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International Journal of Greenhouse Gas Control 18 (2013) 345–360

Contents lists available at ScienceDirect

International Journal of Greenhouse Gas Control

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

onitoring a large-volume injection at Cranfield, Mississippi—Projectesign and recommendations

usan D. Hovorka ∗, Timothy A. Meckel, Ramón H. Trevinoulf Coast Carbon Center, Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin, Box X, University Station, Austin,X 78713-8924, USA

r t i c l e i n f o

rticle history:eceived 20 September 2012eceived in revised form 27 March 2013ccepted 28 March 2013vailable online 3 May 2013

eywords:.S. Department of Energy Regional Carbonequestration Partnership program

a b s t r a c t

Injection and storage of 4 million metric tons of CO2 have been monitored to observe multiphase fluidflow, to test technologies, to document permanence of storage, and to advance techniques for capacityestimation. The injection interval is the 3000-m-deep fluvial Tuscaloosa Formation at a structural closurethat defines the Cranfield oilfield. Tests were conducted in the oil-producing area as well as in the downdipbrine aquifer. These tests assessed the feasibility, operation, and sensitivity of monitoring using a selectionof tools in the vadose zone, in the shallow groundwater, above the injection zone, and within the injectionzone. Although each monitoring approach merits a separate, detailed analysis, this paper assesses thesuccess of the overall strategy for monitoring and presents an overview of conclusions from multiple

ranfield field testonitoring geologic storage

data sets.Comparisons of modeled to observed reservoir response highlight the difficulties encountered in

uniquely explaining measured pressure and fluid saturation measurements at interwell and field scales.Results of this study provide a cautionary note to regulatory and accreditation end users about the feasi-bility of obtaining unique and quantitative matches between fluid flow models and field measurements.

. Introduction

Since 2008, twenty-five organizations (Table 1) have completedata collection related to characterization, modeling, and mon-

toring of a CO2 injection project at Cranfield, Mississippi, thatas stored 4 million metric tons of CO2 as of the beginning of013. This paper provides an overview of programmatic goals, thepproaches taken to meet those goals, and a view from the perspec-ive of the project leadership of the site’s current status and lessonsearned. Purposes of this paper are to (1) provide a framework toink detailed reports of many project elements that recently haveeen published or are soon to be published, and (2) offer time-elevant recommendations for forthcoming projects on successfulnd improved approaches to accomplishing programmatic goals.

.1. Development of the SECARB Cranfield study

The Cranfield study was selected to meet the goals of the

.S. Department of Energy’s Regional Carbon Sequestration Part-erships (RCSP) program, led by the National Energy Technologyaboratory (NETL). Programmatic goals relevant to field storage

∗ Corresponding author. Tel.: +1 512 471 4863; fax: +1 512 471 0140.E-mail address: susan.hovorka@beg.utexas.edu (S.D. Hovorka).

750-5836/$ – see front matter © 2013 Published by Elsevier Ltd.ttp://dx.doi.org/10.1016/j.ijggc.2013.03.021

© 2013 Published by Elsevier Ltd.

projects are to “. . . develop technologies that will support indus-tries’ ability to predict CO2 storage capacity in geologic formations. . .” and “develop technologies to demonstrate that . . . injectedCO2 remains in the injection zones” (National Energy TechnologyLaboratory, 2011).

During project development, a decision was made that one ofthe SECARB field projects would develop strategies to monitor a CO2enhanced oil recovery (EOR) flood associated with a large volume ofsaline aquifer to develop the practice of “stacked storage,” in whichcurrent EOR operations would support infrastructure, character-ization, and public acceptance for longer term saline storage. Thehost was selected from 767 oil fields in the SECARB area screened tobe CO2-miscible (Holtz et al., 2005; Nunez-López and Holtz, 2007;Ambrose et al., 2008a). Major site selection criteria were (1) suit-ability of the injection site to accomplish the project objectives, (2)willingness of subsurface and surface owners to host the test, (3)cost of preparations, (4) cost and availability of CO2 in adequateamounts at the start of the project period, and (5) suitable holderof CO2 liability.

The 2010 Carbon Sequestration Atlas of the United States andCanada (National Energy Technology Laboratory, 2010) shows 800

large, stationary sources of CO2 in the SECARB region. However,interviews with prospective sources revealed that no power plantsin the region were considering starting carbon capture duringthe project start timeframe (2006 through 2009). A search of

346 S.D. Hovorka et al. / International Journal of Greenhouse Gas Control 18 (2013) 345–360

Table 1Key participants contributing to the Cranfield monitoring project.

Participant name Role in project Key personnel

National Energy Technology Laboratory (NETL) Funding, oversight John Litynski, Tracy Rodosta, BruceBrown

Southern States Energy Board (SSEB) Awardee, administration, reporting Gerald Hill, Kathy Sammons, LeighParson, Kimberly Sams, KennethNemeth

Bureau of Economic Geology (BEG) Technical lead, characterization, monitoring design, modeling,history matching, analysis, data compilation andinterpretation, vadose-zone gas, geochemical, petrophysical,geologic analysis, data archive, reporting, CertificationFramework

Susan Hovorka, Timothy Meckela,Ramon Trevino; J-P Nicota

Denbury Onshore LLC Field operator, CO2 supply via SONAT pipeline, permit holder,injection system design, well drilling, 4-D seismic collection,field wide risk oversight and management (via 24 h techniciansurveillance), health and safety, local stakeholdercommunications (via landman)

Ronald Evans, Fred Walsh, KenCameron, Trevor Richards

Sandia Technologies LLC Monitoring systems design and installation, monitoring health,safety and environment, data management, reporting

David Freeman, Dan Collins

Lawrence Berkeley National Laboratory (LBNL) VSP and crosswell design, contracting and analysis, U-tubesampler design and fabrication, tracer analysis, reservoirmodel, Certification Framework, Core imaging andpetrophysics

Jonathan Ajo-Franklina, Thomas Daley,Paul Cook, Barry Freifeld, ChristineDoughty

Lawrence Livermore National Laboratory (LLNL) ERT design and analysis Charles Carrigan, Xianjin YangOak Ridge National Laboratory (ORNL) Tracer emplacement and analysis, field work Tommy Phelps, David ColeSchlumberger Carbon Services Well logging and interpretation Robert Butscha

Promore—Core Lab Well instrument design and installation Dennis LarsenMulti-Phase Technologies, LLC ERT design and inversion Doug LaBrecque, William DailyUniversity of Mississippi Groundwater sampling Frank Roeker; Robert HoltMississippi State Institute for Clean Energy Technology

(ICET)Groundwater Geochemical Analysis Jeff Lindner, Laura Smith

U.S. Geological Survey, Menlo Park and Jackson MS Deep groundwater sampling and analysis Yousif KharakaUniversity of Texas at Austin Department of Geological

ScienceField laboratory for deep geochemistry Philip Bennett and students

University of Texas at Austin, Department ofPetroleum Geosystems Energizing (PGE)

Modeling and analysis Steven Bryant, Gary Pope

National Risk Assessment Partnership (NRAP) 3-D VSP, Seismic interpretation, joint inversion ERT andcrosswell seismic

Thomas Daley

SIM-SEQ Modeling approach intercomparison Jens Birkholzer, Sumit MukhopadhyayCenter for Frontiers of Subsurface Energy Security

(CFSES)Fluid flow modeling; seismic analysis Mojdeh Delshad;

BP; MicroG LaCoste; Colorado School of Mines Borehole gravity Kevin Dodds; Richard KrahenbuhlUniversity of Edinburgh Noble gases Stuart GilfillanStanford Global Climate and Energy Project (GCEP) Petrophysics—special core analysis Sally BensonCCP Petrophysics—special core analysis Kevin DoddsAmerican Water Works Association (AWWA) Push–pull test—field simulation of CO2 migration to

groundwaterChangbing Yanga

Research Institute of innovative Technology for theEarth (RITE)

Microseismic surveillance Tsutomo Hashimoto; Ziqiu Xue

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a Further information in other papers in this issue. The authors present this table ieaching the conclusions presented in this paper.

otential intermediate-volume, high-concentration sourcesrefineries, chemical plants, and fertilizer plants) determined that,n the project timeframe, there were no available sources thatould supply the target volume (i.e., greater than 1 million metricons) except as cost-prohibitive cold compressed CO2. The bestource–sink pair for achieving DOE’s programmatic goals duringhe target time period was geologically generated CO2 (naturalource) commercially produced from Jackson Dome, Mississippi,Studlick et al., 1990) shipped via pipeline by Denbury Onshore,LC to their Cranfield field (Fig. 1).

