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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. Capacity. Injectivity. Containment.

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


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oxyfuel flue gas steel and rock implications for co 2 geological storage

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

geological storage performance factors

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.”

some definitions european directive 2009 31 ec
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”
what is in the rock before we inject co 2
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)
where does the water go
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

contaminants in deep rock experience and insights
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
potential issues sulfate reducing bacteria
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?
potential issues h 2 s geochemistry
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
potential issues so 2 geochemistry
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?
potential issues o 2 geochemistry
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
potential issues corrosion
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
corrosion control
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
conclusions
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