Monitoring CO2 storage in brine formations: lessons learned from the 

Frio field test one year post injection 

Susan D. Hovorka , Shinichi Sakurai, Yousif K. Kharaka, H. Seay Nance; Christine 

Doughty, Sally M. Benson; Barry M. Freifeld, Robert C. Trautz, Tommy Phelps, Thomas 

M. Daley 

ABSTRACT 

The Frio Brine pilot is a closely monitored, small volume (1,600 tons), short duration experiment 

using injection of CO2 into a high permeability brine-bearing sandstone of the Frio Formation 

east of Houston, Texas to test the feasibility of using this technique as method to reduce 

atmospheric build up of greenhouse gasses. For the experiment, pure CO2 was injected for 10 

days 1500m below surface. Because the injection period was brief and the formation was on the 

flank of a steeply dipping structural compartment, a year since injection takes us well into the 

post injection phase of monitoring. Key findings relevant to design of the next experiments are: 

(1)	 Understanding site hydrogeology is critical for designing a successful project 

(2)	 Numerical simulation of flow is essential to guided site selection, well design, and tool 

selection 

(3)	 Successful geochemical techniques include detection of CO2 breakthrough at the 

observation well, evolution of formation waters as CO2 interacted with rock and brine, 

and tracers recovered to quantify CO2 saturation. 

(4)	 Field measurements of saturation using time laps neutron logging, cross well seismic, and 

VSP were successful in measuring CO2 plume evolution. 

(5)	 Models and conceptualization suggest that significant CO2 is trapped post injection as 

relative permeability to gas decreases over time (two-phase trapping); measurements 

confirm the correctness of this process 

(6)	 An innovative sampling devise, the U-tube, provided high frequency, minimally altered, 

samples of two-phase fluids in the wellbore during injection 

(7)	 Complex and rapidly changing surface environments and interference among test 

elements create challenging conditions to monitor for CO2 leakage in groundwater and 

soil. Geochemical monitoring in the sandstone above the injection interval provided 

better signal. 

BIOGRAPHICAL SKETCH 

Susan D. Hovorka is a Research Scientist at the Bureau of Economic Geology, Jackson School of 

Geosciences. She is the chief scientist of the Gulf Coast Carbon Center, 

(www.gulfcoastcarbon.org) an academic-industry consortium seeking an economic basis on 

which to move forward on carbon sequestration. Currently she is leading a team in a Frio Brine 

field pilot CO2 injection to assess the cost, safety, and effectiveness of geologic sequestration as a 

mechanism for reducing atmospheric greenhouse gas emissions). She is also active facilitating 

exchange between applied scientists and citizens, with a focus on pre-college students and 

teachers. 

Contact: Gulf Coast Carbon Center at the Bureau of Economic Geology, Box X, The University 

of Texas at Austin, Austin TX 78713, Phone: (512) 471- 4863, Fax: 512 471-0140Email: 

susan.hovorka2beg.utexas.edu 
 

 

 

 

 

 

 

 

 

 

INTRODUCTION 

Field demonstration is widely recognized as an important element in developing a 

national program for geologic storage of CO2. In order to conduct a first closely monitored CO2 

injection in brine in the US, the Frio Brine Pilot experiment was funded by the Department of 

Energy (DOE) National Energy Technology Laboratory (NETL) to be led the Bureau of 

Economic Geology (BEG) at the Jackson School of Geosciences, The University of Texas at 

Austin with major collaboration from GEO-SEQ, a national lab consortium led by Lawrence 

Berkeley National Lab (LBNL). 

The Frio Brine Pilot has four goals: (1) demonstrate to the public and other stakeholders 

that CO2 can be injected into a brine formation without adverse health, safety, or environmental 

effects, (2) measure subsurface distribution of injected CO2 using diverse monitoring 

technologies, (3) test the validity of conceptual, hydrologic, and geochemical models, and (4) 

develop experience necessary for development of the next generation of larger-scale CO2 

injection experiments. In this paper we review the results of the study with the emphasis on 

achieving the fourth goal, providing recommendations relevant to the next generation of field 

tests. 