The site proved to be valuable for research because many of theomplexities typical of EOR floods are reduced at this site. Cran-eld had a prolonged idle period between the end of production

n 1966 (Mississippi Oil and Gas Board, 1966) and the start of CO2njection in 2008. During this idle period, the reservoir pressureecovered to near-initial pressure as a result of natural water incur-

ion. Such recovery is unusual: typically a CO2–EOR flood is startedt the end of a period of secondary recovery, during which the fieldressure and fluids are highly perturbed, which complicates pre-O2 injection baseline and initial conditions. In addition, Denbury

of listing 40 co-authors, each of whom has made substantive contributions toward

injects CO2 continuously rather than using the water-alternating-gas (WAG) process used in most west Texas floods. Also, rather thanpumping their wells for production as is common elsewhere, Den-bury designs them to self-lift as reservoir pressure increases. Bothof these operational aspects allow us to make useful simplifyingmodel assumptions.

1.2. Characterization at Cranfield

Reservoir characterization for the SECARB test at Cranfield bene-fited from many data sets related to past and current oil production.Wireline logs, core data, and cuttings from the field’s developmentfrom 1944 to 1966 define the geometry and composition of thereservoir and confining system (Fig. 2). Historic operational andproduction data (Hines, 1950; Mississippi Oil and Gas Board, 1966)provide quantitative data for hydrologic and CO2 storage capacity

assessment. As of 2012, commercial preparation for CO2 floodingincluded 29 new wells with modern log suites, whole and sidewallcores, brine and oil samples, and a 3-D seismic survey of the entirefield.

S.D. Hovorka et al. / International Journal of Greenhouse Gas Control 18 (2013) 345–360 347

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Fig. 1. Location of Cranfield field (in red) showinodified from Ambrose et al. (2008b).

The injection zone is the lower Tuscaloosa Formation (Fig. 2)n a broad four-way structural closure at a depth greater than000 m (Fig. 3). Red, terrestrial mudstones define the top of theil-bearing flow unit (informally called the “D–E” sands) thats the CO2 injection zone. Low-permeability mudstones of the

ashita–Fredericksburg Group define the base of the injectionone. The 20- to 28-m-thick D–E injection zone is composed ofomplexly incised channels dominated by chert- and volcanic-ock-fragment-rich sandstones and conglomerates (Kordi et al.,010); these are interpreted as Cretaceous valley-fill to fluvialeposits (Wood and Wolfe, in review). Depositional variability haseen accentuated by diagenetic chlorite, quartz, and local carbonateements (Kordi et al., 2010; Lu et al., 2013). The fluvial stratigraphicnits fine upward, and dark, channel-filling mudstones form localarriers to flow. The fluvial depositional setting creates signifi-ant flow-unit heterogeneity at scales less than interwell spacing200–300 m). These flow units cannot be deterministically mappedsing wireline logs (Lu et al., 2013) or resolved clearly by stratal slic-

ng of the 3-D seismic volume (Hongliu Zeng, Bureau of Economiceology, written communication, 2010).

The lower Tuscaloosa Formation transitions upward to darkudstones and fine-grained, fossiliferous, calcite-cemented sand-

tones of the middle “marine” Tuscaloosa that forms thetratigraphically lowest regional confining zone (Mancini anduckett, 2005; Lu et al., 2011). From reservoir to surface, numerousransmissive sandstones alternate with fine-grained strata (Fig. 2);he thickest fine-grained unit is the Midway shale, approximately00 m above the injection interval. Upward-migrating fluid wouldnter each permeable zone that it contacts (Chabora and Benson,009; Nordbotten et al., 2009; Nogues et al., 2011), attenuatingertical migration.

The complex fluid production history of the Cranfield field addsignificant but unquantified uncertainty to fluid-flow modeling.n initial large gas cap overlying an oil rim was initially recy-led for pressure maintenance during primary production. The

as from the gas cap was eventually produced during field clo-ure, dropping pressure strongly at the end of production. As isypical of depleted oil fields, the pre-CO2-injection fluid distribu-ion was highly uncertain. Ongoing hydrocarbon production from

s screened as prospective for EOR and pipelines.

the Wilcox Formation (2000 m depth), potentially plays a role inlimiting leakage potential at Cranfield by creating a pressure sinkbetween the injection zone and the freshwater and surface envi-ronments.

A fault forming the northeast margin of a crestal graben on theanticline offsets the lower Tuscaloosa “D–E” sandstones (Fig. 3).Hydrocarbon accumulations with separated oil–gas contacts acrossthe fault show that the fault is sealing to horizontal and vertical flowat geologic timescales (Mississippi Oil and Gas Board, 1966). Inter-pretation of 3-D seismic shows that throw on the fault diminishesupward and does not offset the Midway shale.

Freshwater aquifers in the Cranfield area are hosted in poorlyconsolidated, high-conductivity Tertiary sandstones to depths of300–400 m below land surface. These aquifers are separated bymudstone confining zones and have regional gradient to the south-west toward the Mississippi River (Boswell and Bednar, 1985).Additional characterization utilized water wells drilled to depthsof 100–125 m as needed by Denbury for water supply for each ofthe newly drilled injection wells (Fig. 3), gradually building a water-level and hydrochemical data base (Yang et al., 2012). Stratigraphywas characterized in the same wells using a slim-hole gamma-raylogging tool, and sandstone zones were correlated over the sitearea (J. Paine, Bureau of Economic Geology, written communica-tion, 2010). The shallow part (<73 m depth) of the aquifer systemwas cored at a shallow test water well UM1 at the Ella G Lees no.7(EGL7) well pad (Fig. 3) (C. Yang et al., 2013-a). Sediments containlittle carbonate, and iron and sulfate in ground water are variableand locally high (Yang et al., 2012).

In the Cranfield area, uplands are covered by mixed hardwoodsand pine, and wide alluvial areas have been deeply incised by steep-walled valleys, with relief of tens of meters. Some alluvial plainareas are utilized for hay production. Annual rainfall is 158 cm andseasonality is low, with hot, humid summers (average high 32.8 ◦C)and mild winters (average low 3.8 ◦C); there is no quiescent periodto separate deep-sourced from biologic CO2 production. The west-

ern part of the Cranfield study area lies within the Mississippi loessprovince (Leighton and Willman, 1950; Rutledge et al., 1996). Ver-tical 4-m-high loess cliffs form stream banks in the central part ofthe study area, but loess thins toward the east. Alluvial sand and

348 S.D. Hovorka et al. / International Journal of Greenhouse Gas Control 18 (2013) 345–360

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ig. 2. (a) Generalized stratigraphic section at Cranfield, (b) near surface stratigraphyc) detail of the Tuscaloosa Formation generalized from wireline logs at Cranfield, (

ravel deposits are exposed in stream banks. Near-surface corend outcrops are characterized by conspicuous contrasts between

ray reduced sediments and zones of yellow and red oxidized irontains. Research is underway to assess the geochemical reactionsesponsible for mobility of iron and the significance of these obser-ations to monitoring of CO2 leakage. A proposed conceptual model

d on correlations of Jeff Paine, Bureau of Economic Geology, written communication,e facies interpretation by Lu et al. (2013).

is that natural, slow (geologic timescales) transport of methane toshallow environments, typical of hydrocarbon reservoirs (Philip

and Crisp, 1981), may be involved. Methane can be oxidized toCO2, and therefore variable-to-high natural methane concentra-tions could provide a confusing signal against which to assessleakage.

S.D. Hovorka et al. / International Journal of Greenhouse Gas Control 18 (2013) 345–360 349

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ig. 3. Subsurface setting and data collected for characterization and monitoring aroducer Ella G. Lees no. 7 (EGL7), the detailed study area (DAS) and the P-site at re

njection well has an associated groundwater well used for characterization and mo

.3. Development and CO2 injection schedule

Injection operations at Cranfield were staged, involving increas-ng rates and increasing numbers of wells. The start of injection

as tied to conversion of a natural gas pipeline, formerly owned byONAT Corporation, which was subsequently filled with CO2 fromhe natural accumulation at Jackson Dome, Mississippi. CO2 injec-ion was started in June 2008 on the north side of the field. Duringhe period from December 2009 through February 2011, injectionas augmented by federally purchased CO2 to attain higher-than-

ormal (for EOR) injection rates into the water leg of the field, andeservoir response was measured. In April 2010, a rate of 1 mil-ion metric ton/year injection was attained, as well as 1 million

etric tons cumulative injection volume. Injection has continued

field though early 2011. Focused studies were conducted at the reentered historiced producer CFU 47-1 where the vadose zone was instrumented. In addition, eaching.

essentially uninterrupted. However, the rate of increase in the CO2mass stored is no longer as rapid as before because much of thefield is now in production, and the recycled volume of CO2 andmethane makes a significant contribution to the current injectionrate (Fig. 4). As of January 2013, the mass of CO2 stored (injected-recycled) is 4 million metric tons. The cumulative mass injected andre-injected via recycle is 6.8 million metric tons (Denbury, writtencommunication, 2013).

