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International Journal of Greenhouse Gas Control 9 (2012) 103–116

Contents lists available at SciVerse ScienceDirect

International Journal of Greenhouse Gas Control

j ourna l ho mepage: www.elsev ier .com/ locate / i jggc

O2 sequestration into the Wyodak coal seam of Powder Riverasin—Preliminary reservoir characterization and simulation

ratik Duttaa,∗, Mark D. Zobackb

Department of Mining Engineering, Bengal Engineering and Science University, Shibpur 711103, IndiaDepartment of Geophysics, Stanford University, Stanford, CA 94305, USA

r t i c l e i n f o

rticle history:eceived 8 October 2011eceived in revised form 13 March 2012ccepted 15 March 2012vailable online 21 April 2012

eywords:O2 sequestrationeservoir simulationBMCBM

a b s t r a c t

Injection of carbon dioxide captured from flue gas into coal beds is regarded as one of the value-addedoptions of CO2 sequestration as the cost of injection can be partially or fully offset by the revenue gener-ated through release of additional methane. The Powder River Basin is one of the major coalbed methaneproducing areas in the world. The paper presents findings of a preliminary reservoir simulation study onthe feasibility of CO2 sequestration over a nine-section area (4.8 km × 4.8 km) of the Powder River Basininto the thick Wyodak coal seam, one of the two major coal seams in the highly productive Fort Unionformation.

The reservoir model was built on the basis of information available in the public domain. Gamma raylogs from 60 wells were utilized for developing a 3-D geological model of the coal seam and overlying rocksin the area by employing geostatistical techniques. Considerable variability in gas and water productionwas observed in the 65 wells. This variability was utilized for capturing the reservoir heterogeneity byGaussian geostatistical simulation, which produced realizations of fracture porosity and permeabilitydistribution throughout the reservoir.

Results of fluid flow simulation indicated that it would not be feasible to place more than one injectorper 1.6 km × 1.6 km (1 mile × 1 mile) section of the area due to geomechanical constraint. As a preliminaryestimate, it may be feasible to inject 0.658 million tons of CO2 through such injector over a period of

20 years. 12% more CO2 can be injected over the same period by using a horizontal well but the lossof injectivity may be substantial due to reduction of permeability by coal matrix swelling. The loss ofpermeability can partially be overcome by intermittent injection for 6 months followed by a similar soakperiod. Placing one vertical injector each into all the nine sections would result in a scaled-up volume of5.5 million tons of CO2 injection. However, the nature of overlying rock could play a vital role in retentionof injected CO2 and up to 20% of the gas may migrate up by buoyancy.

. Introduction

Sequestration of carbon dioxide (CO2) into deep unminableoal seams is considered to be an attractive option for mitigat-ng the adverse effects of increasing greenhouse gas emission.esearch during the last two decades showed that coals have muchigher adsorption affinity for CO2 than for methane (Arri et al.,

992; Mastalerz et al., 2004; Busch et al., 2003, 2006; Tang et al.,005; Harpalani et al., 2006; Fitzgerald et al., 2005; Dutta et al.,011). Therefore, a coal seam cannot only provide site for storage

∗ Corresponding author at: Department of Mining Engineering, Bengal Engineer-ng and Science University, Shibpur, P.O. - Botanic Garden, Howrah, 711103 Westengal, India. Tel.: +91 33 2668 4561/2/3x477; fax: +91 33 2668 2916.

E-mail addresses: dutta.pratik@gmail.com (P. Dutta), zoback@stanford.eduM.D. Zoback).

750-5836/$ – see front matter © 2012 Elsevier Ltd. All rights reserved.oi:10.1016/j.ijggc.2012.03.004

© 2012 Elsevier Ltd. All rights reserved.

of this greenhouse gas but CO2 injection can also release addi-tional methane from coal not recoverable by the primary pressuredepletion method of producing coalbed methane (CBM), the pro-cess known as the enhanced coal bed methane (ECBM) recovery.Laboratory experiments followed by field pilots have adequatelydemonstrated that CO2 sequestration in coal seams with con-comitant recovery of additional methane is feasible (Reeves, 2001;Mavor et al., 2004; Pagnier et al., 2005; Wong et al., 2007; Kopernaet al., 2009). However, all coal seams may not be amenable to CO2sequestration and ECBM. A host of reservoir and other geologicalconditions will dictate whether or not a particular coal seam will bean ideal target. Rank of coal is a primary selection criterion for CO2sequestration with lower rank coals generally exhibiting higher

sorption affinity for CO2 (Busch et al., 2003; Ozdemir et al., 2004). Inaddition to the rank, variability in coal fracture properties (fractureporosity, permeability, and water saturation) and coal matrix prop-erties (equilibrium sorption, diffusion, and gas saturation) would

1 al of Greenhouse Gas Control 9 (2012) 103–116

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into the thick Wyodak seam towards the west to northwest. ForCO2 sequestration to be meaningful available coal volume has to belarge. Therefore, the possible site of CO2 sequestration for the TwoElk Energy Park should ideally be towards the west to northwest

04 P. Dutta, M.D. Zoback / International Journ

lso affect the CO2 sequestration process. For CO2 sequestrationnd ECBM to be successful, the coal beds should satisfy some cri-eria. Some of the important criteria would include coals with highermeability, thick coals with minimum faulting and folding, lowater saturation, and high methane saturation (Alberta Researchouncil, 2007). Furthermore, it is important to ensure that injectedO2 remains in place and does not travel upwards.

