurs de-

creases. A well-sorted sandstone that is characterizedgenerally by a similar pore body/pore throat ratio dis-plays a smaller nonwetting-phase saturation at a largercapillary number than typical sandstone and carbon-ate rocks (Figure 2). The transition from well-sortedsandstone to typical sandstone to carbonates generallyfollows a trend of decreasing porosity and increasingpore body/pore throat aspect ratio. Therefore, this trendqualitatively shows that nonwetting-phase residual satu-ration increaseswhenporosity decreases and aspect ratioincreases.

A porosity/aspect ratio model yields a theoreticalrelationship between porosity and residual gas satura-tion. Themodel is based onaDelaunay cell that consistsof a tetrahedral cell of closely packed spherical grainsand a Finney dense random packing. For the influenceof a porosity-reducingprocess in an intergranular systemto be analyzed, the Delaunay cell grainsmust be alteredby applying a grain cementation model (Bryant et al.,1993), which keeps the original grains in the same De-launay cell configurationwhile incrementally increasingthe grain radius (Figure 3), simulating cement growth.The incremental radius increase causes the pore vol-ume and the pore-throat size to decrease. From the ge-ometry of the Finney dense random packing, the poros-ity varieswith the incremental radius changes, as shownin equation 2 (S. L. Bryant, 2005, personal communica-tion). Here, R is the grain radius and DR is the incre-mental grain radius change.

f ! 2:6269 1$ !R

R

! "2% 7:2655 1$ !R

R

! "$ 5:0014 "2#

By combining the cementation model with the ac-tual data from the Finney packing (Finney, 1970), it can

FIGURE 2. The relationship between capillary number(Nvc) and nonwetting-phase residual saturation showshow Sgr decreases as Nvc increases (Lake, 1989). Srm is themaximum (plateau) nonwetting-phase saturation.

FIGURE 1. Three possible models illustrate how a wettingphase can trap a nonwetting phase as a result of variationsin pore geometry. (a, b) Modified from Chatzis andMorrow (1981). (c) Proposed by author.

Optimizing Permanent CO2 Sequestration in Brine Aquifers 3

be demonstrated that as porosity decreases, the aspectratio increases. As cement is added to a tetrahedral cell,both porosity and pore-throat size decrease. If the pore-body size can be defined as the radius of a sphere thatwould fit in the pore and the pore-throat size as theradius of a circle that would fit inside the pore throat,these geometries can be determined as cement is addedandporosity decreases. Furthermore, to relate these geom-etry changes to the snap-off model, a pore-body radius/pore-throat radius aspect ratio is determined. By deter-mining themaximum aspect ratio derived for the Finneypacking when cement is added, an aspect ratio-porosityrelationship is derived. The aspect ratio increases moreabruptly thanapower-law relationship, increasingnearlysevenfold before pore throats begin to be shut (Figure 4).Note that Chatzis andMorrow (1981) observed that 80%of the nonwetting-phase trapping in consolidated coreswas caused by snap-off geometries. Thus, the aspect ratiomay be the main factor in the magnitude of Sgrm.

This model gives a basis for understanding how in-terparticle porosity is related to residual gas saturation.

Because decreasing porosity increases the pore body/throat aspect ratio and an increasing aspect ratio causesincreasing residual gas saturation, it follows that decreas-ing porosity will result in increasing residual gas satu-ration. This relationship between porosity and residualgas saturation is the case for isopachous cement in inter-granular sandstone because of its effect on aspect ratio.Other porosity-reducing mechanisms in sandstonesor porosity other than intergranular porosity may havea different relationship. For example, vuggy porosityin carbonate rock or dissolved grains (secondary poros-ity) in sandstones could result in greater aspect ratiosat a given porosity. In contrast, microporosity fromauthigenic clays in sandstones can result in changingpore geometry in such a way that the pore-body radius/pore-throat radius aspect ratio is not meaningful orconstant or even decreasing. This is the case presentedby Hamon et al. (2001), where clay-free samples dis-play increasing Sgrm with decreasing porosity, whereasshaly samples displayed decreasing Sgrm with decreas-ing porosity.

FIGURE 3. The combination of theDelaunay cell and the grain cementa-tion model allows the investigationof the relationship between the poros-ity and pore body/pore throat aspectratio.

FIGURE 4. The relationshipbetween porosity and themaximum pore-body/pore-throat radius aspect ratio inthe Finney dense packingindicates that as porosity de-creases the aspect ratio in-creases dramatically.

4 Holtz

RESIDUAL SATURATIONMODEL FOR

INTERGRANULAR POROSITY

The sandstone of the upper Gulf Coast Frio Forma-tion is fine grained and poorly cemented. This sandstoneis a subarkose, consisting mainly of quartz with smallamounts of feldspar and lithic fragments. The grains aresubangular, with the pore space lying between the grains(Figure 5). This pore character caused the Frio sandstoneto have petrophysical properties similar to those of other

sandstones, which are also dominated by intergranularporosity.