1.4. Linking objectives to monitoring plan

A successful monitoring plan is targeted to project objectives,which can range from research-oriented to fully commercial mon-itoring. The monitoring plan at Cranfield was designed to advance

350 S.D. Hovorka et al. / International Journal of Greenhouse Gas Control 18 (2013) 345–360

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esearch-oriented goals of the RCSP program. In many CO2 geo-ogic storage studies, monitoring is closely and explicitly tied to aisk assessment (for example, World Resources Institute, 2008; Detorske Veritas, 2009). However, risk abatement was not a majorriving force in monitoring design at Cranfield. Denbury, as partf its commercial development for EOR, deployed best practicesor surveillance and optimization of the flood, including regula-ory compliance under the U.S. Environmental Protection Agency’sU.S. EPA) Class II program. In order to practice implementationf geological storage risk approaches, the SECARB team partneredith a project funded by the CO2 Capture Project (CCP) to test

he Certification Framework method (Oldenburg et al., 2009) in anilfield setting (Nicot et al., 2013). Consistent with many other stud-es, well-penetrations of the confining system are found to be theop-ranked leakage risk at Cranfield.

. Results: measurements to assess programmaticuestions

At the Cranfield site, a multi-year effort led to a research designo complete programmatic goals through linked field measurementnd modeling. Availability of tools, expertise to deploy them, andxperience needed to assess the results were important variablesn shaping the design of the monitoring plan. The results of thistudy were intended to provide inputs to future project develo-ers; therefore, this paper presents both successes and areas where

mprovement is needed. In order to evaluate success of monitoringesign, we consider in this paper both how well the monitoringctivities worked toward their designed objectives and how thesectivities might be sufficient or insufficient in the context of U.S.PA’s Class VI rules (U.S. Environmental Protection Agency, 2010).

.1. Geographic and temporal distribution of tools, dataollection, and assessment

The monitoring design accessed four stratigraphic zones: (1)n-zone (IZ): the lower Tuscaloosa “D–E” injection zone; (2)bove-zone monitoring interval (AZMI) set at a 3-m thick, later-lly continuous 100 mD sandstone above the top of the middle

d monitoring activities.

Tuscaloosa regional confining system; (3) the fresh-water sys-tem; and (4) the vadose zone. Geomechanical elements were alsoassessed (cross-zones).

2.1.1. In-zone designTwo IZ-AZMI focus areas were developed. The EGL7 observation

well (Fig. 3) was a reentry of a 1943 production well, Ella G. Lees#7, located 1–1.2 km east of the two initial injectors. The EGL7 wasdesigned to test the effectiveness of IZ and AZMI pressure and tem-perature as a surveillance tool and, as the CO2 flood progressed,measure migration of CO2. The second focus area on the east sideof the field, the Detailed Area Study (DAS; Fig. 3), is an array ofone CO2 injector (CFU31-F1) and two closely spaced observationwells (CFU31-F2 and (CFU31-F3) whose perforations in the IZ werebelow the oil–water interface. The DAS was designed as a labora-tory to assess fluid flow at the interwell scale. Fiberglass casing wasrun for a 143-m interval extending both above and below the injec-tion interval with electrodes for electrical resistance tomography(ERT) (C. Yang et al., 2013-a), a custom mechanical packer, casingdeployed pressure gauges for IZ and AZMI pressure, and fiber-opticcasing deployed distributed temperature sensors and heater cable.The casing-deployed instruments were cemented in place, and thecasing perforations (3180– 3200 m below ground level) were ori-ented to the side of the casing away from the instrument cabling.Bottom-hole pressure gauges, continuous active seismic source andreceiver strings, a U-tube sampler, and a replacement fiber opticcable were deployed on coated tubing (see completion diagrams inButsch et al., 2013).

IZ pressure monitoring was conducted using three tools: (1)conventional gauges that measure tubing pressure at wellhead,(2) pressure gauges with batteries and digital memory that areplaced in wells for a period then retrieved and downloaded, and(3) installed downhole pressure gauges attached to tubing andconnected to surface readout via wireline. Conventional pressuregauges installed at wellhead in production tubing are the lowest

cost pressure monitoring approach and provided high value whenhigh-frequency data was recorded. Pressure gauges at the surfaceare quantitative when the tubing fluid density is well constrainedby density log or intermittent bottom hole pressure measurement.

S.D. Hovorka et al. / International Journal of Gre

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ig. 5. Monitoring pressure in an above-zone monitoring interval (AZMI) is aethod to assess retention in the injection zone.

ubing pressure responds to daily surface temperature which alsoust be filtered out.CO2 arrival in the IZ at a well is indicated by a change in the rate

f change in tubing pressure at wellhead as CO2 displaces brinerom wellbores. Fluid composition was quantified each monthhen produced fluids from each well were separated at Denbury’sell test facility. An innovative method for assessing fluid com-osition change at idle (shut in) wells in the absence of samplingas developed using fluid temperature and density logs (Verma

t al., 2011). Time-lapse saturation measurements were made usingchlumberger’s reservoir saturation tool (RST) in selected produc-rs (Butsch et al., 2013). Injection and production profiles wereollected to measure where the CO2 was leaving and entering theells. Time-lapse 3-D seismic was used to image change in gas sat-ration from pre-injection to two years after the start of injectionDitkof et al., 2011; Zhang et al., 2013).

.1.2. Above-zone designThe project tested feasibility of a first-of-its kind above-zone

onitoring interval (AZMI) concept for geologic storage (Fig. 5;eckel and Hovorka, 2010, 2011). One AZMI installation was a dual

ompletion at the EGL7 well, where the selected AZMI sandstones well as the IZ lower Tuscaloosa Formation D–E were conven-ionally perforated. A remedial cement squeeze assured isolationf the injection zone from the AZMI outside of casing, but a planneddditional squeeze across the AZMI was eliminated because of bud-et constraints; this completion is suspected as a cause of noisend uncertainty in AZMI gauge data at EGL7. Inside the casing, theZMI was isolated by packers, and one PANEX pressure and tem-erature gauge was set at perforations below the upper packer. Aecond similar gauge was set below the lowest packer at the his-oric production perforations in the IZ. Both gauges were equippedith wireline readouts to a surface data logger that resampled and

ransmitted via satellite for real-time internet download.The second AZMI installation was at the DAS where the moni-

oring design was too complex to accommodate a dual completionith multiple perforated zones. Casing-deployed pressure gaugesere set at the AZMI at a depth of 3061 m, 138.7 m above the

op of perforations in both observation wells, with wireline read-ut at the surface on both observation wells (see completioniagram in Butsch et al., 2013). Casing-deployed instrumentationequired drilling a larger diameter borehole and installing a thicker

ement sheath so that the pressure gauge was embedded withinhe cement. The DAS AZMI gauge had a pressure pad designed toouch the rock as well as a directional charge to develop a singleerforation tunnel connecting the gauge to the saline aquifer. The

enhouse Gas Control 18 (2013) 345–360 351

quality of this fluid communication pathway remains an area ofuncertainty in use of data from these gauges.

Fluvial sandstones of the Wilcox Group at depths of1300–2000 m (Fig. 2) are an attractive monitoring target becauseoil production from the Wilcox on the north side of Cranfield prob-ably creates a pressure sink toward which any upwardly movingCO2 might migrate. However, the Wilcox is under production byseveral operators and is a thick, stratigraphically complex interval.Comprehensive monitoring in this zone raised significant logisticalbarriers, and testing was deferred for spot testing toward projectend.

2.1.3. Groundwater designComprehensive monitoring of underground sources of drinking

water presents an unmanageably large target because numerousfreshwater sandstones of the Catahoula Formation are separatedby confining mudstones. Sandstones at 300 m depth are used formunicipal water supply at Natchez, Mississippi, 20 km west ofCranfield. However, no penetrations of this zone were availablein the Cranfield area, and calculations of transport to commercialwells (Vlassopoulos et al., 2011) show that under an assumed worstleakage case, a conservative contaminant plume would move to thenearest municipal wells in 100 years. Such a delayed signal is notof value given the time-frame for the current study.