The Powder River Basin (PRB) in northeast Wyoming and south-est Montana is one of the major CBM-producing basins in theorld. Currently, there are about 14,500 active wells in Wyomingroducing more than 47 million m3 (1.5 billion ft3) of gas per dayWOGCC). Most of the CBM activities are concentrated into the

astach and Fort Union formations. Sub-bituminous PRB coaleams are distinctly different from other commercially developedBM reservoirs. Most of the seams are thick with very low gas con-ent, have high moisture but low ash content, and permeability is

uch higher than most of the other commercial CBM plays. As aonsequence, typical life of a CBM well in PRB is 7–8 years. Althoughost of the gas-producing coal seams are located at shallow depth,

resence of thick and laterally extensive low rank coal seams inRB may make them prime targets for storing huge volume of CO2.he coal beds in PRB satisfy most of the technical criteria outlinedy Gale and Freund (2001), Bachu (2007) and Bachu et al. (2007)or CO2 sequestration. The coal beds lie at depths between 300 and000 m, have very high fracture permeability, are confined locally,nd do not appear to have been deformed through faulting (ARI,002).

Ross et al. (2009) performed reservoir simulation of the Bigeorge coal of PRB to understand the reservoir response to CO2

njection. Their study showed that it is possible to sequester CO2nto the Big George coal and get additional methane recovery. Theyurther observed that capturing reservoir heterogeneity is impor-ant in fluid flow simulation and the nature of overlying rock wouldnfluence CO2 migration and retention within the reservoir. How-ver, their work was more generic in nature and was limited to amall section with data from only 5 CBM wells. For any full-scale orven pilot project of CO2 sequestration to be successful, it is impor-ant to predict in advance the nature of gas storage and flow into a

uch larger area. Also, for capturing reservoir heterogeneity ade-uately it is important that a reservoir 3-D model be built from a

arger database.The primary objective of the study was to determine the feasibil-

ty of CO2 storage into a possible pilot-scale project site by reservoirimulation. GEM, a compositional reservoir simulator from Com-uter Modelling Group, was used for the study. Law et al. (2002)uggested that for correctly modeling the complicated mechanismf CO2 sequestration and ECBM recovery process, a reservoir sim-lator should be able to account for a few important features likeoal matrix swelling with CO2 adsorption, compaction/dilation ofhe cleat system with stress change, diffusion and ad/desorption of

ultiple gas components within the coal matrix, non-isothermaldsorption due to change in temperature, and water movementetween the coal matrix and the natural fracture system. GEM hasost of these capabilities and was used successfully for historyatching in ECBM pilots in Canada and China (Mavor et al., 2004;ong et al., 2007). The thick and laterally extant Wyodak coal,hich is the most significant coal bed other than the Big George

oal within the Wyodak–Anderson coal zone of the Fort Union for-ation, was chosen for the purpose (Fig. 1). Another motivationas to select the site close to the Two Elk Energy Park, which is

clean-energy learning laboratory for multi-disciplinary researchnto carbon capture and storage, to be conducted by the Stanford

niversity. A 3-D stochastic reservoir model of the Wyodak coaled was developed and populated with porosity and permeabilityalues using geostatistical techniques and production trend match-ng. Thereafter, multiple fluid flow simulations were carried out

Fig. 1. Coal seams within the Fort Union formation.Source: Hower (2003).

under various scenarios of CO2 injection. The rock overlying thecoal bed was also considered in simulation to assess the possibilityof upward gas migration. Attempt was made to utilize all avail-able data sources. However, since the study aimed to be only apreliminary reservoir characterization and simulation, reasonableassumptions were made from other sources where site-specificinformation was not available.

2. Site description

Flores (2004) described the complete geological setting of thePowder River Basin in general, a brief account of which is alsogiven by Ross et al. (2009) and hence not repeated here. The TwoElk Energy Park is situated at Township 43, Range 70, southeastof Wright in the Campbell County of Wyoming (Fig. 2). A num-ber of large surface mines are located in the area. Numerous CBMwells surround the project site but are too shallow for CO2 seques-tration. The Wyodak seam splits in the region into the Andersonand Canyon seams. However, these seams tend to dip and merge

Fig. 2. Township/range designations near Wright, Wyoming.Source: ARI (2002).