METHODOLOGY 

The injection site was selected in 2003 after characterization of 21 representative saline 

formations in the onshore US (Hovorka and others, 2000). Sandstones of the Oligocene Frio 

Formation are an ultimate target for large-volume storage because they are part of a thick, 

regionally extensive sandstone trend that underlies a concentration of industrial sources and 

power plants along the Gulf Coast of the United States. However, the specific site selected was 

optimized for a small demonstration and the injection well is not suitable or intended to be a full 

scale injection project. The experimental site is in a historic oil field, where site access, use of an 

idle well as an observation well, wireline well logs, 3-D seismic, and production data were 

donated by the operator, Texas American Resources. 

Detailed characterization was conducted using tradition reservoir assessment tools. This 

included use of seismic and log analysis to define facies, structure, and diagenetic evolution and 

estimation of petrophysical and geochemical properties using core from analogous facies in 

Chambers County to build a quantitative reservoir model. From this characterization, a numerical 

model was created using LBNL TOUGH2 code. Geologically constrained numerical models of 

injection and monitoring scenarios were prepared and used to optimize the experimental design, 

well locations and completion, and monitoring tool selection. The Frio “C” sandstone, a 23-mthick brine bearing interval above oil production was selected as the injection target. The well pad 

was improved, new injection well was completed to near Class I standards, and the existing oil 

production well plugged back and recompleted as an observation well in the injection zone. 

Additional site-specific geologic and petrophysical characterization was completed using new 

core and log suites collected in the new injection well, and baseline cross well and VSP surveys. 

In addition a two-well pumping test using an introduced an florescent tracer was conducted to 

determine hydrologic properties under single phase (brine only) conditions. All of these data were 

used to revise the flow model which was then used as a predictive model to finalize design of the 

experiment. 

The injection was conducted under a Class V experimental well authorization under the 

jurisdiction of the Texas Commission on Environmental Quality (TCEQ) Underground Injection 

Control (UIC) Division. Sandia Technologies, LLC, an experience injection well engineering 

firm served as the field services provider and provided experience to assure that the injection was 

compliant and support the research elements. At the request of TCEQ, the research team prepared 

a report to accompany the Class V application that detailed the information normally put into a 
 

 

 

 

 

 

 

 

 

 

 

class I application that was relevant to this injection. The research team also conducted a public 

notification campaign as part of our public outreach program. We also completed an 

Environmental Assessment an required to obtain federal funding under the National 

Environmental Policy Act. These documents are available for review online 

(www.gulfcoastcarbon.org). From October 4 to14, 2004 the Frio Brine Pilot team injected 1,600 

tons of CO2. at a constant rate of 3kg/sec except for pauses used as pressure-fall off tests. Well 

head pressure was variable, around 800 psi. Gas was delivered as cold liquid at pressure, heated to 

gas at 50 to 70 degrees F, and become supercritical fluid as it descended down tubing. 

Measurement and monitoring of the subsurface CO2 plume was accomplished using a 

diverse suite of technologies in three intervals: the injection zone, above the injection zone, and in 

the shallow near-surface environment. Each monitoring strategy used a pre-injection and one or 

more post injection measurements. Wireline logging, pressure and temperature measurement, and 

geochemical sampling were conducted also during injection. 

In-zone objectives were to measure changes in CO2 saturation through time, in cross 

section, and areally, and to document accompanying changes in pressure, temperature, and brine 

chemistry during and in the months following injection. Tools used for in-zone monitoring 

included five repetitions of logging with the Schlumberger pulsed neutron capture reservoir 

saturation tool (RST), which under conditions of a maximum 35% porosity and 125,000 ppm 

salinity was predicted to be successful in obtaining high-resolution saturation measurements 

across the injection interval. The log analysis team includes researchers from BEG and 

Schlumberger–Doll Labs. An innovative geochemical sampling tool, developed and operated by 

Barry Freifeld and Rob Trautz of LBNL to support in-zone fluid chemistry sampling, is the Utube. The U-Tube is composed of a double length of 9.5 mm O.D. × 1.2 mm wall thickness 

stainless steel tubing, with a check valve open to the reservoir at 1500 m. Formation fluid that 

was collected in the U-Tube was driven at reservoir pressure into evacuated sample cylinders at 

the surface by high pressure ultra-pure nitrogen. Samples were collected hourly to facilitate 

accurate delineation of CO2 breakthrough and recover uncontaminated and representative samples 

of two-phase fluids. 

