Tracing the Movement and Fate of Injected CO2 in Geological Reservoirs

Using Stable Isotope Techniques

G. Johnson, B. Mayer, M. Nightingale, M. Shevalier, S. Taylor & I. Hutcheon

Applied Geochemistry Group Department of Geoscience

University of Calgary Calgary, Alberta, Canada

IAEA-CN-186-184

From: IPCC 2007

Introduction CO2 concentrations in today’s atmosphere are higher than at any other time in the last 650,000 years due to: - fossil fuel burning - deforestation - biomass burning

and are expected to double to quadruple

in the next 250 years …

Introduction … likely causing average temperature increases between 1 to >4°C (IPCC, 2007).

To limit the average temperature increase to < 2°C, anthropogenic CO2 emissions to the atmo- sphere must be significantly reduced.

Figure from: IPCC, 2007

Introduction Carbon capture and storage (CCS) is one of several approaches to reduce CO2 emissions into the atmosphere. CO2 injection is possible in: - un-mineable coal beds - in saline aquifers - for enhanced oil recovery (EOR)

Introduction

In Canada, federal and provincial governments anticipate that carbon capture and storage will contribute significantly to

reducing future CO2 emissions

National Post,

Wednesday

July 9, 2008

Calgary Herald, Thursday October 15, 2009

Introduction

Measuring, monitoring & verification (MMV) is an important part of each CCS project: - assess potential leakage pathways (safety) - verify CO2 storage (e.g. carbon credits)

Various monitoring approaches include: - Geophysics: seismic, resistivity etc. - Geochemistry: fluid and gas sampling + chemical and isotopic analyses

to demonstrate that stable isotopes, in concert with geochemical data,

can be used effectively to a) trace the movement of CO2

b) assess pore space saturation with CO2 c) assist in developing carbon budgets for geological CO2 injection projects

Objective

Weyburn

Study Site: Penn West Pembina Cardium CO2 Enhanced Oil Recovery Pilot

• Largest oil pool in Western Canada

• Under production since the 50’s (primary and secondary); enhanced oil recovery (EOR) with CO2 since 2005

• Injected 70,000 tonnes of CO2 between March 2005 and March 2008

• 2 injectors (red); 8 observation wells

Study Site: Geology

Formation: Cretaceous Cardium Formation siliciclastic sandstones & conglomerate Depth: ~1650m

~ 50ºC

~ 19MPa

~ 30 mD up-dip and fracture pattern to the NW

CO2 Supply

CO2 trucked in from regional suppliers

13CPDB = -4.6 ± 1.1 ‰

18OV-SMOW = +28.6 ‰

Penn West Gas Storage

Fluids: - T, pH, EC, alkalinity, TDS - major cations & anions - water isotopes (2H & 18O)

Gases: - composition of casing gases (CH4, C2H6, CO2, N2 ...) - carbon isotope ratios of casing gases (CH4, C2H6, CO2)

3x background sampling

28 monitoring events after commencement of CO2 injection

Methods

Stable Isotope Ratios

Carbon Oxygen

18O [‰] = x 1000

13C [‰] = x 1000

18O/16Osample - 18O/16Ostandard

18O/16Ostandard

13C/12Csample - 13C/12Cstandard

13C/12Cstandard

Carbon Isotope Tracer

If injected CO2 is isotopically distinct, changes in carbon isotope ratios together with chemical parameters indicate CO2 migration & reaction:

13C change in casing gas CO2 collected at well-head in

concert with increase in CO2 mole %

13C change in dissolved inorganic carbon (DIC) in produced fluids with increase in alkalinity

CO2 + H2O H2CO3 HCO3- + H+

• Measure CO2 concentration in gas at baseline and monitoring events

• Measure 13C values of produced and injected CO2 at baseline and monitoring events

• Try to fit a two end-member mixing model to evaluate contributions of injected CO2 at individual wells

Tracing the Movement of Injected CO2

CO2 Content of Casing Gas

start of CO2 injection

Injection CO2 = - 4.6 ‰

13C of Casing Gas CO2

start of CO2 injection

2-Source Mixing Model: Group 1

2-Source Mixing Model: Group 2

Discussion Carbon Isotopes

• Can qualitatively trace the movement of injected CO2

• Two groups - CO2 response and little response

• Can quantify how much CO2 in casing gas is injection CO2

• Insensitive to downhole phase of CO2 thus cannot determine trapping mechanism and cannot quantify CO2 storage

CO2

water

mixing

Water Isotope Ratios at Baseline

Assess Pore-Space Saturation with CO2

e.g. Kharaka,

Cole et al., 2006

Oxygen Isotope Equilibrium

Oxygen in CO2 and H2O will reach isotopic equilibrium rapidly (hours) with CO2 usually assuming the 18O value of water + fractionation (see 18O analyses for waters after Epstein and Mayeda, 1953)

