### TESTING EFFICIENCY OF STORAGE IN THE SUBSURFACE: FRIO BRINE PILOT EXPERIMENT

Susan D. Hovorka 1 , Christine Doughty 2 , & Mark H. Holtz 1 ,

1 Gulf Coast Carbon Center, Bureau of Economic Geology, Jackson School of Geosciences, Box X,

The University of Texas at Austin, Austin TX 78713-8924

2 Lawrence Berkeley National Laboratory, Berkeley CA, Cyclotron Road Mail Stop 90R1116 Berkeley, CA 94720
ABSTRACT

Howcan wedemonstrate that subsurface storage is aneffective method of reducing emissions of

CO 2to the atmosphere? The Frio Brine Pilot Experiment is designed to test storage performance ofa typical subsurface environment in an area where large-volume sources and sinks are abundant, nearHouston, Texas, USA. We employed extensive preexperiment characterization and modeling to identify significant factors that increase ordecrease risk ofleakage from the injection zone. We then designed the experiment to focus on those factors, as well as to test for presence orabsence of

events that arenot expected.

A fully developed reservoir model of heterogeneous reworked fluvial sandstones of the Frio Formation documents three-dimensional compartmentalization of the injection horizon by faulting associated with salt-dome intrusion and growth. Modeling using the TOUGH2 simulatorshowed that asignificantsource of uncertainty forsubsurface performance of injected CO 2 is residual CO 2 saturation during storage. If initial displacement ofwater during injection is efficient and capillary effects create the expected residual saturation of 30 percent CO 2 , the volume occupied by the plumewillbe limited, and long-termstorage can be expected even inan open system. If, however, during injection, CO 2 moves out fromthe injection wellalong high-permeability pathways, it may not contact most pores, and residual saturation will have a smaller effecton storage. Ourexperimentis therefore designed to monitorplumegeometry and CO 2 saturation nearthe injection welland closely spaced observation well. Leakage out of the injection zone as a result ofwell engineering or other flaws in the seal is also monitored in the sandstone immediately overlying the injection zone and atthe surface using multipletechniques.
Permitting strategies include cooperation among two State agencies, as wellas Federal NEPA assessment, because ofthe innovative aspects of the experiment.

INTRODUCTION

Diverse stationary sources of CO 2 concentrated on the margins of the Gulf of Mexico include refineries, chemical industries, and electric utilities. Using an international-source database [1], we estimated that annual emissions from 450 stationary sources total 520,000 Gg CO 2 [1]. Potential risks from business-as-usual atmospheric release of CO 2 are significant for this region [2]. Relative sea-level rise, increased storm severity, and resulting flooding arealready of concern inthis low-relief coastal area. Increase inthese risks introduced by climatic change could be costly. Increased tropicalization is also ofconcern in this already warm region. Other negative effects ofcombustion on the atmosphere in

warmareas, such as ground-level ozone, have increased regional concern about reducing emissions of the byproducts of

combustion [3].

Inourprevious study [4], we found that the GulfCoast region has a high potential for geologic sequestration ofCO 2 . Thick and permeable sandstones and extensive shales in the subsurface ofthis region are well known because ofhydrocarbon production, and large opportunities

arerecognized forrevitalization of reservoirs indecline through acombination ofstorage and enhanced recovery. For the experiment, however, selection ofinjection into a brine-bearing sandstone was made. The result is to focus the experiment on storage as a step needed to develop through incentives the combination of storage and enhanced recovery. The site is within a historic oil field in which subsurface data are abundant, surface and subsurface infrastructure is available, and additional environmental impacthas been minimized.

SCOPE OF EXPERIMENT

The experiment is being conducted in nine stages: (1) site selection, with general characterization and scoping modeling; (2) geologic characterization; (3) modeling and experimental-design refinement; (4) permitting; (5) site preparation; (6) detailed site characterization; (7) baseline monitoring; (8) injection and syninjection monitoring; and (9) postinjection monitoring. At the time of writing, June 2004, stages 1 through 5have been completed, and stages 6 and 7 are under way, with stage 8 scheduled for early fall 2004. Results ofthe completed stages

arereviewedinthis paper. The experimentwilluse 3,000tons of CO 2 from refinery sources trucked to the site and injected within a 3-week time period. A new well has been drilled for injection 30 m downdip of an existing oil production well that has been retrofitted as an in-zone observation well. A multidisciplinary team from nine institutions and companies are collaborating to field interconnected measurement, monitoring, and verification (MMV) technologies. These include downhole seismic (cross-well and vertical seismic profiling [VSP]), wireline logging for saturation, downhole geochemical sampling and pumping fluids to the surface to monitor geochemical changes, stable isotopic, noble gas, and introduced perfluorocarbon tracers, aquifer, unsaturated zone, and atmospheric monitoring.