P. Dutta, M.D. Zoback / International Journal of Greenhouse Gas Control 9 (2012) 103–116 105

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Table 1Fixed input parameters into the reservoir model.

Parameter Value Source

Pressure gradient 7.02 kPa/m ARI (2002)Coal compressibility 1.47 E−007/kPa

(matrix)2.9E−005/kPa(fracture)

Ross et al. (2009)

Shrinkage swelling parameters Ross et al. (2009)Strain at infinite pressure (CH4) 0.007Strain at infinite pressure (CO2) 0.013Strain Langmuir pressure (CH4) 2069Strain Langmuir pressure (CO2) 345Young’s modulus 0.413E−007Poisson’s ratio 0.39Palmer–Mansoori exponent 3Langmuir volume constant (CH4) 5.22 ton/m3 Hower (2003)

Fig. 3. Study area within Township 43 Range 72.

f Township 43, Range 70. For the current study, the area chosenas the upper left nine-section quadrant of Township 43, Range

2 covering an area of 4.8 km × 4.8 km (3 mile × 3 mile) (Fig. 3). 71BM wells exist in the area all of which produced gas from the Wyo-ak seam and the wells are spread on 0.323 km2 (80-acre) spacing.yoming Oil and Gas Conservation Commission maintain gamma

ay logs, gas production, and water production records of almostll the wells (WOGCC). Throughout this nine-section, the Wyodakeam is around 30 m (100 ft) thick, lying at a depth of 274–305 m900–1000 ft), and is laterally continuous. Most of the wells haveroduced for 7–8 years and are shut-in now. Therefore, the reser-oir is depressurized and depleted, providing opportunity for CO2njection. Since typical gas content of the PRB coals are low and theeservoir is depleted in the area, no attempt was made to study theCBM potential.

. Development of the geological model of the Wyodak coaleam

As already mentioned, Computer Modeling Group’s composi-ional simulator GEM was chosen for building the geological modelnd fluid flow simulation. Ross et al. (2009) emphasized the impor-ance of overlying rock as a seal to prevent upward migration ofO2 by buoyancy. For this reason, rock layers up to ∼15 m (50 ft)bove the coal seam were included in the geological model. Gammaay logs from 60 wells were utilized for building the model. Lat-tude/longitude of the wells was converted to plane coordinatesn the Universal Mercator Projection. Coals have distinctively lowamma ray signature and were clearly distinguishable in the logsless than 20 API). All 60 wells in the study area intercepted the

yodak coal seam. Overlying rock in the PRB typically comprisesf sandstone, mudstone, siltstone, and carbonaceous shale (Flores,004). However, with no specific information on the overlying rockor the site, it was assumed that the overlying rock was composedf either shale or sandstone. These two rock types would probablyrovide with two extremities for the study of upward gas migrationrom the coal bed. Sandstone might allow much easier pathway forhe passage of CO2 by buoyancy compared to shale (Ross et al.,009). Picking up of the gamma ray signatures for delineationf sandstone was rather conservative. Any gamma ray signatureelow API 60 was chosen as sandstone and above it as shale.

Coal seam depth from the top, coal seam thickness, and the

hickness of shale and sandstone up to ∼15 m (50 ft) above theoal seam were observed from the gamma ray logs of individualells. Thereafter, the maps of coal seam top, coal seam thick-ess, sandstone thickness, and shale thickness were generated

Langmuir pressure constant (CH4) 5004 kPaCO2:CH4 ratio 1:3Fracture spacing 5 cm

employing geostatistical kriging techniques. The maps of coal topdepth from surface and coal thickness are shown in Fig. 4, whilethe shale and sandstone layer thickness maps are given in Fig. 5. Itcan be seen from Fig. 4 that the coal seam is deeper in the west-southwest part of the area with depth ranging from 225 to 330 m.The thickness of coal varies widely from 18 to 50 m. It can alsobe observed from Fig. 5 that in the central to the southwesternpart of the study area, the sandstone layer lying above the coal iseither very thin or pinches out. In other parts of the reservoir, thesandstone layer thickness may be low to substantial. Shale layerthickness is high in the zones of low sandstone layer thickness andvice versa. Orthogonal corner point grid with 48 grid blocks eachalong the x and y directions were chosen to cover the entire nine-section area. Vertically, the model was split into ten layers. Thefirst two layers were shale, the next two were sandstone, and theremaining six were coal layers. Therefore, the entire reservoir wasmade up of 23,040 grid blocks.

