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Oxyfuel Flue Gas, Steel and RockImplications for CO2 Geological Storage1st International Oxyfuel Combustion Conference, Cottbus (Germany), 2009 Sep 8

Matteo LoizzoSchlumberger Carbon Services engineering manager

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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.”

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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”

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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)

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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

0 0.1 0.2 0.3 0.4

500

1000

1500

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Dep

th (

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Water pseudo-volume fraction in CO2 (%)

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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

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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?

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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

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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?

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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

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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

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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

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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