Denbury’s standard practice of drilling water supply wells todepths of 100–125 m at injection wells provided an opportunity toevaluate the feasibility and best practices of groundwater monitor-ing over the area above the injected plume. Quarterly groundwatersampling by hydrogeologists at the University of Mississippi useda portable pump to purge wells and measure field parameters.Chemical analysis was completed at the Institute of Clean EnergyTechnology (ICET) chemistry laboratory of Mississippi State Uni-versity (R. Holt, University of Mississippi; J. Linder, ICET, writtencommunications, 2009–2012). The University of Mississippi drilledand split-spoon sampled the upper 73 m of sediments at a ground-water test well located on the EGL7 well pad to provide rock dataimportant to hydrologic modeling. In addition, available wells werelogged using a slim-hole gamma-ray logger to constrain the stratig-raphy and local continuity of the freshwater-bearing sandstones(J. Paine, Bureau of Economic Geology, written communication,2010). The local potentiometric surface was mapped to determineshort-term fate and transport and mixing inputs for rock–waterreaction calculations. The mapping required an accurate survey ofwell elevations. The final innovative test was a controlled release ofCO2-saturated groundwater into the 122 m deep sandstone to testin situ and under relevant redox conditions, the rock water reac-tion in the event that CO2 were to leak into this zone (C. Yang et al.,2013-a).

2.1.4. Vadose zone designA thick and complex vadose zone at the Cranfield site presents

challenges for vadose-zone gas monitoring. Vadose zone gases aresensitive to spatially and temporally variable root and microbialrespiration and recharge. To comprehensively monitor the vadosezone, characterization would be required to assess the transportand storage of gas through buried alluvial sands and gravels andoverlying but dissected loess. If CO2 migration from the reservoir tothe near surface were to occur, fluids might be transported laterallythrough sandstones beneath low-permeability loess. Interactionwith shallow water-tables might be expected to seasonally changemigration patterns. In addition, assessment of the impact of geo-logic, historic, and modern infrastructure on gas generation and

transport would be needed. Hydrocarbons tentatively attributedto historic oilfield activities were identified in one outcrop andtwo water wells (personal communication, P. Mickler, Bureauof Economic Geology, 2012; personal communication, J. Lindner,

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52 S.D. Hovorka et al. / International Journal

CET, 2008). Hydrocarbons in near-surface settings are subjecto microbial biodegradation, which releases CO2. In addition, theossibility of natural seepage of methane or other hydrocarbonshould be considered, as such processes are common over oilfieldsSchumacher, 1996). A comprehensive sampling program wouldave to assess the impact of trenches for pipelines and recently

mproved roads and well pads, which were beyond the scope ofur study.

To simplify the vadose monitoring problem to a scope that coulde assessed in sufficient detail to make a contribution to improvingonitoring strategy, a sampling plan was devised that assessed

nly near-well settings to address the identified well-leakage risk.n well pads, suppression of vegetation and control of drainagereate a vadose zone system with reduced local variables and withontrol and access over long time periods. A detailed study area on aistoric well pad, designated the P-site, was identified for a focusedtudy. This approach is in contrast to those of other monitoringlans that monitor a study area with a comprehensive grid (forxample, Lewicki et al., 2005).

Atmospheric monitoring was not considered for this siteecause of the large geographic area, topographical complexity, andall tree cover. Analysis conducted for the Otway test (Etheridget al., 2011) suggested that enhanced methods, such as isotopesnd introduced tracers, would be needed to increase probability ofeakage detection in the atmosphere. Adding engineered tracers tohe large volume of injected CO2 was rejected because of uncertain-ies with respect to how tracers would interact with hydrocarbonss well as concern that they would be redistributed during CO2ecycle. The injected CO2 from Jackson Dome is isotopically dis-inct from ecosystem CO2 (Romanak et al., 2012; Lu et al., 2012a)nd has distinctive noble gas composition (Zhou et al., 2007).

.1.5. Geomechanical designSurface deformation as a method of monitoring pressure

ncrease in the subsurface is well known from groundwater andteam flood examples (for example, Galloway et al., 1999; Davist al., 2000; Dixon et al., 2006). Interest in using this technology forO2 injection has increased after excellent results were reportedt the In Salah project in Algeria (Vasco et al., 2010). A recon-aissance analysis of existing INSAR data (T. Dixon, University ofouth Florida, written communication, 2011) showed possible pos-tive response. Measurement of borehole tilt was sidelined prior toeployment because the depth of the field exceeded the thermalange of instruments available at project start. A surface seismicrray was deployed associated with the high injection rate testeriod in late 2009 through early 2010, but no seismicity wasetected (personal communication, J. Ajo-Franklin, LBNL, 2010). Aicroseismic array installed by Research Institute of Innovative

echnology for the Earth (RITE) Japan consisting of six instru-ents in 100-m-deep boreholes has been continuously collecting

ata since January 2012 with no local seismic events detected (T.ashimoto, RITE, written communication, 2012).

. Discussion: success of the project in meeting therogrammatic goals

In this section, the programmatic goals (1) evaluate protocols toemonstrate that injected CO2 is retained in the injection zones and

2) predict storage capacities are evaluated with emphasis on find-ngs of value to future projects. This paper overviews the researchlements designed to address these goals and provides status withegard to success in reaching these goals. Detailed results are pre-ented in many topical recently published papers, papers in thisssue, or in preparation for publication.

enhouse Gas Control 18 (2013) 345–360

3.1. Evaluating protocols to demonstrate that injected CO2 isretained

Monitoring to assess permanence was undertaken in four zones:in the injection zone (IZ), in a selected above-zone monitoringinterval (AZMI), in the shallowest of the fresh water zones, andin soil–gas transects near wells.

3.1.1. Monitoring to assess permanence in the injection zone (IZ)IZ monitoring is traditionally the focus of oil field surveillance

and expectation of measurements made IZ have been importedto geologic CO2 storage. Predicting the response of oil reservoirsto production and injection is typically challenging, and has beenextensively studied (for example, Capen, 1976; Floris et al., 2001;McVay et al., 2005). The reservoir complexity at Cranfield is high;therefore, one modeling approach implemented in this study usedmultiple geostatistical realizations of permeability distribution tocreate an ensemble of reservoirs that match the responses observedat the DAS (Hosseini et al., 2013). Unresolved uncertainties includelateral channel connectivity at 100 m scales; deterministic per-meability distribution, and the appropriate relative permeability(Lu et al., 2013). The distribution of remaining oil and methanein the reservoir could not be directly measured; so the signif-icance of this uncertainty was assessed. Modeling assessed theimpact of nearby compressible gas (residual gas in gas cap) onCO2 injected into the brine leg (Solano and Nicot, 2010) andfound that the compressibility of nearby gas had a moderate, notdominant, influence on CO2 migration in the adjacent brine. Ageneralized reservoir charge-production-equilibration history wascreated for one model set (Choi et al., 2011, 2013). For assessmentof fluid flow in the DAS area water leg, the response of the near-est part of the reservoir was simplified with an approximation forhydrocarbons and treated as far-field with respect to developingmodels to match observations at the interwell scale (Nicot et al.,2011).

Intermittent bottom-hole measurements on memory gauges area well-known method for geocellular model calibration and ver-ification and are used at Cranfield (Nicot et al., 2009; Hosseiniet al., 2013). However, most lateral boundary conditions aremodeled, not measured, and therefore are a major source ofuncertainty that could potentially mask leakage signal in any set-ting. Increased leakage in response to pressure increases wouldin fact be a type of flow-unit boundary condition. Calibratedmodels with pressure data are the best tool available to makepredictions, but a good match to a model does not ensureretention is in fact occurring, nor does a mismatch to a modelindicate leakage or other failure. Extended IZ hydrologic pumptests may be one way to address the uncertainty in boundaryconditions.

Continuous IZ pressure measurements were tested as a methodfor surveillance of the flood (Meckel et al., 2013). Initiation of injec-tion at wells up to 3 km from observation well EGL7 produceda rapid change in rate of change of pressure response (Meckelet al., 2008; Meckel and Hovorka, 2009), indicating that the rateof pressure change is a valuable tool for understanding reservoirconnectivity and quantification of sensitivity. Comparing injectionschedules from various wells with pressure responses at EGL7confirmed that the eastern graben-bounding fault was sealingto cross-fault pressure, providing hydrologic evidence confirmingcompartmentalization and boundary conditions described duringcharacterization.