A robust model of residual gas saturation was de-veloped fromupperGulf Coast Frio Formation data andpublished studies of sandstones. A strong relationshipis documented between increasing porosity and decreas-ing residual gas saturation. The trend is semilog, and thebest-fitting equation is given in equation 3. The pub-lished datawere extracted from10 articles (Geffen et al.,1952; Chierici et al., 1963; Crowell et al., 1966; Katz et al.,1966; Keelan, 1976; Fishlock et al., 1986; Firoozabadi andOlsen, 1987; Jerauld, 1996; Mulyadi et al., 2000; Hamonet al., 2001). Additionally, several Texas Gulf Coast FrioFormation samples were included. The data representmainly intergranular pore types instead of microporos-ity or secondary porosity. Thus, the aforementioned re-lationship between porosity and aspect ratio applies.

The four Frio data values can be overlain onto thepublished data (Figure 6). The overlay indicates that Friomeasurements are on trend with other published infor-mation, suggesting that the Frio Formation has a porestructure typical of fine sandstones. Note that this em-pirical trend was predicted from the Delaunay cell ce-mentation model. Notice that the shape of the empir-ical porosity-Sgrm curve (Figure 6) is quite similar to theporosity aspect ratio curve (Figure 4). Thus, snap-off,controlled by aspect ratio, is likely the dominant mech-anism causing the residual phase within interparticlepore-dominated sandstones.

Sgrm ! %0:3108ln"f# % 0:127 "3#

where f is the porosity (fraction).

FIGURE 5. The upper Gulf Coast Frio Formation sand-stone is a fine-grained subarkose with intergranularporosity. Sample from the Frio brine pilot injection wellat a depth of 1544.3 m (5066.6 ft).

FIGURE 6. Residual gas satu-ration displays an inversenonlinear relationship withporosity for intergranularporosity.

Optimizing Permanent CO2 Sequestration in Brine Aquifers 5

CARBON DIOXIDEFLUID CHARACTER

The physicochemical character of CO2 is well un-derstood. With a molecular weight of 44 and a specificgravity of 1.522 at 708F (21.118C) and atmospheric pres-sure, the specific volume is 0.140 g/cm3 (8.74 lb/ft3). Itsbeing less dense than water is the most salient charac-teristic of CO2 in brine-aquifer sequestration. How thedensity changes with increases in both temperature andpressure is also important because these conditionsbothincreasewith depth into the subsurface. Because densityincreases with increasing pressure, a greater amount ofCO2 canbe sequestered in a givenpore volumeat greaterdepths.

The pressure-temperature-volume (PVT) characterof CO2 was modeled using the output of the Tough2simulator. Varying densities were determined for thetemperature-pressure regime that exists in the upperGulfCoast Frio Formation. The general temperature func-tion contains a quasi-surface temperature of 77.458F(25.258C) and increases by 1.58F (%16.948C) with each30.48 m (100 ft) of depth (equation 4). Pressure gen-erally follows a 0.448 psi/ft pressure gradient down toa depth of 4572 m (15,000 ft) before geopressure isreached.

Td ! 0:015& depth "ft# $ 77:45 "4#

The density of CO2 varies significantly according tothedepth atwhich it is sequestered. At a depthof 914.4m(3000 ft), where brine aquifers begin to exist on the GulfCoast, CO2 would already be a supercritical fluid. At agreater depth, CO2 density increases quickly, and thenthe rate of density changewith depth begins to stabilizewhen the density reaches 650 kg/m3 (40.6 lb/ft3). This

stabilization indicates that a point of diminishing re-turns for sequestering CO2 deeper in terms of densityincrease and, thus, injecting more CO2 per unit porevolume exists.

OPTIMIZATION COMBININGPETROPHYSICAL AND

FLUID CHARACTERISTICS

Optimization of permanent CO2 sequestration isachieved by having the largest volume of CO2 to residein a residual phase per bulk volume of rock. For this goalto be achieved, optimization must concurrently occurin both CO2 density and residual-phase storage capacity,which is a function of porosity. As displayed in Figure 7,residual saturation for intergranular pore networks isinversely proportional to porosity, as the overall storagevolume in the bulk volume rock decreases, the part ofthe storage volume occupied by the residual nonwettingphase increases. Thus, a point at which the greatest totalvolume of residual nonwetting phase exists for the bulkvolume rock is observed. Calculation of bulk volume re-sidual saturation indicates that it is greatest at a porosityof 0.23 (Figure 7). A moderate-porosity rock is thereforeoptimal for permanent sequestration instead of a low-or high-porosity rock.

Whereas CO2 density increases with depth, bulkstorage volume forCO2decreaseswithdepth. Loucks andDodge’s (1986)work in theupperGulfCoast onporosity-depth trends showedhowporosity decreases with depth,facilitating the prediction of porosity. Over depths ofnormal hydrostatic pressure, a general linear trend ofdecreasing porosity is observed.