4. Development of the reservoir model

4.1. Laboratory and field data sources

None of the site-specific information like gas content, adsorp-tion isotherm, cleat porosity, absolute cleat permeability, watersaturation, or reservoir pressure was publicly available. Hence,it was decided to utilize the relevant data from the literaturefor basic reservoir characterization. The list of such parametersassumed for building the reservoir model is given in Table 1.Advanced Resources International (ARI, 2002) concluded that thePRB coals are significantly under-pressured especially at the shal-lower regions. This was also observed from the water enhancementtest information available from the Wyoming Oil and Gas Con-servation Commission for the neighboring township and range(WOGCC). Hence, a reservoir pressure gradient of 7.02 kPa/mobserved by ARI (2002) was used for the study.

Stricker et al. (2006) studied the stratigraphic and geographicvariations in CH4 adsorption isotherms in the PRB. They observedthat the isotherms exhibit more vertical variation than lateral. Theadsorption isotherm for the Wyodak coal seam reported by Hower(2003) was used in the study. The isotherm represents an aver-age isotherm of coal cores from the Wyodak seam and assumingthe presence of a small percentage of CO2 (3–5%). CO2 adsorptionisotherm for the coal seam was not available. Laboratory studies

suggests that CO2:CH4 ratio is more than 2:1 for most of the coalsand may be much higher for lower rank coals (Busch et al., 2003;Mastalerz et al., 2004; Tang et al., 2005; Harpalani et al., 2006;Fitzgerald et al., 2005; Dutta et al., 2011). Tang et al. (2005) observed

106 P. Dutta, M.D. Zoback / International Journal of Greenhouse Gas Control 9 (2012) 103–116

ness m

Cpr

aMcPw

CpoMroattaWu

Fig. 4. Coal seam depth and thickness. Thick

O2:CH4 ratio of 3:1 for the PRB coal. Hence, a CO2 isotherm was re-lotted using the CH4 isotherm and assuming a nominal CO2:CH4atio of 3:1.

No field- or laboratory-derived data was available for the rel-tive permeability curves of the Wyodak or any other PRB coals.avor et al. (2003) successfully used the relative permeability

urve of Gash (1991) to history match CBM production from theRB coals. Hence, the same Gash (1991) relative permeability curveas used for the study.

Coal matrix shrinkage with CH4 desorption and swelling withO2 adsorption was included in the analysis. Ross et al. (2009)ublished results of simulation for the PRB coal with and with-ut matrix shrinkage/swelling in GEM with the default Palmer andansoori model (Palmer and Mansoori, 1998) and reported 10%

eduction in CO2 storage with matrix swelling. However, this isnly an indicative value. Actual reduction, if any, will depend, to

large extent, on the values of Palmer–Mansoori model parame-ers for the coal seam under study. However, these parameters of

he modified Palmer–Mansoori model, which is the default shrink-ge/swelling model equation in GEM, were not available for theyodak coal. Hence, the values reported by Harpalani (2005) and

sed in the reservoir simulation by Ross et al. (2009) were used.

ap shows one-sixth of the actual thickness.

Coal desorption time is used in GEM for modeling the rate ofdiffusion in the coal matrix. Flow in most of the CBM reservoirs ispermeability-controlled and diffusion has minor influence. How-ever, for high permeability reservoirs like the PRB coal seams,diffusion might influence the initial flow rates (Harpalani, 2006).Since no information was available on the coal desorption time, areasonable value of 30 days was assumed both for CH4 and CO2.

Flores (2004) reported that the cleat spacing in theWyodak–Anderson coal zone varies between 1 cm and 12 cmand the strike of the face cleats vary from NE to NW. The cleatspacing along both the face and butt cleat directions were assumedto be 5 cm. The bedding plane thickness was taken as 10 cm.

4.2. Estimation of key reservoir parameters through geostatisticalsimulation and production trend matching

Wyoming Oil and Gas Conservation Commission maintaincumulative monthly gas and water production data for all 61 CBM

wells in the study area (WOGCC). The available information wasnormalized into gas and water production rates per month. Cumu-lative monthly gas production against cumulative monthly waterproduction per well is presented in Fig. 6. It is evident from this

P. Dutta, M.D. Zoback / International Journal of Greenhouse Gas Control 9 (2012) 103–116 107

Both m

fiwSaI(bhepfaapwwftttwiwc

Fig. 5. Sandstone layer thickness maps.

gure that there is huge variability in gas and water productionithin the reservoir and no relationship exists between the two.

ome researchers suggested that the PRB coal seams, in generalnd Wyodak in particular, is a huge aquifer (Advanced Resourcesnternational, 2002; Hower, 2003). However, Onsager and Cox2000) indicated that production in parts of the PRB is controlledy leakage from overlying and underlying aquifers. On the otherand, Colmenares and Zoback (2007) suggested that during water-nhancement operation conducted at the beginning of CBM wellroduction for connecting cleats to the production well, verticalractures may grow and intercept the overlying sand aquifer. Theynalyzed water-enhancement and production data of 372 wellscross the PRB and observed that generally wells with high waterroduction yield low gas and vice versa. They concluded that theells with high water but low gas production were in the areashere the existing stress state would force the hydraulic fractures

rom water-enhancement operation grow vertically and intercepthe overlying sand aquifer. The gas and water production data ofhe 61 wells, presented in Fig. 6, show no such relationship betweenhe gas and water production. Therefore, the variability in gas and

ater production was ascribed only to the reservoir heterogene-

ty. Hence, similar to Koperna et al. (2009), it was assumed thatells producing at higher gas rate relate to the zones with higher

leat permeability in the vicinity and vice versa. Similarly, water

aps represent half the actual thickness.