Because Denbury production wells lift without pumping, pro-

duction provides a good analog for a leakage signal. During themonitoring period, production was initiated at different times at 29wells in the field. However, no distinctive pressure signal was mea-sured when production began (Fig. 6). Initiation of production via

S.D. Hovorka et al. / International Journal of Greenhouse Gas Control 18 (2013) 345–360 353

F MI reso

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elf-lift produces no identifiable signal greater than ambient noise;his demonstrates that gradual initiation of leakage or slow leakagechronic) would be difficult to detect in continuous pressure data.ne source of noise in the Cranfield data is that of surface activ-

ties such as injection and production rate changes, which wereecorded on a daily basis and not at high frequency. Many variationsn the pressure data, including expected gradual decrease in rate ofhange of pressure as the plume size increases and sharper rates ofhange presumably corresponding to reservoir architecture, couldask leakage signals.4-D seismic and time lapse vertical seismic processing (VSP)

ata were collected to assess downdip and out-of-injection zoneigration of CO2. Injected CO2 was detected in the injection zone

y time-lapse techniques, in which the change in fluid prop-rties was assessed by subtracting the preinjection 3-D surveyrom the 2010 repeat (T. Richards, Denbury, written communi-ation, 2011; Ditkof et al., 2011; Carter and Spikes, 2013; Zhangt al., 2013). Both the 4-D and the VSP are still being analyzedo extract available information. However the deep geologic set-ing is near the limits of resolution of these methods in terms ofbserving thin saturated zones and heterogeneous reservoir con-itions with multiple fluids. The presence of free-phase methane

n the oil rim as a result of gas recycling limits the seismicelocity change in response to the addition of CO2. Robust map-ing of the edge of free-phase CO2 has not yet been successful.

bove-zone migration of CO2 has not been detected; however,mall signal from CO2 and limitations to repeatability precludeefinitive conclusions about moderate or small amounts of leak-ge.

ponse (blue) at EGL7. (b) Rate of change of IZ pressure with timing of the initiation

3.1.2. Monitoring to assess permanence in a selected above-zonemonitoring interval (AZMI)

Pressure monitoring above the injection zone is a well-knowntechnique for surveillance of gas storage reservoirs (Katz, 1971;Katz and Tek, 1981; Katz and Lee, 1990). However, prior to thisproject this method had not previously been implemented in thefield for CO2 storage. The premise of AZMI pressure monitoring isthat fluids leaking out of the injection zone would be at pressurehigher than that of hydrostatic fluids in overlying permeable units;therefore, if the leakage flow path is in contact with the overlyingunits, fluids will enter them and elevate pressure (Zeidouni et al.,2011; Celia et al., 2011). To be effective, the selected AZMI shouldintercept as many hypothetical leakage paths as possible. Sensitiv-ity will be highest in the base of the interval, in thinner zones, andunder closed boundary conditions.

For AZMI monitoring we selected an easily correlated sandstoneabove the middle “marine” Tuscaloosa, the lowest regional unit ofthe confining system (Meckel and Hovorka, 2010, 2011). At the dualcompletion at EGL7, the IZ gauge measured 303.7 bar (4460 psi)in July 2008 and rose to a maximum of 449.0 bar (6512 psi) inJanuary 2010 (Fig. 6a: lower graph; black line). Change in slopeof the pressure increase at wellhead in response to replacement ofbrine by CO2 in the tubing began in July 2010. Because this tub-ing is open to IZ perforations, this signifies breakthrough of CO2in the reservoir. The AZMI gauge started at 304.4 bar (4416 psi) in

July 2008, dipped to 303.3 bar (4399 psi) by the end of September2008, and rose to a maximum of 312 bar (4529 psi) in January 2010(Fig. 6a: lower graph; blue line). The EGL7 AZMI pressure responseshows elements that are tentatively interpreted as geomechanical

354 S.D. Hovorka et al. / International Journal of Greenhouse Gas Control 18 (2013) 345–360

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nd a diagram of the three DAS (Detailed are of Study) wells, F1 (injector), F2 (obserellow signifies interpreted reservoir facies. The “68 m” and “112 m” indicate, respe

esponses, such as a dip in pressure when injection began in a dis-ant well. However, an increase in AZMI pressure of 6.7 bars duringhe time period when pressure increases of 145 bars in the underly-ng reservoir occurred as the result of injection. This simultaneousressure change is interpreted as communication from IZ to AZMIt unidentified locations. EGL7 gauge response was complicated by

recurrent, sudden, intermittent pressure increase of 0.07–0.7 bar1–10 psi), followed by gradual falloff. The small but sharp signalsere interpreted as local to the wellbore, and this interpretationas confirmed when event frequency changed after the well was

eentered with noise-logging equipment; however, no source wasdentified.

Leakage at the EGL7 well itself as a source of pressure increaseas eliminated by means of modeling, which indicated that the

bserved thermal response precluded sufficient local transportTao et al., 2013). We attempted to perform time-lapse geochemicalampling to compare the geochemistry of AZMI brine before injec-ion to the chemistry of the brine 1 year post-CO2 breakthrough.owever, because of aging of the dual completion, formation brine

rom the AZMI was contaminated by completion fluids and CO2-earing IZ formation brine during sampling.

The DAS AZMI gauges in observation wells CFU31-F2 and CFU31-3 (Fig. 7) show geomechanical signal still in analysis. A smalleakage signal was created during efforts to reseat the packer after

orkover a microannulus opened between the IZ and the AZMIauge. A spike in AZMI pressure was observed, followed by fall-offnd recovery.

We conclude from this test that results validate the concept of

ZMI pressure monitoring for leakage detection but highlight theeed for better engineered and well-characterized completions asell as several measuring points both vertically and spatially to

ocate and quantify leakage signal.

ct of the IZ (below). Superimposed on the transect are picked stratigraphic horizons) and F3 (observation). Well diagrams consist of wireline SP-resistivity logs where

horizontal distances in meters from the F2 and F3 wells to the F1 well.

3.1.3. Monitoring fresh-water aquifer to assess permanenceMonitoring drinking water resources during injection has

come to be an expected part of the geologic-storage moni-toring program (Official Journal of the European Union, 2009;National Energy Technology Laboratory, 2009; U.S. EnvironmentalProtection Agency, 2010). This can serve either to assure that nodamage has occurred, or as an element of a program to con-firm that CO2 storage retention is occurring as planned. Modelingrock–water reaction and the perturbation that would be expectedfrom introduction of CO2 into aquifers at Cranfield shows theexpected trends in pH and dissolved inorganic carbon; this wasvalidated in the laboratory (Yang et al., 2011; Lu et al., 2010). Afield test at the EGL7 water well (C. Yang et al., 2013-a) showedthat rock–water reaction under in situ conditions was similar tothat recorded in laboratory studies but showed less reaction. Notrend in groundwater evolution interpreted as leakage has beendetected at Cranfield. However, experiments show that addition ofallochthonous CO2 may not create a distinct and diagnostic waterchemistry that can be easily distinguished from natural variability(C. Yang et al., 2013-a, Fig. 13).

Both temporal and spatial uncertainties are noted in usingground-water monitoring as a tool for assessing permanence. Ifmajor leakage from the injection zone were to occur, retardationby intermediate trapping and dissolution might delay the signalfrom reaching the monitoring points in fresh ground water fordecades or centuries, by which time large amounts of leaked fluidmight already be in transport. In addition, spatial uncertainty aboutwhere the leakage signal might be detected increases with distance

above the injection zone. For example, at Cranfield, gas productionshows that the crest of the domal structure is offset at differ-ent depth intervals. If large volumes of CO2 were to leak fromthe Tuscaloosa at depth, accumulation in the Wilcox Group might

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ranspose the ultimate leakage points northward and away fromuscaloosa injection patterns. This example shows the need for ade-uate characterization of the intermediate (overburden) intervaletween reservoir and surface for designing monitoring strategies.