103ln = a (106/T2) + b (103/T) + c

at 25°C = 40.1‰ (Bottinga, 1968)

at 53°C (reservoir temperature) ~ 35‰

H2O H2O

CO2 CO2

At CO2 injection sites, there is so much super-critical CO2 that the oxygen isotope ratio of CO2 may change the 18O value of the reservoir fluids

Oxygen isotope exchange between water and CO2 at Pembina

CO2 provides very little

oxygen. Therefore 18O CO2

= water value + e

CO2 Storage Setting - CO2

much higher concentration and

thus should change the oxygen

isotope value of the water:

maximum 18OH2O shift: +8 ‰

18O of injection CO2

e = 35.5 ‰ @

50°C

Baseline water 18O

Oxygen fraction in system from CO2

18O increase in

group 1 wells by

up to 4 ‰

Water Oxygen Isotope Ratios During CO2 Injection

Quantification of CO2 Pore-Space Saturation based on 18OH2O shifts

Three Assumptions

1. Pore space is saturated with either water (Sw) or CO2 (SCO2)

2. CO2 in contact with water will dissolve according to Henry’s Law until saturated. Excess = free phase

3. Three major sources of oxygen in the reservoir • CO2 as a free phase = A

• CO2 dissolved in water = B

• Water itself = C

– Can calculate XOCO2 as a

function of Sw an SCO2

SCO2 can be calculated from the change in 18O of water

XCO2O

ASCO2 BSw

ASCO2 BSw CSw

Wells

Group 1 Group 2

Parameter

7-11 8-11 9-11 12-12 1-11 10-11 4-12 5-12

XCO2O

0.116 0.063 0.262 0.540 0.077 -0.007 -0.040 -0.066

SCO2 0.118 0.034 0.326 0.637 0.055 0 0 0

Parameter

Quantification of CO2 Pore-Space Saturation using Geochemical

Techniques (based on 18OH2O shifts)

Petrel model

“Very Preliminary” Carbon Budget

based on geochemical data informed by seismic results and reservoir properties input into a Petrel model we:

accounted for 51,000 tonnes of CO2: ~ 70% free phase CO2 ~ 11% dissolved in water ~ 19% dissolved in oil

Discussion Oxygen Isotopes

• Oxygen isotope ratios of CO2 and water are a second parameter that provides qualitative evidence for presence of injected CO2.

• The observed shift in 18O of the reservoir fluids may reveal the extent of CO2 saturation in the pore space

• This parameter is key for predicting the extent of CO2 - fluid - rock reactions.

Conclusions

Knowledge of porespace saturation is essential to determine “Carbon budgets” for CO2 storage projects and thus for quantitatively accounting for injected/stored CO2

Carbon isotopes can be used to identify relative proportions of injected CO2 in the subsurface across the reservoir but cannot determine downhole phase of CO2

Pore space saturations of CO2 can be estimated from the 18OH2O shifts since isotopically distinct CO2 in contact with water changes its 18OH2O

A combination of monitoring techniques (seismic, geochemical, geoelectric etc.) holds the most promise for improving our ability to account for injected CO2 in the subsurface.

Conclusion

The stable isotope composition of CO2 provides in many cases an excellent tracer that enables the assessment of movement and reactions of injected CO2 in mature oilfields and likely also saline aquifers. Wherever possible, geochemical techniques should be an integral part of measurement monitoring and verification (MMV) approaches in carbon capture and storage (CCS) projects.

Acknowledgements

Isotope Science Laboratory - University of Calgary

References • Bottinga, Y., 1968, Calculation of fractionation factors for carbon

and oxygen in the system calcite – carbon dioxide – water: Journal of Physical Chemistry, 72, 800-808.

• Epstein, S., and Mayeda, T.K., 1953, Variations of the 18O/16O ratio in natural waters: Geochimica et Cosmochimica Acta, 4, 213.

• Gunter, W.D., Bachu, S., and Benson, S., 2004, The role of hydrogeological and geochemical trapping in sedimentary basins for secure geological storage for carbon dioxide. In: Baines, S.J., and Worden, R.H., (eds.), Geological Storage of Carbon Dioxide, Geological Society, London, Special Publications, 233, 129-145.

• Kharaka, Y.K., Cole, D.R., Hovorka, S.D., Gunter, W.D., Knauss, K.G., and Freifeld, B.M., 2006, Gas-water-rock interactions in Frio Formation following CO2 injection: Implications for the storage of greenhouse gases in sedimentary basins: Geology, 34-7, 577-580.

• Raistrick, M., Mayer, B., Shevalier, M., Perez, R.J., Hutcheon, I., Perkins, E.H., and Gunter, W.D., 2006, Using Chemical and Isotopic Data to Quantify Ionic Trapping of Injected Carbon Dioxide in Oil Field Brines: Environmental Science and Technology, 40, 6744-6749.