production was directly related to the fracture porosity. Accord-ingly, two indices per well were defined as:

Permeability Index = Cumulative gas production from the wellAverage gas production from all wells

Porosity Index = Cumulative water production from the wellAverage water production from all wells

The above two indices were calculated for all 61 wells. Gridblocks containing a particular well were assigned the respectivevalues of the indices. Gaussian geostatistical simulation was thenrun to produce realizations of these indices over all grid blocksto capture the permeability and porosity heterogeneities over theentire reservoir. Thereafter, these indices were multiplied by theaverage permeability and average fracture porosity of the entirereservoir to generate the permeability and porosity realizations ofthe individual grid blocks. The average permeability and porosityvalues were obtained through production trend matching.

In the absence of any reservoir-specific data, lack of bottom-holepressure information, and the erratic nature of the production data,

no detailed well-to-well history matching was attempted. Insteadit was decided to carry out a trend matching exercise to reason-ably characterize the reservoir parameters. Trend matching waslimited to the seven production wells located at the central section

108 P. Dutta, M.D. Zoback / International Journal of Greenhouse Gas Control 9 (2012) 103–116

0

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0.3% to 1.6%. Ross et al. (2009) generated similar permeability andporosity realizations for the Big George coal, where the face cleatpermeability varied from 4 md to 55 md and the total cleat porosityvaried from 1.7% to 6.3%.

Table 2Trend-matched reservoir parameters.

Parameter Value

Average face cleat permeability 60 md

Fig. 7. Well positio

f the reservoir (Fig. 7). Average face and butt cleat permeability,verage fracture porosity, water saturation, and gas content werearied repeatedly to get a reasonably successful trend match andhe results are depicted in Figs. 8 and 9 for gas and water production,espectively.

The figures match the peak gas and water rates for most of theells. Both actual data and simulated data indicate that after about

years of operation both gas and water rates drop to very low lev-ls. The final trend-matched parameters are given in Table 2, andhe final realizations of absolute cleat permeability and porosity

cross all grid blocks are presented in Figs. 10 and 11, respectively.s can be seen from Table 2, the fracture water saturation of theoal bed is 70% and the average gas content is 1.2 ton/m3. Faceleat permeability over the entire reservoir varies approximately

he central section.

between 30 md and 100 md while the fracture porosity varies from

Average butt cleat permeability 40 mdAverage fracture porosity 0.8%Fracture water saturation 70%Gas content 1.2 ton/m3

P. Dutta, M.D. Zoback / International Journal of Greenhouse Gas Control 9 (2012) 103–116 109

0

5000

10000

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Fig. 8. Trend matc

. Simulation of CO2 injection

.1. Optimum number of injectors in one section

First phase of fluid flow simulation was limited to the centralection only. The seven wells were produced for 8 years to depletend depressurize the reservoir, which reflects the actual situations all the wells are shut-in after the end 7–8 years of production.y the end of 8 years the wells collectively produce 107 million m3

f gas out of the total gas-in-place of 127 million m3, which cor-esponds to a recovery of ∼83%. The next step was to determinehe optimum number of injectors in the section. It was assumedhat the least principal stress in the area is around 70% of the ver-ical stress. It put a constraint on the maximum injection pressure,hich should be below the least principal stress to avoid creation of

ccidental fracture into the reservoir. Considering an average over-urden rock density of 2300 kg/m3 and an average depth of 260 m,he least principal stress was calculated as ∼4200 kPa. Therefore,he maximum bottom-hole injection pressure was constrained to200 kPa. Thereafter, three vertical injectors were placed into theeservoir injecting CO2 continuously for a period of 20 years (Fig. 7).he injectors were located where the sandstone layer was eitherery thin or pinched out. The resulting fracture pressure in allrid-blocks of the section at the end of CO2 injection is depicted

n Fig. 12(a). It can be observed from this figure that the fractureressure may exceed the maximum allowable reservoir pressuref 4200 kPa in some region. In practice, this may not happen, as gasan still move laterally thereby eliminating the possibility of such

Months

f gas production.

pressure build-up. However, by constraining the reservoir volumeinto one section only we could assess that placing three injectors inone section would not be feasible. Injector 2 was then removed andthe simulation carried out again similarly. The resulting fracturepressure in the grid blocks after 20 years of CO2 injection is shownin Fig. 12(b). Again, fracture pressure with two injectors in placemay exceed the injection pressure constraint in some grid blocks.Finally, the simulation was done with only Injector 3 in place andthe resulting fracture pressure in the grid-blocks is presented inFig. 12(c). In such single injector situation, the fracture pressure inthe entire section remains below the maximum limit. Therefore, itcan be concluded that one injector per section may be the upperlimit for placing injectors in the reservoir. One of the shut-in wellscan be used as the injector.