.1.4. Monitoring to assess permanence via vadose-zone gasransects near wells

A reconnaissance survey of shallow vadose gas near historicells was undertaken with surface measurements and shallowrobes in 2008 and repeated in 2010, with most results showingypical background gas compositions. In the first survey, prior tony CO2 being injected in that part of the field, an elevated con-entration of methane and CO2 was identified in the vadose zoneeneath the recently prepared well pad for well CFU47-1, a pluggednd abandoned production well scheduled to be re-entered androught into service as a producer for the EOR flood. An array ofoil gas instruments was deployed in the area, referred to as the-site (Fig. 3), and the anomaly was mapped over an area of about00 m2 and from the surface to a depth of 3 m. A “process-based”pproach (Romanak et al., 2012) was developed as part of the Cran-eld project for separating in situ-generated gases from exogenousases. The process-based method considers the ratios of N2, O2, CO2,nd CH4 to distinguish between processes that consumed or gen-rated in situ gases in the vadose zone versus leakage processes inhich gas is added from sources at depth. Values of this method-

logy over the traditional mapping of gas concentration include1) separation of leakage signal from in situ natural processes, and2) reduced need for pre-leakage background measurements todentify leakage signal. Analyses of compositional ratios, stable-sotopic, and noble-gas compositions were used to determine that,t the P-site, CO2 is a microbial degradation product of thermo-enic methane (sourced from the deep subsurface) in the presencef atmospheric gases (Romanak et al., 2010).

Sources of deep methane were assessed by sampling the gasesirculated in the drilling mud (mud-logging) during the drillingperation. Initial inspection of sampled isotopic composition ofethane determined that the P-site signal most closely matchedethane from the Tuscaloosa (K. Romanak, Bureau of Economiceology, written communication, 2012). Tie-back and workover of

he CFU47-1 well to fit it for service as a producer allowed assess-ent of the plug and abandonment engineering. Multiple cement

lugs occluding the well casing were found to be intact. However,ome methane had been left in the casing and a section with no cas-ng was identified between the surface casing and the cut-off longtring casing. The migration path of the methane to surface remainsnclear. Monitoring continues, to assess any changes from pre-CO2o post-CO2 arrival in the reservoir and collect additional infor-

ation about migration pathways. Perfluorocarbon tracers (PFT)ere placed at bottom-hole during completion, and monitoring

f soil–gas composition and tracers continues in order to observehether increased or isotopically identifiable Jackson Dome CO2 isetected in soil gases. Production records indicate that CO2 arrived

n the reservoir in the P-site area before August 2010.

.2. Predicting storage capacities

A goal of the RCSP Program is to develop a national storageapacity assessment (Litynski et al., 2008). The overall hydrocarbonapacity of Cranfield field is well known from historic produc-ion (Mississippi Oil and Gas Board, 1966). However, because oil,as, and condensate were accumulated over geologic time, the

ore volume occupancy of these fluids was probably significantlyigher than that of rapidly injected CO2. Interactions of the pres-ure field with capillary entry pressure and relative permeabilityreate reservoir flow conditions in which not all pores are accessed

enhouse Gas Control 18 (2013) 345–360 355

by CO2. This is a well-known porous-media problem referred to as“sweep efficiency.”

Several measurements to assess sweep efficiency have beenmade at the DAS. Measurement of evolution of flow in the DAStransect is used to validate models that can then be applied withincreased confidence at other sites. The DAS site was selected withthe injection zone below the oil–water contact, so that the fluids inthe assessment area would be brine-only, leading to simpler and,therefore, more rigorous measurement and modeling. An injectionwell and two observation wells were placed close together (Fig. 7)so that the interwell heterogeneity would not be extreme. Bothobservation wells were cored and laboratory analyses of porosity,permeability, and relative permeability collected over a 20-m-thick, permeable lower Tuscaloosa D–E interval. Open-hole logs,including dipole sonic and porosity logs as well as baseline cased-hole logs, were collected. An extensive hydrologic test program wasdeveloped to quantify single-phase flow properties of the reser-voir, including placement of water-soluble fluorescein tracer in theinjection well and pressure observation during brine withdrawaland injection.

Time-lapse cased-hole well logging with the Schlumbergerpulsed neutron reservoir saturation tool (RST) was used to calculatedisplacement of brine by CO2 near the wellbores. This tool per-formed well in quantifying CO2 (Butsch et al., 2013); uncertainty isintroduced by the need to correct for change in tubing fluids whenCO2 replaced brine. In addition, minor imperfections in time-lapsedepth-match limited the sensitivity in obtaining a measurement ofno-change above the injection zone.

Time-lapse, cased-hole, dipole sonic was used to calculatechanges in sonic velocity because of CO2 migration. The dipolesonic tool experienced unexpectedly high noise, limiting its utilityin the CFU31-F3 well and decreasing confidence in interpretationof CFU31-F2 (Ditkof et al., 2011). Interference with acoustic signalby the complexity of the well completions is one possible cause ofnoise.

Time-lapse, cased-hole, Schlumberger AIT resistivity logs cal-culate near-wellbore displacement of brine by CO2 by measuringchanges in electrical resistivity. Electrical interference because ofcomplexity of well completions was more extensive than predictedby preinjection tests (Butsch et al., 2013). Time-lapse, cased-hole,resistivity log tools at the Nagaoka site in nonconductive casingdetected both free-phase and dissolved CO2 (Mito and Xue, 2011)and may be valuable for other studies.

Cross-well continuous active seismic source monitoring(CASSM) (Daley et al., 2007) was undertaken between the obser-vation wells. Two piezoelectric sources deployed on tubing in theCFU31-F2 well and two strings of armored multi-level hydrophonesin the CFU31-F3 well to allow high-frequency cross-well measure-ment of time-lapse change in velocity caused by replacement ofbrine by CO2 were installed. Valuable measurements of seismicresponse to pressure increase were made before injection duringthe hydrologic tests; however, failure of hydrophone seals prior tothe CO2 injection phase precluded data collection on multiphaseflow with this instrument. CASSM yielded high-value results at theFrio test site (Daley et al., 2007) and is worthy of repetition withimproved engineering that can withstand the downhole environ-ment.

Time-lapse crosswell tomography was conducted between eachpairs of DAS wells. The initial survey was conducted in the sum-mer of 2009 prior to perforation and tubing completion of the twoobservation wells, CFU 31F2 and CFU 31F3, and the repeat surveywas conducted in the summer of 2010, nine months after the start

of injection and after the end of well-bore logging and geochemi-cal sampling programs. This program yielded tomograms that arevaluable to constrain other data sets (Ajo-Franklin and Daley, 2013;Butsch et al., 2013). Strongly heterogeneous distribution of CO2

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56 S.D. Hovorka et al. / International Journal

as noted between the two observation wells, which are only 30 mpart (Fig. 7).

Cross-well, continuous electrical resistivity tomography (ERT)as successfully undertaken between the two observation wells

X. Yang et al., in this issue). ERT is widely used in shallowontaminated-site applications but has only been used onceefore to measure supercritical CO2 at the GFZ-hosted Ketzin siteKiessling et al., 2010). ERT consists of measurements betweenairs of electrodes. Several surveys can be run each day in auto-ated mode, providing high-frequency updates on the location of

hanges in conductivity that are then related to CO2 concentration.nversions of ERT data collected during the first year of injection athe Cranfield DAS showed systematic changes in reservoir proper-ies that were plausibly linked to CO2 flow (C. Yang et al., 2013-a;oetsch et al., 2013). Additional joint inversions of this novel dataith other types of data may lead to validation of tool output.

The conceptually simple installation of ERT electrodes on theutside of the casing was complicated by requirements to maintain

nonconductive environment (nonconductive casing, electricallysolated and insulated components in the reservoir zone) and byhe need to run individual wires from each electrode to the surface.he installation had to be sufficiently armored to place it at a depthf 3200 m, as well as to prevent conduits through the cabling orement that would allow CO2 to migrate to surface. An extensivengineering effort was therefore undertaken to support installa-ion of ERT. Now that ERT is shown to be successful, improvedechnologies for emplacement of more robust electrodes at closerpacing over longer intervals are needed. Such improved technolo-ies should eliminate the risk created by many individual wires onhe outside of the casing.

A first-of-its-kind deployment of borehole gravity in a CO2torage environment, funded by Carbon Capture Project, yieldeduccessful CO2 detection IZ (Dodds et al., 2013). The value of thisool is detection of changes in mass as water is replaced by CO2,hich is a parameter not evaluated by other geophysical methods.

A novel technique, perturbed distributed temperature sensor,ioneered at the Ketzin project (Freifeld et al., 2007), was plannedor deployment at the DAS. However, the spliced long heater cablesailed, and the distributed temperature sensor (DTS) was used onlyn passive mode (Núnez-López, 2011). High temperatures at depthppear to be a source of noise in DTS.

