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1st International Oxyfuel Combustion Conference, Cottbus (Germany), 2009 Sep 8
Matteo Loizzo
Schlumberger Carbon Services engineering manager
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Oxyfuel Flue Gas, Steel and Rock
Implications for CO2 Geological Storage
Geological storage performance factors
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“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
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““Geological storage of CO2” means injection accompanied by storage
of CO2 streams in underground […] rock layers”
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"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”
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– Deep saline formations and (depleted) oil and gas reservoirs
What is in the rock before we inject CO2?
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EOR/EGR: Enhanced hydrocarbon Recovery
– Oil recovery rate ~40% of OOIP
 Gas: >90%
 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
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Depleted (gas) reservoirs  very low pressure gas, and water
Deep saline formations  salty water (brine)
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– Initial production, then pressure maintenance (water or gas), then tertiary
recovery
Where does the water go?
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Water needed for most contaminants’
reactions
CO2-water displacement
Source:Azaroual et al., ENGINE Workshop, 2007
 Like “salting out”  does it really affect
injectivity?
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Depth (m)
– Diffusion of CO2 and contaminants at the
edges of the plume
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 Depends on exchange surface, upside 
solubility trapping
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Shut-downs  water flows back
– Near reservoir and wells affected
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Water pseudo-volume fraction in CO2 (%)
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– Sharp front, residual saturation Srw
– Evaporation of residual water in the
plume
Contaminants in deep rock – experience and insights
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Injection of flue gas for pressure maintenance
In-situ combustion
 Including “rich air” after N2 removal
– Low and high temperature  total O2 injection rate, heavier hydrocarbon chains
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Raw Seawater Injection
– Oxygenated water
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Acid gas disposal
– CO2+H2S
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– Air injection
Potential issues – Sulfate-Reducing Bacteria
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Reduce sulfur (SO4/SO3) to H2S
– Form injectivity-reducing biofilms in near wellbore
 Biofilms enhance steel corrosion in tubulars
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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
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Risk mitigation
– Low pH, high salinity (deep saline formations), O2 inhibit growth
– NOx (nitrates) control SRB by bio-exclusion
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Aerobic bacteria?
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– H2S can lead to the precipitation of FeS and S (with NO2), reducing injectivity
Potential issues – H2S geochemistry
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Weak acid
Can precipitate iron sulfide or elemental sulfur (with nitrites)
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Risk mitigation
– Iron in reservoir (hematite or siderite) can scavenge H2S
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Additional issues
– “Sour” steel corrosion, Stress Corrosion Cracking
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– Reservoir plugging and injectivity reduction
Potential issues – SO2 geochemistry
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Very soluble in water, oxidizes to sulfuric acid
 Smaller acid area with carbonates, reduced mineralization potential
– Might reduce FeS scaling?
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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?
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– O2 scrubber, requires metal catalysts?
– Simulations (Xiao et al.) suggest a pH 0 zone ~10-100 m from the injection well
Potential issues – O2 geochemistry
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Hydrocarbon oxidation
– Low temperature (no sustained combustion) or high temperature
– Requires “light” oil (C7 or heavier)
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Rock oxidation
– Iron in rock or water, Fe2+  Fe3+, which then precipitates as ferric hydroxide 
competing with H2S reduction?
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Risk mitigation
– Not enough O2
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 LTO may slightly damage recovery  oil emulsions
Potential issues – corrosion
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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
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Corrosion control
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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
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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
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Conclusions
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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
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Corrosion
– No water
 Water flow back during injection breaks
– Transport “weakest link”
 Biggest impact of CRA adoption
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