The near-surface monitoring program measured soil gas fluxes and concentrations, 

introduced tracers, and fluid chemistry in the vadose zone and shallow aquifer in an attempt to 

detect any leaks upward out of the injection zone, especially those rapid enough to cause releases 

in a short time frame such as behind well casing. We also measured the post-injection 

geochemistry of the Frio “B” sandstone above the Frio “C” injection sandstone. 

RESULTS 

Hydrogeologic setting 

The upper Frio in this area is composed of NW-SE elongated fluvial sandstone separated 

by mudstones and shales that can be correlated over the field but not regionally. The upper Frio 

“C”, “B”, and “A” (in lower to upper stratigraphic order) sandstones are part of trend of fluvial 

sandstones that were increasingly reworked beneath the regionally extensive 60 m (200 ft) thick 

shales and mudstones of the overlying Anahuac Formation. The selected injection zone, the upper 

half of the Frio “C” sandstone, is an 22.8 m (75 ft) upward-fining, fine grained, poorly indurated, 

well sorted sandstone. Thin section analysis shows that sandstones are composed of well sorted 

but angular grains, dominantly quartz with about 20% fresh-to-leached orthoclase and plagioclase 

feldspar and altered rock fragments, trace quantities of micas, calcite, organic materials, pyrite, 

and minor clays as grain coats and local matrix. 

Important to predicting matching modelled with observed CO2 plume evolution is accurate 

definitions of the flow unit properties. The massive upper part of the upper “C” sandstone has 
 

 

 

 

 

 

porosities of 30 to 35% and permeabilities of 2,000 to 2,500 md. Finer grained and more layered 

sandstone and clayey sandstone with porosities of 24-28% and permeabilities of 70 to 120 md 

make up the mid-“C” gamma marker and the top “C” transition to the top “C” seal. The top “C” 

seal is composed of shale, sands and siltstones that form a minor seal beneath the regional 

Anahuac Shale but probably a major barrier to vertical flow out of the “C” sandstone. 

Structural analysis of the injection interval using logs and a 3-D seismic volume shows that 

the upper Frio Formation at the test site is within a fault–bounded compartment that is part of a 

system of radial system of faults above the salt dome (Figure 1). Dips within the injection 

compartment are steep. Hand picked interpretation of the FMI log by Schlumberger measured 

dips of 18 degrees to the south at the injection well; interwell correlation measured an average dip 

of 16 degrees south. Neither FMI nor seismic surveys identified fractures or faults in the interwell 

area, although the steep dip is compatible with deformation band structures interpreted in core CT scans. 

A set of single-phase hydrologic tests helped to better define the flow system near the 

injection well. A drawdown test defined the average permeability in the area if the perforated 

zone in the injection and observation well as 2.3 Darcys, a good match to that defined by core 

plug analysis. A two-well tracer test resulted in a breakthough time of the tracer that was 

somewhat slower than predicted. Since porosity is relatively well constrained by measurements 

on core plugs, we refined the effective aquifer thickness to 7.2 m from the original 6.5 meter used 

in initial predictive model. The 10% greater thickness required to match the single phase tracer 

test might be conceptualized as a result of stratigraphic or structural heterogeneity which 

thickened the upper “C” unit/sandstone or of discontinuities in the muddy and laminated sands at 

the top and bottom of the “C” unit/sandstone so the flow field occupied a larger volume of 

sandstone. 

Figure 1. Frio experimental site setting showing geologic context near South Liberty Salt Dome 

and detail of injection well location within a gridded reservoir model made using seismic data of 

the fault block. 
 

 

 

 

Numerical Simulation 

Simulation supported all phases of the experiment. Initial realizations using probabilistic 

data constrained by predicted ranges and heterogeneity of rock and fluid properties were used to 

design the experiment (Hovorka and others, 2004). As site specific data were developed they 

were incorporated into the model. Model runs identified poorly known parameters, in particular 

the correct value for residual saturation, allowing improvement of these parameters to be a focus 

during additional data collection. Model results were used to select the field site, select the 

placement of the new injection well relative to the existing well (used as an observation well), 

define the perforation and injection zone, and optimize the volume and duration of injection. 

