carbon dioxide emissions and water consumption from oil shale
TRANSCRIPT
CARBON DIOXIDE EMISSIONS AND WATER CONSUMPTION FROM OIL SHALE PRODUCTION: A SECOND LOOK Jeremy Boak, Director 30th Oil Shale Symposium Center for Oil Shale Technology & Research October 18-20, 2010 Colorado School of Mines Golden Colorado
Outline
‣ Problem statement: Impact of production from saline zones
‣ Inferred nahcolite fraction from Fischer Assay
‣ Additional releases of CO2 and water
‣ Effect of release of breakdown products
‣ Conclusions
Previous Analyses
‣ CO2 emissions from in-situ oil shale production dominated by power plant fuel consumption for electrical heating to pyrolysis temperature
‣ Mitigation would depend upon reduction of power plant emissions, or substitution of alternative means of heating
‣ At that time, proponents of in situ methods planned to remove evaporitic minerals (nahcolite, dawsonite) prior to heating – Adds to potential water consumption
– Substantial water already required for power plant steam condensation and post-retort water/steam cleaning of the rock (Boak and Mattson, 2010).
ExxonMobil Approach
‣ Heat rock in saline section of the Green River Formation (GRF) prior to removing evaporitic minerals
‣ Nahcolite will react to natrite at temperatures in the range 150 - 200°C by the following reaction:
‣ 2 NaHCO3 = Na2CO3 + H2O + CO2
Impact of CO2 release
‣ Volatile constituents may fracture the rock
‣ Will certainly be released when the additional volume increase from pyrolysis occurs in the range of 300-400°C.
‣ Might affect early pyrolysis products
‣ Nahcolite constitutes as much as ~20 wt % of the rock in the saline sections of the GRF (or more?) – large additional CO2 output has not been accounted for
in earlier analyses.
‣ Mitigation of CO2 release will add to cost of recovery
Impact of water release
‣ Large volume of water released from the rock will mitigate use of water elsewhere in recovery of oil
‣ ExxonMobil proposes using water: – To recover the transformed nahcolite – To remediate contaminants of concern in the
retorted block – As a single step
Nahcolite breakdown (after Templeton, 1978)
‣ Reactions conducted at constant Vg/Vs
‣ Calculated for Vg/Vs = 0 ‣ U. S. Bureau of Mines/AEC
Colorado #1 well used as representative
‣ At lithostatic load of saline zone, reaction occurs at ~200°C
‣ Substantially below pyrolysis temperature
0
500
1000
1500
2000
2500
3000
3500
4000
0 50 100 150 200 250
Depth (fe
et)
Temperature (°C)
Nahcolite Decomp.
Top Saline Zone
Base Saline Zone
Fischer Assay data reveal nahcolite trend Gas+Loss
Oil Water
y = -0.9458x + 0.9966 R² = 0.96892
Ternary Boundary 385-1200 1740-2500 2619-3108 Nahcolite Carbonates Kerogen Linear (1740-2500)
U. S. Bureau of Mines/AEC Colorado #1 Well
Simplified normative minerals from FA
‣ Assumes loss part of gas+ loss negligible
‣ Defines rich and lean zones
‣ Broadly indicates illitic oil shale and nahcolitic oil shale
‣ Nahcolite may be overestimated
‣ Relatively small fraction of carbonate reacts
0 50 100 385
1061
1347
1689
1928
2162
2379
2611
2860
Kerogen
Nahcolite
NonvolaOle
VolaOle Carbonate Hydrous Minerals
Additional CO2 release
0
0.05
0.1
0.15
0.2
0.25
0.3
0.35
0 2 4 6 8 10 12 14
CO2 (tons per barrel)
Produc;on Quality (FA*FA%*Power plant eff.)
Nahcolite 19% Nahcolite 0.8%
Water release from nahcolitic oil shale
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0 0.2 0.4 0.6 0.8 1 1.2 1.4
Wat
er (b
arre
l/bar
rel o
il)
Kerogen/Nahcolite ratio
Will it fracture the rock?
2NaHCO3 = Na2CO3 + H2O + CO2 2*81.4 g/mol 106 g/mol 18 g/mol 44 g/mol
2.173 g/cc 2.54 g/cc
2*38.66 cc/mol 41.73 cc/mol
Δ Volume (solids) = -35.59 cc/mol = 44 %
fluid density in void = 18 + 44 g/35.594 cc = 1.742 g/cc
Density of CO2 alone = 44g/35.594cc = 1.236 g/cc
Density of water alone = 18/35.594 = 0.506 g/cc
Volume change for kerogen and nahcolite
0
5
10
15
20
25
30
before aUer
7.2 7.2
8.1 2.9
9.4
6.6
Volume (G
3 )
Kerogen
HC Liquid
HC Vapor
Coke
Kerogen
Mineral
15.3
26.1
0
5
10
15
20
25
30
before aUer
6.3 6.3
8.1 8.1
2.9 1.6 0.8
9.6
Volume (G
3 )
Nahcolite
CO2
Water
Natrite
Nahcolite
Kerogen
Mineral
17.4
26.4 225°C 150 bar ~2160 feet
CO2 phase dominates volume increase
0
4
8
12
16
0 100 200 300 400
Specific Vo
lume (m
l/g)
Temperature (°C)
Water CO2
P = 150 bar (~2160 U depth)
Specific volume of water and CO2
50 150 250 350 0
5 10 15 20 25 30 35 40
0
50
100
150
200
Specific Vo
lume (m
l/g)
P (bar)
CO2
0-‐5 5-‐10 10-‐15 15-‐20
20-‐25 25-‐30 30-‐35 35-‐40
50 150 250 350 0
5 10 15 20 25 30 35 40
0
50
100
150
200
Specific Vo
lume (m
l/g)
P (bar)
H2O
0-‐5 5-‐10 10-‐15 15-‐20
20-‐25 25-‐30 30-‐35 35-‐40
Can water alone fracture the rock?
‣ Large volume change to steam
‣ Occurs at higher T ‣ Upper zone generally
leached ‣ Increased porosity may
accommodate volume increase
‣ Will activity of water affect pyrolysis?
0
500
1000
1500
2000
2500
3000
3500
4000
0 50 100 150 200 250 300 350
Depth (fe
et)
Temperature (°C)
Nahcolite/Natrite Water/Steam Top Saline Zone Base Saline Zone
Remaining questions
‣ One phase or two?
‣ Dissolution of natrite in resulting fluid
‣ After conversion, who owns the water derived from heating alone?
‣ Question applies to water in other minerals
‣ Will water alone be sufficient to fracture rock?
Conclusions - Issues
‣ Production from saline zone potentially increases CO2 emissions by 60%
‣ Produces 1/3 to 2/3 barrel of water per barrel of oil
‣ Both releases likely to occur before significant hydrocarbon production starts
‣ Handling of CO2 – water mixture produced may be challenging, but is not novel
Conclusions – potential benefits
‣ CO2 and water release prior to production of significant hydrocarbons simplifies CO2 capture
‣ Early fracturing of rock gives control over reaction and production, and enhances heat transfer
‣ Planning to handle soluble minerals may address concerns about CO2 handling