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Summary of TaberSummary of Taber’’s Reports Report(Fate of NOx, SO2 and O(Fate of NOx, SO2 and O22 during EOR)during EOR)

Stanley SantosIEA Greenhouse Gas R&D Programme

Vattenfall R&D OfficeStockholm, Sweden

October 2008

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OutlineOutline• Introduction• Type of Gas Injection projects

• Stack Gas Scrubbing using Produced Gas• Flue Gas Injection• Downhole Steam Generation• In Situ Combustion• Air Injection• Acid Gas Injection

• Related Concerns• Conclusions

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IntroductionIntroduction• Taber’s Report is the first and

only report exclusively onto the fate of acid gas components that could be associated with oxyfuel combustion with CCS.

• This report was commissioned by ANL during the first technical study looking at the viability of oxyfuel combustion technology to capture CO2 for EOR application.

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(1.) Stack Gas Scrubbing(1.) Stack Gas Scrubbing• Ref.: Snavely and Bertness (1975) Petroleum

Technology. Vol. 27, pp. 227-232. • Oil field which are steam or water flooded could

produced water with very high pH (~ 8.0 – 8.5).• Early experimental work done looking onto the use

of produced water from these field to scrubbed out SO2 from flue gas of any steam generator using ~0.3m – 1.1m of packing indicated 60% – 95% removal efficiency.

• Some results indicated a 10% - 21% NOx removal

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(1.) Stack Gas Scrubbing (cont(1.) Stack Gas Scrubbing (cont’’d)d)• Implication:

• Storage site which has been water flooded (especially for depleted oil fields) could have the capabilities to handle smallamount of SO2 in the CO2 product with no detriment to storage integrity.

• This could be applicable to CCS cases with short pipeline or on-site storage.

• It is highly recommended that geo-chemistry study should also focus on the fate of SO2 and NOx to confirm the findings of Snavely and Bertness (1975).

• O2 content seems to be not a barrier in the acid gas neutralisation by the produced water

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(2.) Flue Gas Injection(2.) Flue Gas Injection• Use of flue gas containing SO2, NOx and O2 has

been applied since 1924.• Table 2 of Taber’s Report – See next slide –

summarized the experience of EOR using flue gas injection. • This includes University Block 31 – Texas, which

has been injected with flue gas since 1966. Brief discussion with S. Havorka and her colleagues –indicated that this block is currently the most productive gas (?) and oil field for University of Texas.

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(2.) Flue Gas Injection (cont(2.) Flue Gas Injection (cont’’d)d)

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(2.) Flue Gas Injection (cont(2.) Flue Gas Injection (cont’’d)d)• Elk Basin, Wyoming Experience

• Flue gas injection started in 1949. Injection continued for 20 years. (First successful flue gas injection EOR in the world).

• Corrosion problem was noted during early days of experience. • SO2 and NOx was controlled by removal H2S from the gaseous

fuel burned and injection of ammonia prior to combustion and compression.

• No evidence indicating removal of acid gas after combustion. This implies that NOx should be around 0.2% - 0.3%.

• It could be implied that O2 content should be same level typical for methane combustion.

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(2.) Flue Gas Injection (cont(2.) Flue Gas Injection (cont’’d)d)• University Block 31 Texas Experience

• Flue gas injected consists of 8 ppm SO2 and 18 ppm NOx. (It could be implied that O2 could be about ~2% based on methane combustion and 10% excess).

• Reduction of NOx is based on Flue Gas Recirculation technique.

• NH4OH injection was also used to reduced SO2 and NOx

• Until 1984 –• Only breakthrough of CO2 was reported and it was noted that

breakthrough is later than expected. • no breakthrough of SO2 and NOx in the producing well (This

should be further verified to current or past years of experience).

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(2.) Flue Gas Injection (cont(2.) Flue Gas Injection (cont’’d)d)

• Neale Field, Louisiana Experience• Flue gas injection started 1966. • Literature reported

• No problem with corrosion due to removal of NOx via catalytic reduction and mol. sieve dehydration (indicated that Glycol dehydration is not enough).

• No problem with plugging in the injection well.• No problem with acid gas migration in the reservoir.

• It was noted that further investigation of acid gas breakthrough in the producing well should be undertaken. Until 1984, there is still no significant quantities of SO2 or NOx produced.

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(2.) Flue Gas Injection (cont(2.) Flue Gas Injection (cont’’d)d)

• Conclusions (by Taber)• Large volume of alkaline water and carbonate rocks

apparently helped neutralized the SOx and NOx.• Lack of evidence of any breakthrough is not a true

results of allowing large quantities of SOx and NOx that could be injected.

• This implies that a minimum level of NOx and SOx should be recommended and determined scientifically to ensure no problem caused by these substances

• Reduction of NOx and SOx are undertaken as the first step in previous 40-50 years of experience due to corrosion problem.

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(3.) Downhole Steam Generation(3.) Downhole Steam Generation• Both steam and flue gas are injected in the

reservoir.• Test were undertaken by Sandia National Laboratory in

5 acre, inverted 5 spots.• Test were undertaken using air/diesel and oxygen/diesel

steam generators.• No removal acid gas were undertaken. Issues related to

corrosion during operation (i.e. materials and operation problem) were documented. Severe problem were indicated during oxygen/diesel test.