5.2. CO2 injection scenarios

After ascertaining that only one injector can be placed in onesection, reservoir fluid flow simulation was run for different con-figurations of the well. Six different scenarios were assessed and,for each scenario, an injection period of 20 years was considered.The first five simulations were carried out within the central sec-tion only while the sixth simulation was done for a full-field studyconsidering the entire nine sections. First, only a vertical well was

placed in the center of the section with no hydraulic fracture. Sincethe stress state was unknown in the area, the direction of fracturepropagation in case a hydraulic fracture is created at the base ofthe well could not be ascertained. Therefore, two situations, one

110 P. Dutta, M.D. Zoback / International Journal of Greenhouse Gas Control 9 (2012) 103–116

0

10

20

30

40

50

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Simulated Water Produc�on

S8-48781 S8-48879 S8-48880

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Fig. 9. Trend matching of

Fig. 10. Permeability distribution across grid blocks.

Months

water production.

with a vertical and the other with a horizontal hydraulic fractureat the base of the vertical injector well were assessed. In many sit-uations, a horizontal well can lead to greater spread of CO2 intothe reservoir than a fractured vertical well. Although the existingshut-in vertical wells can be utilized for CO2 injection, the effectof injecting along a horizontal well was also included in the study.Accordingly, the fourth scenario was assessed with a 600-m longhorizontal well. CO2 injection can lead to coal swelling with subse-quent drop in injectivity as has been observed in the CO2 injectionpilot projects (Reeves, 2001; Pagnier et al., 2005). CO2 injection fol-lowed by a soak period can lead to recovery of injectivity (Mavoret al., 2004), A scenario with the same horizontal well but with

intermittent injection for 6 months followed by a soak period ofanother 6 months during the first 10 years of injection was alsostudied. Finally, the simulation was up-scaled to the entire nine

Fig. 11. Fracture porosity distribution across grid blocks.

P. Dutta, M.D. Zoback / International Journal of Greenhouse Gas Control 9 (2012) 103–116 111

F

saifao

Table 3Porosity and permeability of cap rock layers used in simulation.

Rock type Permeability Porosity

x-Direction y-Direction z-Direction

Shale 0.009 md 0.009 md 0.002 md 10%

in Fig. 15. It can be seen from the figure that CO2 rises as a plumeand gradually migrates into the overlying rock layers.

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ig. 12. Fracture pressure with three, two, and one injectors in the central section.

ections. The overlying rock in the central section is mostly shales seen in Fig. 5. But there are sections where sandstone thicknesss much higher compared to the shale thickness. Simulation of the

ull nine-section can capture the effects of reservoir heterogeneitynd varying overlying rock thickness more realistically. Therefore,ne vertical injector was placed into each of the nine sections and

Sandstone 70 md 70 md 70 md 10%

the simulation was carried out to estimate the possible volumetricstorage capacity of the entire nine-section of the reservoir.

One of the objectives of the simulation was to assess the sealintegrity of the overlying rock, which is critical for the success ofCO2 sequestration technology. As explained in Section 3, overly-ing rock was modeled along with the coal bed. The sandstone andshale layers were assumed to be homogeneous and each layer wasassigned uniform porosity and permeability similar to the valuesused by Ross et al. (2009) and given in Table 3.

6. Results of CO2 injection scenarios

6.1. Vertical well with no hydraulic fracture

Fig. 13 shows the retention of CO2 in the coal and overlying rocklayers after 20 years of continuous injection. It can be observedfrom the figure that it may be possible to inject 1.495 × 1010 gmole(∼0.658 million ton) of CO2 into the coal seam. Injectivity is veryhigh for the first 10 years and then drops off gradually. However, theentire injected CO2 may not remain within the coal. Out of the totalinjected volume about 82.3% is retained within the coal seam andthe rest travels up into the overlying rock. Out of the total injectedvolume of CO2, 6% is retained in the sandstone layer and 11.7% istrapped into the shale layer. To study the migration pattern of theinjected CO2, the spatial spread of CO2 within the six layers of coalwas studied and is presented in Fig. 14. The figure clearly shows thatCO2 sweep area is the maximum at the topmost coal layer (layer 5)and gradually reduces at the lower layers, which indicates that theinjected CO2 rises up by buoyancy and sweeps the upper parts ofthe seam more than the lower parts. The temporal spread of CO2into the coal and overlying rock was also studied and is presented

Time (Date)

2020 2025 2030 2035

Fig. 13. CO2 injection rate and cumulative injected volume through a vertical well.