GEOLOGIC SETTING
During site selection we determined that the target is 250- to 400-m-thick, regionally extensive, Oligocene Frio sandstone, which underlies many sources along the GulfCoast. To reduce perceived risk and liability, we elected to inject into a fault-bounded compartment, which arecommon around salt domes. In order to develop a detailed characterization at minimal expense and conduct the experiment with minimal environmental impact, wedecided to develop the experimental site inan oilfield. We proposed a site in South Liberty oil field, where access to several idlewells and arecent3-Dseismic survey weredonated by Texas AmericanResources Company. During scoping modeling, we realized that the volume ofrock through which CO 2 passes is critical to assuring that breakthrough to the observation well will occur. This realization resulted in our selecting the close (30-m) well spacing and the upper part (10 m) of a 23-m-thick upper Frio “C” sandstone as the injection interval. The top Frio“C” lies atdepths of about 1,500 m. The seal on the injection interval is shale overlying the “C” sandstone. The regional seal is the locally 78-m-thickAnahuac shale.

The study areais inthe low-topographic-relief, lowercoastal plainof the Gulf of Mexico on the terrace above the Trinity River. The area was developed as an oil field in 1950 and is now densely wooded marginal wetland that is agricultural and rural residential with other low-density

uses.

CHARACTERIZATION

The experimentsite is on the southeast flankof asaltdome(figure 1)withinSouth Liberty oilfield. Bounding faults radiate away from the salt dome, trending northeast in the site area and dipping to the northwest. Reservoir characteristics and hydrology in the oil-productive zones beneath the brine saturated injection zone suggest that the faults are sealing. At the experiment site, dip on the top Frio “C” is south at 16°. Although dips are steep, correlations and FMI logs identify no evidence of fracturing between the faults. Log-determined porosity in the sandstone is 17to 37percent, and permeability derived fromFrioporosity cross-plotted versus permeability is 14 to 600 md (figure 2). Analysis of core fromthe injection well shows that the lower high-permeability zone lies within a thick-bedded, crossbedded fluvial sandstone, and the highest permeability lies withinmassive marine, reworkedfluvialsandstone beneath the top “C” transgressive marineshale. Sandstones are well sorted, mineralogically complex, minimally cemented, fine sandstones. Shales are bedded or burrowed, plastic, and nonfissile. The low-permeability sandstones that form the lower boundary of the injection interval represent a marine burrowed local flooding surface. Measured temperature inthe injection interval is 56° C, pressure at this depth is measured at 152 bar, and estimated salinity is between 75,000 and 125,000 ppm. No free hydrocarbon is present however brines are nearly saturated with dissolved methane (J. Kharaka, USGS, personal communication, 2004). Underthese conditions, CO 2 willbe supercritical.

Figure 1: Block diagram showing general site setting and a reservoir model showing detailed site stratigraphy in the upper Frio Formation.

Reservoir model prepared by J. Yeh, Bureau of Economic Geology.
WELL CONSTRUCTION AND PERMITTING

The experimental wellhas been permittedby the Texas Commission on Environmental Quality, Underground Injection Control Division, as a Class 5 experimental well with concurrence ofthe Texas Railroad Commission. However, to assure conformance ofinjection, well engineering has been adapted from Class 1 techniques using a design developed by Sandia Technologies LLC. Detailed characterization of the area of review was provided in a report to accompany the Class 5 application [5], cement was injected behind casing for the entire well, and stakeholders were informed through public meetings. The observation well originally had a typical oil-production well construction, with no cement behind casing between the top ofthe production interval (2,417 m) and the base ofsurface casing (621 m). To control behind-casing leakage and allow isolation ofthe injection zone for observation, we have done remedial cement squeezes behind casing to attempt to limit annular flow. The injection will test the success of this remediation and the methods for measuring potential leakage. We also completed a reportassessing environmental impacts of the experimentforNational Energy Policy Act(NEPA) review [6].