As a complementary constraint on sweep efficiency, introducednd ambient tracers were sampled at high frequencies using the-tube sampler (Freifeld et al., 2005). The U-tube sampler is a fit-

o-purpose design for research-oriented, high-frequency samplingrom observation wells. The U-tube nitrogen lift line is designedo sample brine prior to arrival of the free-phase CO2 plume.ntroduced gas-soluble perfluorocarbon tracers (PFT’s), krypton,nd SF6 were injected into the injection well using a custom-esigned, tracer-emplacement vessel. The vessel was fabricatedrom a length of oversized flow line plumbed so that the sectionould be isolated from the high-pressure flow line, vented to atmo-phere, allow the introduction of liquid- or gas-phase tracer intohe vessel, and, finally, sweep the contents of the vessel into theell by reconnection with high-pressure CO2. Well completion was

ptimized for gas sampling with small-volume attic spaces in theasing-tubing annulus. The casing was sparsely perforated at oneerforation per 30 cm over 20 m of reservoir. At Cranfield, the U-ube check valves on both samplers became plugged prior to CO2reakthrough. With arrival of CO2, material plugging the line wasissolved or dislodged, and each sampler operated as a single small-iameter, self-lifting tube. Emplaced tracers were used to measure

nteractions of the flow field as the rate was doubled in steps (Lut al., 2012b).

Methane and minor longer-chain hydrocarbons dissolved inmbient brine served as a high-value natural tracer (Romanak et al.,

enhouse Gas Control 18 (2013) 345–360

2010; Lu et al., 2012b), because dissolution of CO2 and releaseof methane are linked to initial contact with brine and thereforeprovide information on evolution of the flow field. Modeling isunder way to quantitatively link geochemical observations andgeophysical observations to optimize the data set to be historymatched (for example, Doetsch et al., 2013).

The first arrival of CO2 at a well, the event known as break-through, is a useful model-calibration parameter. Breakthroughat the two DAS wells was modeled and observed (Hosseini et al.,2013). At the DAS, different measurements provide different esti-mates of arrival times (Table 2). The highest sensitivity tool may bechange of the pH of brine inside the well casing as small amounts offree-phase CO2 dissolve into the non-rock-buffered brine in storagein the casing and tubing. This phenomenon was observed at the Friotest (Kharaka et al., 2006) but not at Cranfield, because the U-tubewas inoperably plugged at critical times. U-tube gas sampling, withthe inlet set in the attic, provided the next detection. At the obser-vation well CFU31F-2, nearest the DAS injector, CO2 influx into thewell was observed in the U-Tube on day 7 after the start of injection.CO2 entry into the well casing for the first several days was slow,approximately at the same rate that it was produced via the U-tube(about 100 L/h). Increase in the rate of influx into the casing allowedthe CO2 column height below the packer to increase greater thanthe 2.3 m “attic” and start to fill the tubing, providing the diagnosticpressure response at wellhead. The RST log collected at this timehad a change from pre-injection baseline over 11 m, with an aver-age calculated change in saturation in this zone of 12%. However,many of these measurements lie within the range of noise; confi-dence in RST increased with increase in saturation and repetition(Butsch et al., 2013).

Breakthrough measured with the U-tube sampler at the DASon day 15 after the start of injection at the DAS observation wellCFU31-F3 showed a similar delay in change in response of surfacetubing pressure; this was complicated by a longer attic (10 m ofunperforated tubing below the packer) and a slower rate of samp-ling with the U-tube because during this period both wells weresampled alternately with the same surface facilities.

Breakthrough of CO2 was measured at EGL7 by change in pres-sure at wellhead, which was then confirmed by density loggingand fluid sampling (personal communication, J. Lu, Bureau of Eco-nomic Geology). Breakthrough occurred 24 months after injectionbegan in that part of the field—much slower than anticipated givenone CO2 injector was located 300-m away. Model predictions (J.-W.Choi, Bureau of Economic Geology, written communication) indi-cated an expected CO2 arrival of about 6 months.

3.3. Modeling to predict storage capacities

Although it is straightforward to allocate the injected volume of4 million metric tons to the area of the Cranfield field, this mea-surement in itself is not valuable to predict the capacity that canbe ultimately stored at Cranfield or, more importantly, in any sim-ilar rock volume. Only through numerical models validated usingfield measurements can such predictions be made. Table 2 com-pares some of the available field measurements with current modelpredictions.

All assessments agree that flow was highly preferential as aresult of geologic heterogeneity and accessed flow paths that aresinuous in three dimensions. At the interwell scale, only a frac-tion of the 20-m-thick sandstone was accessed by CO2. The flowpaths changed with flow rate and evolved over time. Imaged- andtracer-test results have not yet converged to a single efficiency fac-

tor. Further analysis is under way. Monitoring a transect of theflood with multiple tools has provided data to begin to quantify thefield measurement uncertainties. Future work further comparingthe various collected saturation measurements will provide needed

S.D. Hovorka et al. / International Journal of Greenhouse Gas Control 18 (2013) 345–360 357

Table 2Comparison of selected measured and modeled parameters.

Tool CO2 arrival EGL7 CO2 arrival CFU31F2 CO2 arrivalCFU31F3

CO2 Thickness (m)CFU31F2 after 10months

CO2 Thickness (m)CFU31F3 after 10months

U-tube detection NA Day 12 Day 16 NA NATubing pressure rate of change

detection24 months Day 17.5 Day 20.5 NA NA

RST inversion NA Before day 12 Before day 15 18 10.5Cross-well ERT inversion NA Day 72d Day 25d 8d 8d

Updatede Day 12 Updatede Day 16 Updated 3e Updated 3e

Cross-well Acoustic inversion NA NA NA 7.2c 10c

Model prediction 6 monthsb Day 7, 13, 16, 28a Day15, 21, 28, 33a 18a 19.51

a Hosseini et al., Table 4, in this issue, modified model.b Choi, Bureau of Economic Geology, personal communication, 2009.

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nformation to sites that have selected one measurement approach.odeling approaches using probabilistic realizations of flow geom-

try are needed to assess the complexity shown by the system. Thebserved uncertainty envelope is estimated as being of about theame magnitude as the model uncertainty (Table 2).

Data to improve prediction of maximum possible well injec-ion pressure proved to be elusive at the SECARB test at Cranfield.eomechanical data on faults, reservoirs, and seals are needed tovaluate the maximum acceptable pressure and the extent to whichressure in the reservoir is attenuated by interaction with the sealChang et al., 2011).

Injection rate was increased for several months at the DASo the maximum rate that the injection tubing would accept ateld surface pressures of 150 bars (2200 psi). Installed bottom-ole pressure gauges suffered electronic-component failure, asid downhole memory gauges installed to replace them. Pressureesponse of the reservoir was nonlinear and difficult to extrapolateo maximum pressure. Assumptions about boundary conditionsnd reservoir connectivity result in large changes in the modeledressure response. These assumptions then dominate the qualityf the pressure match.

. Discussion

In this paper we highlight the significance of some of the currenteld test results relevant to the design and execution of other fieldrojects. In addition, we outline some of the research remaining toe completed at Cranfield, and draw interim conclusions.

.1. Recommendations from the SECARB Cranfield study to futureeld tests

The current results at this stage of analysis from Cranfieldllustrate the extent to which the implications of uncertaintyn characterization for modeling and monitoring must be care-ully evaluated. Expectations that observed plume evolution willlosely match the modeled evolution may not be realistic (Table 2).ven under conditions of high investment in monitoring such ashose employed at Cranfield, uncertainty remains in the details of

easurements of multi-phase CO2 plume evolution and pressurelevation. If appropriate ranges of uncertainty are not expresseduring project development, such mismatches could lead to a per-eption of project failure. Use of a mass balance or in-zone pressureurveillance approach, in contrast, may not be sensitive enough

o detect slow or chronic leakage. Experience gained in this studyhows the need for new concept defining specifically the types ofismatch between model and observed reservoir response signal a

ondition that indicates current or potential future poor retention.

Dealing with reservoir uncertainty during oil production ismature (for example, McVay et al., 2005) and can serve as a modelfor geologic storage of CO2. Work on formal handling of uncertaintyhas been developed for waste storage (for example, Wu et al., 1999)and contaminant transport (Essaid et al., 1993), and this researchmay provide useful approaches for geologic storage.