112 P. Dutta, M.D. Zoback / International Journal of Greenhouse Gas Control 9 (2012) 103–116

Fig. 14. CO2 migration across the coal layers.

Fig. 15. Temporal spread of CO2 over the coal and cap rock layers.

P. Dutta, M.D. Zoback / International Journal of Greenhouse Gas Control 9 (2012) 103–116 113

Time (Date)

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Cumulative Gas Inje. Moles(CO2) SC Coal

Gas Moles IPF(CO2) Coal

Gas Moles IPF(CO2) Sand_Fracture

Gas Moles IPF(CO2) Shale_Fracture

Gas Molar Inje. Rate(CO2) SC Coal

ig. 16. CO2 injection rate and cumulative injected volume through a vertical wellith (a) vertical fracture and (b) horizontal fracture.

.2. Vertical well with horizontal and vertical hydraulic fractures

The same vertical well was simulated twice, once each with aertical and a horizontal hydraulic fracture at the base of the well.he results of simulation are presented in Fig. 16. It can be seen fromig. 16(a) that about 1.495 × 1010 gmole of CO2 can be injected intohe coal seam, which is an increase of about 6% compared to theo fracture scenario. However, a comparison of Figs. 13 and 16(a)ould reveal that the drop in injectivity is sharper with the fracture

ompared to the no fracture scenario. With a horizontal hydraulicracture, shown in Fig. 16(b), the increase in the volume of injectedO2 is about 11% and the drop in injectivity is comparable to thatf the vertical hydraulic fracture.

.3. Horizontal well

The results of continuous CO2 injection into the section with a00-m long horizontal well are presented in Fig. 17. As can be seenrom this figure, about 1.679 × 1010 gmole (∼0.738 million ton) of

O2 can be injected into a single section of the Wyodak seam over

period of 20 years, which is an increase of about 12% comparedo that with the vertical well. Out of the total injected volume ofO2, about 83.5% remains trapped in coal and the rest migrates to

Fig. 17. CO2 injection rate and cumulative injected volume through a horizontalwell.

the overlying rock. The initial injectivity is very high due to thehigh contact area of the well with the coal seam but the injectivitydrops sharply after about 8–9 years of injection. This sharp drop ininjectivity could be due to coal swelling resulting from high volumeof CO2 adsorbed into the coal. To investigate this, the change in cleatpermeability with time was observed and is presented for one ofthe coal layers in Fig. 18. It is clear from this figure that the cleatpermeability reduces sharply after only 2 years of injection.

6.4. Intermittent injection with the horizontal well

The results of CO2 injection into the same horizontal well withinjection for 6 months followed by a soak period of 6 months for thefirst 10 years are presented in Fig. 19. Total volume of CO2 that canbe injected is about 1.624 × 1010 gmole, which is about 3% less thanthe volume that can be injected with continuous injection and 9%more than the volume that can be injected with the vertical well.However, the soak periods allow some recovery in cleat permeabil-ity and, as a result, the drop in injectivity is more gradual comparedto the continuous injection scenario. After each soak period, theinjectivity regains due to the gain in cleat permeability.

6.5. Full field simulation – one vertical well in each of the ninesections

To scale up a full-field simulation was run with one vertical wellin each of the nine sections and the results are presented in Fig. 20.It can be seen from the figure that the injectivity goes up initiallyfor the first 2 years before beginning to fall off. Closer look at Fig. 13,which shows similar CO2 injection but with only one vertical wellinto the central section, reveals that there is a small rising trend ofinjectivity in the first couple of years before beginning to decline.Therefore, it is not surprising to see the distinct rise in injectiv-ity within the first 2 years observed in Fig. 20, which may capturethe combined effect of such rising trend from all the nine wells.In Alberta multiwell micro-pilot such initial rise in injectivity wasalso observed (Mavor et al., 2004). The CBM wells in this studywere depressurized after primary CBM production. CO2 injection atmuch higher pressure is likely to open up the closed fractures andenhance the permeability thereby. The total volume of CO2 that can

be injected over the entire nine-section is about 1.25 × 1011 gmole(∼5.49 million ton). Out of this about 77% is retained in coal and therest migrates into the overlying rock.

114 P. Dutta, M.D. Zoback / International Journal of Greenhouse Gas Control 9 (2012) 103–116

Fig. 18. Change in cleat per

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Fig. 19. CO2 injection rate and cumulative injected volume through a horizontalwell but with intermittent injection.

Coal Distributed

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2018 2020 2022 2024 2026 2028 0.00e+0

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Fig. 20. CO2 injection rate and cumulative injected volume th

meability over time.