MODELING

2Modeling using TOUGH2 has helped us identify significant areas of uncertainty that will be resolved by field testing. TOUGH2 is a general-purpose simulatorformultiphase flows in porous and fractured media [7]; here we use a fluid-property model for supercritical CO 2 [8]. One key uncertainty is to determine the appropriate conceptual model for two-phase behavior of CO 2 and brine within a heterogeneous permeability system at field scale. We focus here on two aspects: how CO 2 will move into the pore system under pressure from injection and how it will drain out ofthe pore system under gravity. An introduced immiscible fluid has a widely observed tendency to minimize the area wetted. As injection proceeds, the introduced fluidmaypreferentially moveinto areas that have already been wetted by that fluid and by-pass

areas that have not been wetted, a process described as fingering

. Analysis [9] suggests that hydrodynamic causes of fingering may be millimeter to meter scale and therefore not significant for field-scale problems; however, stratigraphic heterogeneity may result in significant channeling of flow and bypassing of unwetted rock. To date, modeling done on this project has discretized the rock volume into stratigraphically defined cells averaging 1 m inthickness (figure 2), an interpretation that seems appropriate for heterogeneity observed in core and on logs in massive sandstones that will be major flow units. Models show that CO 2 moves into the rock volume with a relatively smooth frontatarate proportional to zone permeability (figure 3, Case 1). To test the validity of this conceptualization, observation ofsaturations using Schlumberger ’ s RST tool will document the shape and evolution ofthe plume as it moves through the rock volume and past the observation well.

Figure 2: Comparison of permeability calculated from log porosity with permeability assigned to model. During the injection period (modeled as 14 days), flow is dominated by pressure at the well and is dominantly radial out from the injection well. Atthe end ofinjection, the pressure gradient from the well to the rock volume declines, and gravity becomes a significant force, moving CO2 upward. Gravitationally driven flowoccurs both bed-parallel withinthese steeply dipping units, resulting in elongation ofhigh-permeability plumes, and upward. Because highest permeability inthe upperpartof the Frio“C” is inthe reworkedsandstone atthe top, both factors lead to maximum spreading ofthe plume within the upper layers. Some ofthe CO 2 that enters each pore will be trapped by capillary forces and left behind as residual saturation (S GR ). Data compiled from the literature [10] suggest that the appropriate S GR for Frio conditions could be 30 percent. Comparing base Case 1, S GR =.05, withCase 2, S GR =.3 (figures 3 and 4), shows the significance ofresidual saturation in controlling the fate of CO 2 .The Case 2high S GR results inmoreretention of CO 2 atthe injection well, inturn resulting inslowerbreakthrough to the observation well. The largestchange is observed afterinjection, when, withinayear, ahigherS GR results innearimmobilizationof the CO 2 plume close to the injection site (figure 3). If

residual saturation is less effective, amuchlargerproportion of CO 2 remains mobileand moves away from the injection site to form a more extensive plume. In either case, modeling suggests that CO 2 will ultimately dissolve into the pore water and pressure will decline backtoward initialconditions.

3Figure 3: Modeled crosswell (structural dip) plume geometry time series for two different residual saturations: Case 1 S GR =.05; Case 2 S GR

=.3.

Figure 4: Modeled CO 2 saturations at injection and observation wells versus time.

ASSESSMENT OF RESULTS
Matching detailed data collected at the injection site over a short (less than 1-year) period to model results can confirm the validity of conceptual models orsuggest improvements innumerical inputs and assumptions. Breakthrough to the observation wellwillbe measured using diverse techniques, including saturation measurements using the wireline RST tool, fluid real-time fluid sampling, and detection ofnatural and introduced tracers in the injected CO 2 . Changes in saturation at the observation well measured over time will refine our understanding of the
correct value for S GR . Seismic measurements using crosswell and VSP techniques will help us document geometry of the plume between the wells and test ourassumptions about radial flowduring injection and piston likeversus highly fingered flow. Monitoring the overlying Frio “B” sandstone, groundwater, vadose zone, and airforintroduced tracerwilldetermine the effectiveness of the system in retaining CO 2 . Ofparticular interest willbe quantifying leakage fromthe remediatedexisting production wellunderexperimental conditions.

ACKNOWLEDGEMENTS

This research is funded by U.S. DOE National Energy Technology Laboratory under contract No.DE-AC26-98FT40417 to the Bureau of Economic Geology and by the GEO-SEQprojectcontract No. DE-AC03-76SF00098 Preparation and presentation of this paperwas funded by the John G.and Katherine A. Jackson School of Geosciences undermatching funds to the GulfCoast Carbon Center. We thank our team members fortheirpast and continuing efforts to conduct this experiment.

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