Characterization of the intermediate interval between the top ofthe injection interval and the base of fresh water (overburden) hasnot traditionally been undertaken for subsurface studies; however,this innovation is needed if the zone is used as part of monitor-ing. At Cranfield, we experimented in using pressure observationsin an AZMI. Inability to completely interpret results to documentretention shows that better characterization of the AZMI hydrologicsystem, especially the observation well completions, is needed. Inthe next installations that our team is conducting, we are invest-ing in site characterization including repeat formation tester (RFT)measurements of pressure in many zones of the intermediate inter-val, multiple wells with conventional perforated completions in theAZMI, a pre-injection hydrologic characterization using two-wellinjection tests in the AZMI, and surveillance in multiple AZMIs.

Monitoring in near-surface environments is desirable becauseof ease of access; however, ease of access is offset by difficulties inassessing complexity and variability in these dynamic settings. Arelatively limited near-surface monitoring program was deployedat Cranfield. Interpretation of results has required a deeper invest-ment in characterization than planned. For example, to reacha conclusion that no leakage to groundwater was detected, theaquifer water sampling program had to be supported with aquifercharacterization in terms of gradient, hydraulic conductivity,aquifer rock composition, and measurement of rock–water–CO2interaction. The needed characterization program is distinct froma pre-injection baseline in that it provides inputs to models inorder to determine how changes resulting from leakage wouldbe recognized. The model output provides testable conclusionsdemonstrating which signal indicates leakage. Growth toward tra-ditional contaminated site surveillance approaches would be oneapproach to maturation of monitoring; however, documenting theexpected finding of no leakage seems to require a more comprehen-sive program than traditional strategies for tracking a contaminantplume.

4.2. Further work

Commercial injection for EOR continues at Cranfield, and Den-

bury continues to add new well patterns in the southern andwestern parts of the field. Recycling of injectate is the dominantprocess in the developed part of the field, requiring addition of“make-up” CO2 to replace fluid that is retained in the subsurface.

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ata collection also continues at Cranfield, with a focus on long-erm response to sustained injection and storage by systems abovehe reservoir. RITE microseismic monitoring continues until 2015.ubing pressure at wellhead (reservoir response) and above-zoneressure monitoring continues at the DAS. Groundwater geochem-

cal sampling and monitoring soil gas composition at the P-site willontinue until project end.

This paper presents an overview of current understanding, andhis analysis has illuminated a number of limitations on interpre-ation. Work is underway to reduce those limits to interpretation,s well as to quantify the limits encountered. Four groups are fur-her processing time-lapse 3-D seismic and VSP. Joint inversion islanned for ERT and acoustic cross well data as part of the Nationalisk Assessment Program (NRAP). Cranfield characterization andonitoring data support several modeling experiments. For exam-

les, see the SIM-SEQ project (Mukhopadhyay et al., 2012) andenter for Frontiers of Subsurface Energy Security (CFSES) (Delshadt al., 2013).

. Conclusions

The SECARB test underway at Cranfield field, Mississippi, haseen monitoring CO2 injection at rates of about 1 million metricons per year since 2008. The monitoring program was designed torovide research-oriented information to the U.S. Department ofnergy’s programmatic questions: (1) how best to provide assur-nce of storage permanence, and (2) suitable techniques to estimatehe capacity of a rock volume to accept CO2. Monitoring has focusedn four intervals: (1) within the injection zone (IZ), where measure-ents record pressure response to injection and the geometries of

O2 substitution for brine and hydrocarbons; (2) in the above-zoneonitoring interval (AZMI), where pressure response as a poten-

ial leakage indicator is monitored; (3) groundwater geochemistryensitivity to potential leakage signals; and (4) vadose-zone gasomposition sensitivity to potential leakage signal, with a focus oneveloping approaches useful at a hydrocarbon-producing site.

Current results suggest we should temper our expectations thatatching observations to modeling can be used to provide robust

ssurance of containment. In-zone reservoir fluid pressure is a well-nown measure of reservoir response and provides data that testhe credibility of reservoir models. However, under multi-phaseow conditions, a large number of realizations can be reasonablyatched to a pressure response. Further adding to uncertainties,

o single fluid flow model has yet been created for the DAS area ofranfield that can completely match reservoir response data fromultiple types of measurements. Time lapse measurements of CO2

aturation show complexities that are not included in traditionalodel matching. At the DAS, fast and rate-dependent breakthrough

nd transport of natural and introduced tracers confirm prefer-ntial flow though fluvial channel geometries. Comparing one setf reservoir observational data to another creates an uncertaintynvelope quantifying system response to injection. The observedncertainty envelope is estimated as being of about the same mag-itude as the model uncertainty.

The Cranfield study tested the value of high-frequency pressureata that document short-term transients in the rate of pressurehange not visible in low-frequency measurements. Basic obser-ations confirm traditional strengths and applicability of suchbservations for CO2 projects: increase in rate of pressure change inistant wells at the start of injection shows reservoir connectivity;o response confirms isolation predicted during characterization.

owever, many observed changes in pressure are observed, and

hese changes are not related to production but are interpreted asesponses to complexities of the reservoir system. Such complex-ties could mask the leakage of fluid out of the injection zone, in

enhouse Gas Control 18 (2013) 345–360

particular if onset was gradual. Wells perforated in the injectionzone can be monitoring for trends in pressure using low-cost, eas-ily repaired, wellhead-tubing pressure gauges if pressure responseis calibrated to density of the fluid in the tubing. Frequent andhigh-resolution subsurface observations are most useful for reduc-ing uncertainties in subsurface performance when integrated withdata on surface activities of comparable frequency and detail.

As input to capacity assessment, robust measurements showedthat in near-injection well settings, CO2 preferentially movedthrough sinuous channel units, occupying only a fraction of the20-m-thick permeable sandstone reservoir. Sweep efficiency wasobserved to be rate dependent and therefore will not be a singlenumber. The variety of tools selected was effective; even thosethat experienced engineering failure are worthy of redesign andredeployment. Repetition of this type of detailed capacity study inseveral other rock–fluid systems will be of high value for improvingpredictive capabilities of efficiency of occupancy. In future rep-etitions, it is important that the measurements be designed toconstrain fluid flow models so that findings can be extrapolated.However, this type of study is not appropriate for monitoring com-mercial projects.

AZMI pressure monitoring, tested for the first time in a CO2 stor-age environment, shows promise as a leakage detection method.Reduction of uncertainties in interpretation of AZMI pressurechange may be achieved by (1) investing more heavily in hydrologiccharacterization of the AZMI interval, (2) investing more heavily inwell construction to ensure that the AZMI pressure gauge is well-connected to the formation and isolated from the well construction,and (3) laying out a hydrologically interconnected grid so that morethan one well would respond to the same perturbation.

Groundwater monitoring for a geologic storage site should drawupon classic contaminated-site protocols. If groundwater moni-toring is an important element of the program, a characterizationstudy is needed to determine (1) ambient water composition, (2)aquifer rock composition, (3) local and regional potentiometric sur-faces, (4) fate and transport calculations to determine where to setand perforate optimal monitoring wells, and (5) optimization of theconstituents sampled, sampling method, and sampling frequency.To evaluate a finding of no leakage, such a characterization studywill be necessary for each hydrologically separate unit assessed.

The process-based approach to separating in situ-generatedgases from exogenous gases in the vadose zone is being testedfor the first time at a CO2 storage site and shows promise. Val-ues of this methodology include (1) separation of leakage signalfrom in situ natural processes, and (2) reduced need for pre-leakagebackground measurements to identify leakage signal. Preinjectionsurveys of vadose-zone gas identified a localized high CO2 concen-tration that is interpreted as a biodegradation product of methane.Without a process-based approach such a concentration could bemisinterpreted as a result of leakage.

Acknowledgments

The Cranfield study was funded by U.S. Department of Energy,National Energy Technology Laboratory, under contract DE-FC26-05NT42590 to the Southern States Energy Board. Ken Nemethserves as Principle Investigator of the South Eastern Regional Car-bon Sequestration Partnership, under the leadership of Gerald Hilland Kimberley Sams. We acknowledge with gratitude the supportof Denbury Onshore LLC, the site host, and especially former CEO

Tracy Evans, who supported the initial stages of the project, andthe Cranfield field staff led by Ken Cameron and Fred Walsh. Theresearch team leaders listed in Table 1, their staffs, and sponsorshave provided essential contributions. Publication authorized by

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he Director, Bureau of Economic Geology. Editing assistance pro-ided by Amanda Masterson, Lana Dietrich, and Chris Parker.

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