Modelled saturations of CO2 were used to select monitoring tools and resulted in rejection of 

some tools as unlikely to be successful and identification of replacements. 

 It is helpful to describe the modelled flow system as four sequential but partly overlapping 

phases. Pre-injection, the flow field containes only brine. Hydrologic and geochemical tests 

showed that methane detected in the brine is present as a dissolved gas, not free gas. During 

injection, flow was mostly radial, dominated by the injection pressure. Shortly after injection, as 

pressure equalized near the wells, modelling predicted that density contrast between CO2 and 

brine (0.6 to 1) will cause gravitational forces become the more important force in controlling 

flow. During this phase, the plume of CO2 is predicted to migrate laterally, updip though the high 

permeability, steeply dipping “C” sandstone, and became larger and more asymmetrical around 

the injection well. It also increases saturation in the upper beds of the “C” sandstone. During the 

last phase of plume evolution, modelling predicts that relative permeability to CO2 will decrease, 

resulting in decreasing mobility, so that CO2 migration slows to almost nothing and saturations 

approach residual saturation. With high permeability and steep dips favouring rapid lateral 

migration during the third phase, and a short injection period, the period of almost no migration is 

predicted to be reached within a few months. 

Geochemical monitoring the plume 

Geochemical tools were successful in monitoring the evolution the CO2 plume. During 

rapid evolution of the plume, the U-Tube sampler was critical in obtaining samples of two-phase 

fluids at high frequency. The sampler produced native formation fluid for two days after injection 

started. Conductivity remained stable as injection began, then pH dropped from 6.7 to 5.9, then 

rose again. A dramatic change in fluid composition was observed in the sample collected 51 

hours after the beginning of injection. Carbon dioxide replaced methane as the dominant gas 

analysed in the quadrupole mass spectrometer. The pH decreased rapidly during the next hour to 

less that 5.8. These changes mark the first appearance or “breakthrough” of supercritical CO2 in 

fluids produced at the observation well. Over the next 24 hours, sharp increases in concentration 

of reaction products was measured: alkalinity increased from 100 to 3000 mg/L as bicarbonate, 

and dissolved Fe increased from 30 to 1,100 mg/L; Mg and Ca also increased (figure 2). Brine 

produced at atmospheric pressure outgased vigorously, and precipitated calcite, iron and 

manganese oxides, so that brine samples appeared dark brown. Sampling 20 days and 184 days 

post injection showed increased pH and decreased metals in the subsurface volumes still occupied 

by CO2. The concentration of dissolved organic carbon (DOC) was low in native brines (1-5 

mg/L), and increased slightly to 5-6 mg/L during injection. However, 20 days post injection DOC 

increased by a factor of 100, and then declined to 4.5 to 7.5 mg/L six months post injection. 

Organic molecules identified in high DOC samples include formate, acetate, and toluene. It is 

possible that this represents a similar phenomenon to iron, in that CO2 dissolved and mobilized 

minor amounts of 
 

 

 

 

 

 

0 

 

 

 

 

 

 

 

 

 

 

 

 

organics. 

1200 

1000 

800 

6/04 8/04 

Fe injection C 

Fe observation C 

Fe observation B 

Mn injection C 

Mn observation C 

Mn observation B 

“ ” 

“ ” 

“ ” 

“ ” 

“ ” 

“ ” 

20 

16 

Fe (mg/L) 

12 

Mn (mg/L) 

600 

8 

400 

4 200 

0 0 

10/5/04 10/6/04 10/7/04 4 12/04 2/05 4/05 

Figure 2. Evolution of metals in brine. The increase mid-day 10/6/04 represents arrival CO2 and 

low pH brine at the observation well. 

