1. Schlumberger Private Oxyfuel Flue Gas, Steel and Rock Implications for CO 2 Geological Storage 1 st International Oxyfuel Combustion Conference, Cottbus (Germany), 2009 Sep 8 Matteo Loizzo Schlumberger Carbon Services engineering manager

2. 2 Schlumberger Carbon Services Schlumberger Private Geological storage performance factors “I’ll pay you 50 € /t to take 6 Mt/year for the 40 years of life of my power plant, with a reliability of 4 , and with no measurable leaks.”

3. 3 Schlumberger Carbon Services Schlumberger Private Some definitions – European Directive 2009/31/EC ““Geological storage of CO 2 ” means injection accompanied by storage of CO 2 streams in underground […] rock layers” –Deep saline formations and (depleted) oil and gas reservoirs "A CO 2 stream shall consist overwhelmingly of carbon dioxide. Concentrations of all [contaminants] shall be below levels that would […] adversely affect the integrity of the storage site or the relevant transport infrastructure”

4. 4 Schlumberger Carbon Services Schlumberger Private What is in the rock before we inject CO 2 ? EOR/EGR: Enhanced hydrocarbon Recovery –Oil recovery rate ~40% of OOIP Gas: >90% –Initial production, then pressure maintenance (water or gas), then tertiary recovery Issues: unconnected/heterogeneous reservoirs, pressure decline, water… –CO 2 is lighter (but not so much) so it can sweep the “ceiling” and reasonably miscible so it reduces fingering Minimum Miscibility Pressure ~10 MPa Water Alternate Gas to sweep the floor as well –Oil, water, gas Depleted (gas) reservoirs  very low pressure gas, and water Deep saline formations  salty water (brine)

5. 5 Schlumberger Carbon Services Schlumberger Private Where does the water go? Water needed for most contaminants’ reactions CO 2 -water displacement –Sharp front, residual saturation S rw –Evaporation of residual water in the plume Like “salting out”  does it really affect injectivity? –Diffusion of CO 2 and contaminants at the edges of the plume Depends on exchange surface, upside  solubility trapping Shut-downs  water flows back –Near reservoir and wells affected Source:Azaroual et al., ENGINE Workshop, 2007

6. 6 Schlumberger Carbon Services Schlumberger Private Contaminants in deep rock – experience and insights Injection of flue gas for pressure maintenance In-situ combustion –Air injection Including “rich air” after N 2 removal –Low and high temperature  total O 2 injection rate, heavier hydrocarbon chains Raw Seawater Injection –Oxygenated water Acid gas disposal –CO 2 +H 2 S

7. 7 Schlumberger Carbon Services Schlumberger Private Potential issues – Sulfate-Reducing Bacteria Reduce sulfur (SO 4 /SO 3 ) to H 2 S –Form injectivity-reducing biofilms in near wellbore Biofilms enhance steel corrosion in tubulars –H 2 S can lead to the precipitation of FeS and S (with NO 2 ), reducing injectivity Requirements –Nutrients: volatile fatty acids, available from (long chain) hydrocarbon LTO – depleted reservoirs; phosphates (?); nitrogen Can use thermodynamic inhibitors like methanol or diethylene-glycol, or other C sources –Temperature: surface to ~90ºC Risk mitigation –Low pH, high salinity (deep saline formations), O 2 inhibit growth –NOx (nitrates) control SRB by bio-exclusion Aerobic bacteria?

8. 8 Schlumberger Carbon Services Schlumberger Private Potential issues – H 2 S geochemistry Weak acid Can precipitate iron sulfide or elemental sulfur (with nitrites) –Reservoir plugging and injectivity reduction Risk mitigation –Iron in reservoir (hematite or siderite) can scavenge H 2 S Additional issues –“Sour” steel corrosion, Stress Corrosion Cracking

9. 9 Schlumberger Carbon Services Schlumberger Private Potential issues – SO 2 geochemistry Very soluble in water, oxidizes to sulfuric acid –O 2 scrubber, requires metal catalysts? –Simulations (Xiao et al.) suggest a pH 0 zone ~10-100 m from the injection well Smaller acid area with carbonates, reduced mineralization potential –Might reduce FeS scaling? Readily precipitates anhydrite (CaSO 4 ) and barite (BaSO 4 ), with limited solubility – “swap” with CO 2 –Reservoir plugging, injectivity reduction  HCl/HF used for reservoir stimulation Bigger risk for carbonates, interaction with wormholing?

10. 10 Schlumberger Carbon Services Schlumberger Private Potential issues – O 2 geochemistry Hydrocarbon oxidation –Low temperature (no sustained combustion) or high temperature LTO may slightly damage recovery  oil emulsions –Requires “light” oil (C7 or heavier) Rock oxidation –Iron in rock or water, Fe 2+  Fe 3+, which then precipitates as ferric hydroxide  competing with H 2 S reduction? Risk mitigation –Not enough O 2

11. 11 Schlumberger Carbon Services Schlumberger Private Potential issues – corrosion CO 2 “sweet” corrosion, reasonably mild –Uniform (vs. pitting), possible protection from FeCO 3 layer Contaminants will increase corrosion, synergistic effects –O 2 concentration seems to be detrimental Removes FeCO 3 Will produce pitting in 13Cr Corrosion Resistant Alloy  <10 ppb May passivate steel, contrasted by SO 2 –H 2 S from SRB may add Sulfide Stress Corrosion and pitting –Chlorides in formation water lead to Stress Corrosion Cracking

12. 12 Schlumberger Carbon Services Schlumberger Private Corrosion control Corrosion Resistant Alloy –Very expensive metallurgy, poorly tested for all contaminants in flue gas Risk mitigation –Coating  hard to protect casing connections, wireline damage –Inhibitors  expensive, may play a role in SRB growth Main point: corrosion requires water! –Dehydrating CO 2 streams proved most effective corrosion control Reduction or elimination of Water Alternate Gas EOR strategy by Kinder Morgan –Injection breaks and formation water flow back May be reduced by formation plugging at the edge of the plume

13. 13 Schlumberger Carbon Services Schlumberger Private Conclusions Flue gas-rock interactions –Precipitation of insoluble scale and plugging of rock pores in the near wellbore seems to be the main risk SO 2, H 2 S, O 2 Iron and carbonates risk factors, but some competing effects may help Some standard control mechanisms in use in the O&G industry Characterize reservoir chemistry (rock and water), core floods –“Preventive” hydraulic fracturing to mitigate scaling? –Biofilms might be an issue, especially with intermittent injection Corrosion –No water Water flow back during injection breaks –Transport “weakest link” Biggest impact of CRA adoption