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(3.) Downhole Steam Generation (cont(3.) Downhole Steam Generation (cont’’d)d)

• Breakthrough of N2 in the nearest well for air/diesel generator were reported to occur within 2 days.

• Breakthrough of N2 in the oxygen/diesel generator pattern occurred in 7 days with farthest point to occur in 97 days.

• CO2 breakthrough is reported to be later than N2.

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(3.) Downhole Steam Generation (cont(3.) Downhole Steam Generation (cont’’d)d)

• Test indicated the following:• Reduced O2 in the production well• Reduced CO in the production well• Reduced H2 in the production well• Increased H2S in the production well• No change in SO2 (please note that initial SO2 is

low anyway).

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(3.) Downhole Steam Generation (cont(3.) Downhole Steam Generation (cont’’d)d)

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(3.) Downhole Steam Generation (cont(3.) Downhole Steam Generation (cont’’d)d)

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(3.) Downhole Steam Generation(3.) Downhole Steam Generation

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(4.) In Situ Combustion (Fire Flooding)(4.) In Situ Combustion (Fire Flooding)• Stinson et. al. (1976) reported the composition of produced gas during

fire flooding. It should be noted that NOx and SO2 are not present. (See Table 5 next slide)

• Average results from various fire flooding tests reported by Taber:• N2:- 55 -73% (average 65%)• O2:- 0%• CH4:- 15 – 32% (average 22%)• CO2:- 11 – 13% (average 12%)• 6 fields reported 85% of N2 injected recovered from the production well. O2

is pretty much consumed. • All fire flooding tests only monitors N2, O2 and HC to analyse the

progress of in-situ combustion. They did not report acid gas composition. Therefore results on the fate of NOx and SO2 are inconclusive.

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(4.) In(4.) In--Situ Combustion (contSitu Combustion (cont’’d)d)

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(4.) In Situ Combustion (Fire Flooding)(4.) In Situ Combustion (Fire Flooding)

• It should be noted that fire flooding technique is suitable for EOR application with very heavy oil.

• N2 is a very good carrier of pollutant gases. It was noted that at high temperature cracking condition, H2S will be produced instead of SO2.

• It was noted that the use of oxygen instead of air seems to have some promising effect due to higher CO2 concentration than N2.

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(5.) Air Injection(5.) Air Injection• Air injection is sometimes used to re-pressurized the oil field. • Taber indicated that corrosion issue is the main concern and

problem. • Corrosion control is highly dependent to the dehydration process.

• But injection of air in the reservoir on its own is not an issue. (Taber has indicated the experience of air injection in the Pennsylvania Oil Field wherein oil is not as reactive as one found in California or Mid-continent).

• Taber concluded from his review that oxygen will not pose any problem in the reservoir. He also noted that oxidation of oil by the oxygen should not presents a problem more serious than those routinely experienced during in-situ combustion cases.

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(6.) Acid Gas Injection(6.) Acid Gas Injection• Acid Gas consisting of CO2 and H2S was reported to have

injected in a West Texas oil field.• The acid gas is obtained from the Claus Unit of the

Slaughter Gasoline Plant (about 7 miles from the oil field).• The acid gas has a composition of 28% H2S and 72%

CO2.• Slaughter Pilot Test clearly provide evidence that

extremely acidic gas could be handled by the EOR operator. The project detail was presented in the Taber’s Report and was well referenced.

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Related ConcernsRelated Concerns

• Taber’s Report presented the following concerns:• Injection well plugging. He has reported that

laboratory test has indicated a reduced permeability could probably occur when 85%-15% CO2/SO2 mixture was used.

• Strong consideration should be made about this issue if injection in a limestone rich reservoir.

• However, it should be noted that flue gas SO2 concentration will be typically less than 1%.

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Other Concerns (contOther Concerns (cont’’d)d)

• Reservoir heterogeneity: Taber reported that there is no evidence that heterogeneity would be an issue in any previous flue gas injection projects.

• Nonetheless, Taber cautioned that extremely permeable reservoir should be evaluated before any flue gas injection activity in order to ensure that no breakthrough of acid gas component would occur.

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TaberTaber’’s Report Conclusionss Report Conclusions• Reservoir has enormous capacity to reduce SO2 and NOx

present in any flue gas.• Prior to 1984, no evidence of acid gas breakthrough were

reported from previous flue gas injection projects.• With O2 consideration, a small amount could be injected

without any problem. (The amount involved as discussed in the report could somewhere in the region of ~2% typically found in any methane combustion.)

• No plugging or reservoir formation problem was reported in any previous activities related to flue gas injection.

• Equipment corrosion issue is still the main concern.

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TaberTaber’’s Report Conclusions (conts Report Conclusions (cont’’d)d)

• Corrosion issue could be resolved by acid gas reduction to an acceptable level and good dehydration practice.

• Carbonate reservoir is still a concern in terms of plugging especially when injecting very high level of SO2 (i.e. ~ 15%).

• Plugging did occur in laboratory test when injecting 15% SO2 in a limestone core but not in a sandstone core.

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TaberTaber’’s Report Conclusions (conts Report Conclusions (cont’’d)d)

• Extreme heterogeneity will continue to pose problem of early breakthrough of acid gas components, especially in the most permeable zone. This means that residence time for the acid gas to be neutralized by the reservoir would not be enough.