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

Susan D. Hovorka 1, Christine Doughty2, & Mark H. Holtz1, 

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

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

Berkeley, CA 94720

ABSTRACT

How can we demonstrate that subsurface storage is an effective method of reducing emissions of CO2 to the atmosphere? The Frio Brine Pilot

Experiment is designed to test storage performance of a typical subsurface environment in an area where large-volume sources and sinks are

abundant, near Houston, Texas, USA. We employed extensive preexperiment characterization and modeling to identify significant factors that

increase or decrease risk of leakage from the injection zone. We then designed the experiment to focus on those factors, as well as to test for

presence or absence of events that are not 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

simulator showed that a significant source of uncertainty for subsurface performance of injected CO2is residual CO2saturation during storage. If

initial displacement of water during injection is efficient and capillary effects create the expected residual saturation of 30 percent CO2, the

volume occupied by the plume will be limited, and long-term storage can be expected even in an open system. If, however, during injection, CO2

moves out from the injection well along high-permeability pathways, it may not contact most pores, and residual saturation will have a smaller

effect on storage. Our experiment is therefore designed to monitor plume geometry and CO2saturation near the injection well and closely spaced

observation well. Leakage out of the injection zone as a result of well engineering or other flaws in the seal is also monitored in the sandstone

immediately overlying the injection zone and at the surface using multiple techniques.

Permitting strategies include cooperation among two State agencies, as well as Federal NEPA assessment, because of the innovative aspects

of the experiment.

INTRODUCTION

Diverse stationary sources of CO2concentrated 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 CO2 [1].

Potential risks from business-as-usual atmospheric release of CO2 are significant for this region [2]. Relative sea-level rise, increased storm

severity, and resulting flooding are already of concern in this low-relief coastal area. Increase in these risks introduced by climatic change could

be costly. Increased tropicalization is also of concern in this already warm region. Other negative effects of combustion on the atmosphere in

warm areas, such as ground-level ozone, have increased regional concern about reducing emissions of the byproducts of combustion [3].

In our previous study [4], we found that the Gulf Coast region has a high potential for geologic sequestration of CO2. Thick and permeable

sandstones and extensive shales in the subsurface of this region are well known because of hydrocarbon production, and large opportunities

are recognized for revitalization of reservoirs in decline through a combination of storage and enhanced recovery. For the experiment, however,

selection of injection 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 impact has 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 5 have been completed, and stages 6 and 7 are under way, with stage 8 scheduled for early fall 2004. Results of the completed stages

are reviewed in this paper. The experiment will use 3,000 tons of CO2from 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 Gulf Coast. To reduce perceived risk and liability, we elected to inject into a fault-bounded compartment, which are
common around salt domes. In order to develop a detailed characterization at minimal expense and conduct the experiment with minimal

environmental impact, we decided to develop the experimental site in an oil field. We proposed a site in South Liberty oil field, where access to

several idle wells and a recent 3-D seismic survey were donated by Texas American Resources Company. During scoping modeling, we realized

that the volume of rock through which CO2 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 at depths 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-thick Anahuac shale.

The study area is in the low-topographic-relief, lower coastal plain of 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 experiment site is on the southeast flank of a salt dome (figure 1) within South Liberty oil field. 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 17 to 37 percent, and permeability derived from Frio porosity cross-plotted versus permeability is 14 to 600 md (figure 2). Analysis

of core from the injection well shows that the lower high-permeability zone lies within a thick-bedded, crossbedded fluvial sandstone, and the

highest permeability lies within massive marine, reworked fluvial sandstone beneath the top “C” transgressive marine shale. 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 in the 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). Under these conditions, CO2 will be 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 well has been permitted by the Texas Commission on Environmental Quality, Underground Injection Control Division, as a

Class 5 experimental well with concurrence of the Texas Railroad Commission. However, to assure conformance of injection, 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 of the production interval (2,417 m) and the base of surface casing (621 m). To control behind-casing

leakage and allow isolation of the 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

report assessing environmental impacts of the experiment for National Energy Policy Act (NEPA) review [6].

MODELING

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Modeling using TOUGH2 has helped us identify significant areas of uncertainty that will be resolved by field testing. TOUGH2 is a

general-purpose simulator for multiphase flows in porous and fractured media [7]; here we use a fluid-property model for supercritical CO2[8].

One key uncertainty is to determine the appropriate conceptual model for two-phase behavior of CO2and brine within a heterogeneous

permeability system at field scale. We focus here on two aspects: how CO2 will move into the pore system under pressure from injection and

how it will drain out of the pore system under gravity. An introduced immiscible fluid has a widely observed tendency to minimize the area

wetted. As injection proceeds, the introduced fluid may preferentially move into 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 in thickness (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 CO2 moves into the rock volume with a relatively smooth

front at a rate proportional to zone permeability (figure 3, Case 1). To test the validity of this conceptualization, observation of saturations using

Schlumberger’s RST tool will document the shape and evolution of the 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. At the end of injection, the pressure gradient from the well to the rock volume declines, and gravity becomes a significant force, moving

CO2 upward. Gravitationally driven flow occurs both bed-parallel within these steeply dipping units, resulting in elongation of high-permeability

plumes, and upward. Because highest permeability in the upper part of the Frio “C” is in the reworked sandstone at the top, both factors lead to

maximum spreading of the plume within the upper layers. Some of the CO2that enters each pore will be trapped by capillary forces and left

behind as residual saturation (SGR). Data compiled from the literature [10] suggest that the appropriate SGR for Frio conditions could be 30

percent. Comparing base Case 1, SGR =.05, with Case 2, SGR =.3 (figures 3 and 4), shows the significance of residual saturation in controlling the

fate of CO2. The Case 2 high SGR results in more retention of CO2at the injection well, in turn resulting in slower breakthrough to the observation

well. The largest change is observed after injection, when, within a year, a higher SGR results in near immobilization of the CO2 plume close to the

injection site (figure 3). If residual saturation is less effective, a much larger proportion of CO2remains mobile and moves away from the injection

site to form a more extensive plume. In either case, modeling suggests that CO2 will ultimately dissolve into the pore water and pressure will

decline back toward initial conditions.

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

=.3. 

Figure 4: Modeled CO2 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 or suggest improvements in numerical inputs and assumptions. Breakthrough to the observation well will be measured using

diverse techniques, including saturation measurements using the wireline RST tool, fluid real-time fluid sampling, and detection of natural and

introduced tracers in the injected CO2. Changes in saturation at the observation well measured over time will refine our understanding of the

correct value for SGR. Seismic measurements using crosswell and VSP techniques will help us document geometry of the plume between the

wells and test our assumptions about radial flow during injection and piston like versus highly fingered flow. Monitoring the overlying Frio “B”

sandstone, groundwater, vadose zone, and air for introduced tracer will determine the effectiveness of the system in retaining CO2. Of particular

interest will be quantifying leakage from the remediated existing production well under experimental 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-SEQ project contract No. DE-AC03-76SF00098 Preparation and presentation of this paper was funded by the

John G. and Katherine A. Jackson School of Geosciences under matching funds to the Gulf Coast Carbon Center. We thank our team members

for their past and continuing efforts to conduct this experiment.

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