## Monitoring CO 2 

## 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), s hort duration experiment using injection of CO 2 into a high permeability brine-beari ng 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 CO 2 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 re levant 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 CO 2 breakthrough at the observation well, evolution of formation waters as CO 2 interacted with rock and brine, and tracers recovered to quantify CO 2 saturation.

(4) Field measurements of saturation using time la ps neutron logging, cross well seismic, and VSP were successful in measuring CO 2 plume evolution.

(5) Models and conceptualization suggest that significant CO 2 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 envi ronments and interference among test elements create challenging conditions to monitor for CO 2 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 th e 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. Curre ntly she is leading a team in a Frio Brine field pilot CO 2 injection to assess the cost, safety, and e ffectiveness of geologic sequestration as a mechanism for reducing atmospheric greenhouse g as emissions). She is also active facilitating exchange between applied scientists and citizen s, 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, Fa x: 512 471-0140Email:

susan.hovorka 2 beg.utexas.eduINTRODUCTION

Field demonstration is widely recognized as an important element in developing a national program for geologic storage of CO 2 . In order to conduct a first closely monitored CO 2 injection in brine in the US, the Frio Brine P ilot experiment was funded by the Department of Energy (DOE) National Energy Technology La boratory (NETL) to be led the Bureau of Economic Geology (BEG) at the Jackson School of Geosciences, The Univ ersity 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 CO 2 can be injected into a brine formation without adverse health, safety, or environmental effects, (2) measure subsurface distribution of injected CO 2 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 CO 2 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 afte r characterization of 21 representative saline formations in the onshore US (Hovorka and othe rs, 2000). Sandstones of the Oligocene Frio Formation are an ultimate target for large-volum e storage because they are part of a thick, regionally extensive sandstone trend that under lies 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 injecti on 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 pr operties using core from analogous facies in Chambers County to build a quantitative reservoir m odel. From this characterization, a numerical model was created using LBNL TOUGH2 code. Ge ologically 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 petrophysi cal characterization was completed using new core and log suites collected in the new injec tion 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 u sed 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 Environm ental Quality (TCEQ) Underground Injection Control (UIC) Division. Sandia Technologies, LLC, an experience injection well engineering firm served as the field services provider and provid ed experience to assure that the injection was compliant and support the research elements. At th e request of TCEQ, the research team prepared a report to accompany the Class V application that detailed the information normally put into aclass I application that was relevant to this in jection. 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 CO 2 . 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 CO 2 plume was accomplished using a diverse suite of technologies in three intervals: th e injection zone, above the injection zone, and in

the shallow near-surface environment. Each monito ring strategy used a pre-injection and one or more post injection measurements. Wireline loggi ng, pressure and temperature measurement, and geochemical sampling were conduc ted also during injection. In-zone objectives were to measure changes in CO 2 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 obt aining high-resolution saturation measurements across the injection interval. The log anal ysis team includes researchers from BEG and Schlumberger–Doll Labs. An i nnovative geochemical sampling to ol, developed and operated by Barry Freifeld and Rob Trautz of LBNL to supp ort 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 reser voir pressure into evacuated sample cylinders at the surface by high pressure ultra-pure nitrogen. Samples were collected hourly to facilitate

accurate delineation of CO 2 breakthrough and recover uncontaminated and representative samples of two-phase fluids. The near-surface monitoring program measu red soil gas fluxes and concentrations, introduced tracers, and fluid chemistry in the va dose zone and shallow aquifer in an attempt to detect any leaks upward out of the injection z one, especially those rapid enough to cause releases

in a short time frame such as behind well casi ng. 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 Fo rmation. The selected injection zone, the upper

half of the Frio “C” sandstone, is an 22.8 m (75 ft) upwar d-fining, fine grained, poorly indurated, well sorted sandstone. Thin section analysis show s 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 quantiti es of micas, calcite, organic materials, pyrite, and minor clays as grain coats and local matrix.

Important to predicting matc hing modelled with observed CO 2 plume evolution is accurate definitions of the flow unit properties. The ma ssive upper part of the upper “C” sandstone hasporosities of 30 to 35% and perm eabilities of 2,000 to 2,500 md. Finer grained and more layered sandstone and clayey sandstone with porositi es 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 interpretati on of the FMI log by Schlumberger measured dips of 18 degrees to the south at the injecti on well; interwell correlation measured an average dip of 16 degrees south. Neither FMI nor seismic survey s identified fractures or faults in the interwell area, although the steep dip is compatible with de formation 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 Da rcys, 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 th ickness to 7.2 m from the original 6.5 meter used in initial predictive model. The 10% greater thic kness required to match the single phase tracer test might be conceptualized as a result of st ratigraphic or structural heterogeneity which thickened the upper “C” unit/sandstone or of disc ontinuities 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 gri dded reservoir model made using seismic data of

the fault block.Numerical Simulation

Simulation supported all phases of the experime nt. Initial realizations using probabilistic data constrained by predicted ra nges 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, allowi ng 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 injec tion zone, and optimize the volume and duration of injection.