The ratio of CO2 to brine produced by the U-tube at the surface increased during the 24 

hours after breakthough, until almost no brine was produced. CO2 breakthrough was faster than 

model predictions, and sweep efficiencies were relatively small, suggesting that gas movement 

occurred along preferential pathways. Gas phase tracer arrivals (corrected for transport up the Utube) range from 48 to 53 hours, with a typical measurement error of 0.5 hours (Freifeld et al., 

2005), which generally agree with the CO2 breakthrough time of ~51 hours. 

Wireline log and geophysical monitoring the plume

 Saturation logs collected with the RST tool, cross-well seismic tomograms, and VSP 

document that the CO2 plume developed similarly to that predicted by modeling. CO2 moved 

radially out from the injection well over the 3 meter perforated interval, with fastest flow in the 

upper and higher permeability zones. Comparing changes in saturation in the observation well 

over time calculated from the reservoir saturation tool (RST) to the to the modeled saturation in 

this same well (Figure 3) shows that by the time the log was collected 4 days after injection, the 

plume was slightly better developed than had been modeled. The assumptions, simplifications, 

and corrections used in the calculation of saturation from RST log response are significant, and 

are described by Sakurai et al. (2005) and Mueller et al. (2005). The modeling conditions are 

reviewed in Doughty (2004). 

The highest saturation measured was on day 10, at the end of the injection period. 

Saturation then declined quickly as CO2 moved away from the injection site. By the time the day 

29 log was collected, this process was decreasing as gas permeability decreased as a function of 

decreasing saturation. Only minor changes in saturation were observed in the next four months. 

The largest non-correspondence between the predicted and observed CO2 saturation is that the 

observed CO2 plume moved more effectively upward though the layered muddy sandstones at the 
 

 

 

 

 

 

top of the “C”, showing that layering was more discontinuous than assumed in the model. A 

repeat logging is planned for 17 months. 

Another view of the observed distribution of CO2 compared to the modeled distribution is 

shown in Figure 4 which compares the cross-well tomogram showing impedance contrast the 

developed as a result of CO2 and is inferred to represent supercritical CO2 saturation. The crosswell survey was completed on day 57 after injection. An azimuth VSP survey tested the 

symmetry of the CO2 plume outside of the plain of the two wells, and shows that the plume is 

more asymmetrical than modeled. 

Figure 3. CO2 saturation at the observation well calculated from RST logs, compared to modelled 

changes in saturation per layer plotted at layer midpoint. Day 66 and 142 logs are corrected for 

borehole effects by simple subtraction of the above-background saturation, and should be 

considered less quantitative. Porosity from log is compared to simplified model input porosity, 

elevations KB datum. 

Surface monitoring 

Monitoring at the surface for leakage signal was not effective because the natural and 

induced noise was large and the pre-perturbation baseline period was short. Examples of natural 

variability include a variably high water table, which resulted in little or no soil gas, and high 

natural CO2 flux because of the swampy forest setting (Ron Klusman, Rome, October 2004) . 

This warm and wet region does not have a period of quiescent biological activity during which to 

identify a leakage signal. Examples of perturbation include atmospheric release of tracer during 

sampling and perturbation of groundwater recharge by well site activities. Venting CO2 during the 

purge cycle of the U-tube sampler released tracer to the atmosphere, which resulted in a rapidly 

developed plume of tracer detection in the soils around the injection wells (Art Wells, Rome, 

October 2004). This aerosol contamination obscures any lekage signal that might have formed 

later at other possible leak points. Groundwater chemistry changed rapidly during the monitoring 

period, with a pre-injection region of high salinity migrating down-gradient across the monitoring 

array. We tentatively attribute these groundwater changes to improvement of the well pad and 

construction of a large fresh water filled mud disposal pit. Bicarbonate, which might serve as a 
 

 

 

 

leakage signal, was variable, but against this background of groundwater evolution, it is difficult 

to interpret. 

Figure 4. Cross well seismic difference tomogram on Day 57. Saturation calculated from RST 

logs for each well are aligned with the tomogram. 

Monitoring above the injection zone proved somewhat more interpretable. Brine from the 

“B” sand, first sampled eight months after injection, showed detectable amounts of PFT tracer 

and slightly elevated bicarbonate, Fe, and Mn relative to pre-injection “C” composition (figure 2). 

