Oxyfuel Flue Gas, Steel and Rock Implications for CO 2 Geological Storage

1. Oxyfuel Flue Gas, Steel and RockImplications for CO2 Geological Storage 1st International Oxyfuel Combustion Conference, Cottbus (Germany), 2009 Sep 8 Matteo Loizzo Schlumberger Carbon Services engineering manager

2. Capacity Injectivity Containment 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. Some definitions – European Directive 2009/31/EC • ““Geological storage of CO2” means injection accompanied by storage of CO2 streams in underground […] rock layers” • Deep saline formations and (depleted) oil and gas reservoirs • "A CO2 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. What is in the rock before we inject CO2? • 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… • CO2 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. Where does the water go? • Water needed for most contaminants’ reactions • CO2-water displacement • Sharp front, residual saturation Srw • Evaporation of residual water in the plume • Like “salting out”  does it really affect injectivity? • Diffusion of CO2 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. Contaminants in deep rock – experience and insights • Injection of flue gas for pressure maintenance • In-situ combustion • Air injection • Including “rich air” after N2 removal • Low and high temperature  total O2 injection rate, heavier hydrocarbon chains • Raw Seawater Injection • Oxygenated water • Acid gas disposal • CO2+H2S

7. Potential issues – Sulfate-Reducing Bacteria • Reduce sulfur (SO4/SO3) to H2S • Form injectivity-reducing biofilms in near wellbore • Biofilms enhance steel corrosion in tubulars • H2S can lead to the precipitation of FeS and S (with NO2), 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), O2 inhibit growth • NOx (nitrates) control SRB by bio-exclusion • Aerobic bacteria?

8. Potential issues – H2S 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 H2S • Additional issues • “Sour” steel corrosion, Stress Corrosion Cracking

9. Potential issues – SO2 geochemistry • Very soluble in water, oxidizes to sulfuric acid • O2 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 (CaSO4) and barite (BaSO4), with limited solubility – “swap” with CO2 • Reservoir plugging, injectivity reduction  HCl/HF used for reservoir stimulation • Bigger risk for carbonates, interaction with wormholing?

10. Potential issues – O2 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, Fe2+  Fe3+, which then precipitates as ferric hydroxide  competing with H2S reduction? • Risk mitigation • Not enough O2

11. Potential issues – corrosion • CO2 “sweet” corrosion, reasonably mild • Uniform (vs. pitting), possible protection from FeCO3 layer • Contaminants will increase corrosion, synergistic effects • O2 concentration seems to be detrimental • Removes FeCO3 • Will produce pitting in 13Cr Corrosion Resistant Alloy  <10 ppb • May passivate steel, contrasted by SO2 • H2S from SRB may add Sulfide Stress Corrosion and pitting • Chlorides in formation water lead to Stress Corrosion Cracking

12. 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 CO2 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. Conclusions • Flue gas-rock interactions • Precipitation of insoluble scale and plugging of rock pores in the near wellbore seems to be the main risk • SO2, H2S, O2 • 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