7. Discussion

The preliminary reservoir simulation for CO2 injection into theWyodak coal seam near the Two Elk Energy Park indicates that thesequestration may be feasible. However, the reservoir is depleted inthe area and no additional recovery of methane is possible. Hence,CO2 sequestration into the coal bed can only be attempted as anon-value-added option. However, the process may be cost effec-tive as some of the existing vertical CBM wells can be utilized forCO2 injection. The results of various simulation scenarios presentedin Section 6 show that it may be possible to inject about 0.658 mil-lion tons of CO2 over a period of 20 years into the central sectionof the area through one vertical well without any hydraulic frac-ture. Placing of a hydraulic fracture at the base of the well mayresult in a 6–10% increase in injected CO2 volume. Furthermore, amarginal 12% increase in CO2 injected volume may be possible witha 600-m long horizontal well instead of the vertical well. The rate ofCO2 injection would also be higher with the horizontal well. How-ever, this increased rate of CO2 adsorption can result in increasedswelling of coal matrix with subsequent reduction in cleat per-meability. As a result, the injectivity can drop sharply. This dropin injectivity can be partially overcome by employing a strategy

of intermittent injection where a 6-month period of injection isfollowed by a 6-month soak period for the first 10 years.

With one vertical well into each of the nine sections, the injectedvolume of CO2 would scale up to about 5.5 million tons after 20

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P. Dutta, M.D. Zoback / International Journ

ears. The simulation exercise carried out under this study coversn area of 4.8 km × 4.8 km (3 mile × 3 mile). The Wyodak coal seamxtends far beyond this limited study area and major part of it isepleted and depressurized. Therefore, the coal seam can provide

substantial sink for CO2 sequestration. However, the storage vol-me of CO2 calculated under different scenarios are only indicativend based on the production trend-matched reservoir parameterss explained in Section 4.2. The actual volume may be slightly dif-erent and should be assessed on site-specific information. Theoalbed geological model was developed on the basis of adequateell log information and this should give some confidence on

he volume of coal in the study area. However, specific reservoirarameters like porosity, permeability, sorption isotherms, and gasaturation should be assessed locally and a more rigorous reser-oir simulation carried out before a field demonstration project isndertaken.

Results of CO2 flow analysis into the overlying rock indicate thatbout 20% of gas may migrate into the overlying rock. These calcu-ations are based on the assumed overlying rock layer permeabilitynd porosity values indicated in Table 3. Once again, the exact vol-me of CO2 migration would be dictated by the actual nature andharacteristics of the overlying rock layers. Nevertheless, it can bemphasized from this study that the nature and characteristics ofhe overlying rock is important for CO2 sequestration and should betudied in details before designing a field demonstration project.

. Conclusion

The paper reports on a preliminary reservoir characterizationnd fluid flow simulation that was carried out to investigate theeasibility of CO2 sequestration into the Wyodak coal seam of theowder River Basin as a possible site of CO2 sequestration near thewo Elk Energy Park. A 3-D geological and reservoir model was builtor the nine-section area of Township 43 range 72 in the Campbellounty of Wyoming for CO2 storage modeling in the Wydoak coaleam using the GEM compositional simulator. The method utilizedublicly available gamma ray logs, well production data, and datavailable through literature. The reservoir geometry was developednd heterogeneity in porosity and permeability therein was cap-ured by the extensive use of geostatistical techniques of Krigingnd Gaussian geostatistical simulation. Production trend matchingas limited to the central section of the area and the model could

easonably predict peak gas rates and the well life. It was furtherhown that the geomechanical stress constraint would put a limitn placing only one injector well per section. Thereafter, differentcenarios of CO2 injection were studied and the following majoronclusions can be derived from the study:

Injection and storage of CO2 into the Wyodak coal seam withinthe study area is feasible.Through a vertical well into one section, it is possible to injectabout 0.658 million ton of CO2 over 20 years.About 12% additional volume of CO2 can be injected through a600-m long horizontal well compared to a vertical well.The loss of injectivity is much higher with the horizontal wellthan that with the vertical well due to loss in permeability bycoal swelling.The loss in permeability with the horizontal well can be partiallyovercome by intermittent injection for 6 months followed by a6-months soak period.Placing one vertical well into each of the nine sections would

result in a scaled-up volume of 5.5 million tons over the entirearea for the same 20-year period.In general, about 20% of the injected CO2 can travel upand migrate into the overlying rock. Therefore, proper

reenhouse Gas Control 9 (2012) 103–116 115

characterization of overlying rock is equally important whiledesigning a CO2 sequestration project.

Acknowledgments

The keen observations and comments of two anonymousreviewers and Dr Stephan Bachu helped in preparing an improvedversion of the paper. The Lead author is thankful to the Co-authorand the School of Geosciences of Stanford University for invitinghim to work as Blaustein Fellow in the Department of Geophysics.

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