This is interpreted as evidence of leakage from the injection interval in the “C” sandstone to the 

overlying “B”. This signature increases confidence that geochemical indicators and tracers may 

be useful in identifying leakage. Additional testing is underway to determine if this leakage is 

because of flaws in remedial well engineering (imperfect remedial squeeze or failed squeeze on 

perforations in the “C”) or indicates that the top “C” shale did not retain CO2. Interpretation of 

seismic data in the injection well also suggests an anomalous area that might be interpreted as 

supercritical CO2 behind casing within the Frio but above the “C” .Follow-up research is in 

design. 

CONCLUSIONS

 Description and quantification of injection zone hydrogeology is a low cost but important 

element. This information is required to support modeling and to interpret the test results. 

Numerical simulation of flow is a second highly effective, low cost tools that should guided site 

selection, well design, and tool selection. 
 

 

 

 

 

 

 

 

 

 

 

 

 

Geochemical techniques were successful in documenting the evolution of the CO2 plume. 

Gas analysis detected CO2 breakthrough at the observation well and aqueous geochemistry 

documented evolution of formation waters as CO2 interacted with rock and brine. Introduced 

tracers provide a unique fingerprint for CO2 and are used to quantify CO2 saturations and CO2 

dissolution. The U-tubes sampler was a novel mechanism to obtain high frequency, minimally 

altered, samples of two-phase fluids in the wellbore during injection 

Geophysical measurements of CO2 saturation using neutron logging (RST), cross well 

seismic, and VSP were successful in measuring plume evolution and CO2 retained in the 

formation over time. This analysis supports the conceptualization that significant CO2 is retained 

as relative permeability to gas decreases over time (two-phase trapping). Complex and rapidly 

changing surface environments and interference among test elements create challenging 

conditions to monitor for CO2 leakage in groundwater and soil., however above-injection-unit 

monitoring shows promise for leak detection. 

REFERENCES CITED 

Daley, T. M, Myer, L., Hoversten, G. M., Peterson, J. E., 2005, Borehole Seismic Monitoring of Injected 

CO2 at the Frio Site, abst., American Geophysical Union, 2005 fall meeting. 

Freifeld, B.M., Trautz, R.C., Kharaka, Y.K., Phelps, T.J., Myer, L.R., Hovorka, S.D., and Collins 

D.J., 2005, The U-tube: A novel system for acquiring borehole fluid samples from a deep 

geologic CO2 sequestration experiment: Journal of Geophysical Research-Solid Earth. 

Hovorka, S. D., Doughty, Christine, Benson, S. M., Pruess, Karsten, and Knox, P. R., 2004, The 

impact of geological heterogeneity on CO2 storage in brine formations: a case study from 

the Texas Gulf Coast, in Baines, S. J., and Worden, R. H., eds., Geological storage of 

carbon dioxide: Geological Society, London, Special Publications, 233, p. 147–163. 

Hovorka, S. D., Romero, M. L., Warne, A. G., Ambrose, W. A., Tremblay, T. A., Treviño, R. H., 

and Sasson, D., 2000, Sequestration of greenhouse gases in brine formations: The 

University of Texas at Austin, Bureau of Economic Geology, hypertext publication at 

http://www.beg.utexas.edu/environqlty/CO2seq/dispslsaln.htm 

Kharaka, Y.K, Cole, D.R., Thordsen, J.J., Kakouros, Evangelos, and Nance, H.S., in press, Gaswater-rock interactions in sedimentary basins: CO2 sequestration in the Frio Formation, 

Texas, USA: Geofluids 

Müller, Nadia, Ramakrishnan, T.S., Sakurai, Shinichi, and Boyd, Austin, 2005, Time-lapse CO2 

monitoring with pulsed neutron logging , hypertext publication at 

http://www.beg.utexas.edu/environqlty/CO2seq/dispslsaln.htm 

Sakurai, Shinichi, Ramakrishnan, T. S., Austin Boyd, Nadja Mueller, and S. D. Hovorka, 2005, 

Monitoring saturation changes of CO2 sequestration: Petrophysical support of the Frio 

brine pilot experiment: Society of Petrophysics and Well Log Engineers 46th Annual 

Logging Symposium, New Orleans, LA.