Modelled saturations of CO 2 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 CO 2 and brine (0.6 to 1) will cause gravitational forces b ecome the more important force in controlling

flow. During this phase, the plume of CO 2 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 CO 2 will decrease, resulting in decreasing mobility, so that CO 2 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 injec tion 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 CO 2 plume. During rapid evolution of the plume, the U-Tube samp ler 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 app earance or “breakthrough” of supercritical CO 2 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 vi gorously, and precipita ted 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 CO 2 . 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 CO 2 dissolved and mobilized

minor amounts of0 organics.

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Figure 2. Evolution of metals in brine. Th e increase mid-day 10/6/04 represents arrival CO 2 and low pH brine at the observation well.

The ratio of CO 2 to brine produced by the U-tube at the surface increased during the 24 hours after breakthough, until almost no brine was produced. CO 2 breakthrough was faster than model predictions, and sweep efficiencies were relatively small, suggesting that gas movement occurred along preferential pathways. Gas phase tracerarrivals (corrected for transport up the Utube) range from 48 to 53 hours, with a typical m easurement error of 0.5 hours (Freifeld et al., 2005), which generally agree with the CO 2 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 CO 2 plume developed similarly to that predicted by modeling. CO 2 moved radially out from the injection well over the 3 mete r perforated interval, with fastest flow in the

upper and higher permeability zones. Comparing ch anges 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 satur ation 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 CO 2 moved away from the injection site. By the time the day 29 log was collected, this process was decreasi ng 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 CO 2 saturation is that the

observed CO 2 plume moved more effectively upward though the layered muddy sandstones at thetop 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 CO 2 compared to the modeled distribution is shown in Figure 4 which compares the cross-we ll tomogram showing impedance contrast the developed as a result of CO 2 and is inferred to represent supercritical CO 2 saturation. The crosswell survey was completed on day 57 after injection. An azimuth VSP survey tested the symmetry of the CO 2 plume outside of the plain of the two wells, and shows that the plume is more asymmetrical than modeled.

Figure 3. CO 2 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 CO 2 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 groundwat er recharge by well site activities. Venting CO 2 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 obscur es 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 ch anges to improvement of the well pad and construction of a large fresh water filled mud di sposal pit. Bicarbonate, which might serve as aleakage signal, was variable, but against this b ackground of groundwater evolution, it is difficult to interpret.

Figure 4. Cross well seismic difference tomogr am 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 rela tive 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 tes ting 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 CO 2

. Interpretation of seismic data in the injection well also suggests an anomalous area that might be interpreted as supercritical CO 2 behind casing within the Frio but above the “C” .Follow-up research is in design.

CONCLUSIONS

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

element. This information is required to support m odeling 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 CO 2 plume. Gas analysis detected CO 2 breakthrough at the observation well and aqueous geochemistry

documented evolution of formation waters as CO 2 interacted with rock and brine. Introduced tracers provide a unique fingerprint for CO 2 and are used to quantify CO 2 saturations and CO 2 dissolution. The U-tubes sampler was a novel me chanism to obtain high frequency, minimally altered, samples of two-phase fluids in the wellbore during injection

Geophysical measurements of CO 2 saturation using neutron logging (RST), cross well seismic, and VSP were successful in measuring plume evolution and CO 2 retained in the

formation over time. This analysis supports the conceptualization that significant CO 2 is retained as relative permeability to gas d ecreases over time (two-phase tr apping). Comple x and rapidly changing surface environments and interfere nce among test elements create challenging

conditions to monitor for CO 2 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

CO 2 at the Frio Site, abst., American Geophysical Union, 2005 fall meeting.

Freifeld, B.M., Trautz, R.C., Kharaka, Y.K., Phel ps, 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 CO 2 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 CO 2 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., Ambr ose, W. A., Tremblay, T. A., Treviño, R. H., and Sasson, D., 2000, Sequestration of gr eenhouse gases in brine formations: The University of Texas at Austin, Bureau of Economic Geology, hypertext publication at http://www.beg.utexas.edu/environqlty/CO 2 seq/dispslsaln.htm

Kharaka, Y.K, Cole, D.R., Thordsen, J.J., Kakour os, Evangelos, and Nance, H.S., in press, Gaswater-rock interactions in sedimentary basins: CO 2 sequestration in the Frio Formation, Texas, USA: Geofluids

Müller, Nadia, Ramakrishnan, T.S., Sakurai, Shinichi, and Boyd, Austin, 2005, Time-lapse CO 2 monitoring with pulsed neutron logging , hypertext publication at http://www.beg.utexas.edu/environqlty/CO 2 seq/dispslsaln.htm

Sakurai, Shinichi, Ramakrishnan, T. S., Austin Boyd, Nadja Mueller, and S. D. Hovorka, 2005, Monitoring saturation changes of CO 2 sequestration: Petrophysical support of the Frio brine pilot experiment: Society of Petrophysics and Well Log Engineers 46 th Annual Logging Symposium, New Orleans, LA.