The final optimization step is to develop a CO2 se-questrationoptimization curve (SOC). The SOC integratesCO2 density character and petrophysical relationships

FIGURE 7. Because satura-tion is a function of porosityand measured as a fractionof porosity, an optimal poros-ity value at which the bulkvolume of the residual phaseis the largest exists. The largestvolume of a residual non-wetting phase in an intergran-ular pore network occurs ata porosity of 0.23.

6 Holtz

with depth, thus allowing the determination of opti-mal depth for permanent CO2 sequestration. For the FrioFormation in the upper Gulf Coast, optimal sequestra-tionoccurs at depths of 3048–3657m (10,000–12,000 ft)(Figure 8). The SOC displays a maximum, with the CO2

bulk volume residual phasedecreasing at greater depths.The SOC also demonstrates that, for this area, an opti-mal CO2 emplacement depth exists that will allow thegreatest amount of CO2 to be sequestered as an immo-bile phase, thus reducing the risk of anyCO2 leakage andachieving permanent storage.

Over this optimal depth range, additional advan-tages occur. The variation of lithostatic, fracture-limit,and hydrostatic pressures is not parallel with increasing

depth. Both lithostatic and fracture pressure increasemore rapidly with depth, so the difference betweenfracture and hydrostatic pressures increases with depth(Figure 9). These pressure characteristics increase themaximum injection pressure difference (DPim), thus al-lowing higher injection rates and higher pressure build-up, which results in greater storage capacity. The DPimincreases linearly, therefore not reaching a maximumfor optimization. Additionally, the CO2 pressure build-up from a density gradient at a spill point of 3048 m(10,000 ft) allows for a closure of nearly 1828.8m (6000 ft),much greater than actual Gulf Coast structures (Figure 9).The possibility of reaching fracture pressure from a CO2

gas column therefore does not exist.

FIGURE 8. The CO2 seques-tration optimization curvefor the upper Gulf Coast FrioFormation indicates thatdepths of 3048–3657 m(10,000–12,000 ft) are opti-mal for obtaining permanentCO2 storage.

FIGURE 9. Pressure characteristics for the upper Gulf Coast Frio Formation illustrate how storage and maximuminjection pressure difference (#DPim) increases with increasing depth.

Optimizing Permanent CO2 Sequestration in Brine Aquifers 7

CONCLUSIONS

For optimal permanent storage of CO2 to be facili-tated, considerable engineering is required, and themostsignificant engineering design parameter is the emplace-ment of the greatest volume of CO2 as a residual non-wetting phase within the rock. An empirical residualsaturation model, which was based on a physical inter-granular pore network, was developed to assist in design.This model allows the prediction of residual saturationin sandstones dominated by intergranular porosity as afunction of porosity. Modeling of these petrophysicalproperties indicates that optimal permanent sequestra-tion is achieved at a porosity value of 0.23. Engineeringthe combinationof bothpetrophysical and fluid charac-teristics results in anSOCthatdisplays thedepthatwhichthe greatest volume of CO2 can be stored as a permanentresidual saturation phase. In the example of the GulfCoast Frio Formation, the optimal depth is in the rangeof 3048–3657m (10,000–12,000 ft), which has the addi-tional advantages of a large storage andmaximum injec-tion pressure difference, as well as extremely largemaxi-mum gas column heights.

An approach was developed for the construction ofan SOC. The SOC tool integrates CO2 andpetrophysicalcharacter in order that the optimal depth for seques-tering CO2 in a brine aquifer can be determined. For theFrio Formation in the upper Gulf Coast, the optimalsequestration depth is from 3048 to 3657 m (10,000–12,000 ft). Sequestration optimization curves can be de-veloped for other formations in other basins to aid inpermanent low-risk anthropogenic CO2 sequestration.

ACKNOWLEDGMENTS

This research is funded by the U.S. Department ofEnergy National Energy Technology Laboratory undercontractDE-AC26-98FT40417 to theBureauof Econom-ic Geology and by the GEO-SEQ project contract DE-AC03-76SF00098. The preparation and presentation ofthis articlewere funded by the JohnA. andKatherineG.Jackson School of Geosciences under matching fundsto the Gulf Coast Carbon Center (GCCC). We thankour GCCC contributing members BP, Praxair, KinderMorgan, and ChevronTexaco for their support. I alsothank Larry W. Lake and Steven L. Bryant for their guid-ance in the study of this subject and Sue Hovorka forcontinued encouragement and Libby Stern for helpfulguidance inwriting. SusannDoenges edited the article.Patricia Alfano prepared the figures under the supervi-sion of Joel L. Lardon, Media Information TechnologiesManager. Publication was authorized by the director,Bureau of Economic Geology, The university of Texas atAustin.

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Optimizing Permanent CO2 Sequestration in Brine Aquifers 9