The document proposes capturing 2.76 billion lbs of CO2 per year from a power plant, transporting it via pipeline, and sequestering it in a saline aquifer. 38.24% (1.067 billion lbs) would be used for enhanced oil recovery, with the remaining 1.68 billion lbs sequestered directly in the saline aquifer. Technical and economic analyses show the cost of CO2 capture would increase electricity costs from 3.7 to 5.9 cents/kWh. Sequestration costs in the saline aquifer are estimated to be $7.714/ton of CO2. Modeling suggests the CO2 would be trapped primarily through solubility and hydrodynamic mechanisms, with a small

1. Bander Al Ghamdi
Kyungsoo Kim
Seyhan Emre Gorucu
Yogesh Bansal

2. ` Team Statement
` Results
` Approach
◦ Capturing
◦ Sequestration
◦ Utilization
` Conclusion

3. ` Reduce CO2 emission by
efficiently capture it, utilize
it for EOR purposes, and/
or sequester it, while
considering technical and
economical analysis. Capturing
Storing
Utilizing
CO2 Project
Handling/ Transporting
Source

4. 1.067E09 lbs of CO2/year (38.24%)
1.68E09 lbs of
CO2/year (60.76%)
2.97E07 lbs of CO2/year (1%)
Saline
Aquifer
2.76E09 lbs of CO2/Year

5. Capture
(100%)
$48/ton spent
EOR (1%)
$6.91/ton
earned
Oil Field(38%)
$7.714/ton
spent
Total Cost:
$53.3/ton
Saline
Aquifer(61%)
$3.95/ton spent

6. Cost
without
CCS
Cost with
Capture
only
Cost with
CCS
3.7cent/kWh
5.4 cent/kWh
5.9 cent/kWh

8. ` Capture method
◦ Post-combustion
x <,
x Chemical absorption
x <
x Membrane
◦ Pre-combustion
◦ Oxy-fuel
Data Source :
Rao A, Rubin E, A technical, economic, and environmental assessment of
Amine-based CO2 capture technology for power plant greenhouse gas
control in Environ1

9. Project life (years) 10
Operating hours (hour/year) 6000
Operation and maintenance cost (% of capital cost) 3
Spent solvent making up ($/ton CO2 captured) 4
Interest rate (%) 5
Coal price ($/ton) 48
SO NO in flue gas (ppm) 70
` Reduce 1% of PA’s annual CO2 emission from the power industry and
keep the emission amount the same for ten years
` Values for power plant efficiency and capital cost are the same as those
of similar power plants
` No capital cost for power plant, the capital cost for power plant starts to
be paid from the first running point of the capture process
<Economic analysis assumptions>

10. CO2 compression
1.43%
Gas Pumping
0.21 %
CO2 compression
1.43 %
Steam extraction
2.87 %
Steam extraction
3.47 %
DEA absorption
Power plant
600 MW
(Capture
42%)
Gas Pumping
0.18 %
Efficiency loss
5.08 %
MEA absorption
Efficiency loss
4.51%

11. ` CO2 capture with MEA
Net power production(MW)
Reference plant 600
Power plant with CO2 capture 568
Specific CO2 emission (lb/kWh)
Reference plant 1.8
Power plant with CO2 capture 1.1
Electricity production cost(cent/kWh)
Reference plant 3.7
Power plant with CO2 capture 5.4
CO2 capture cost ($/ton CO2) 48.6
Capital cost(million USD) 957
Reference plant Construction 690
Chemical absorption unit 182
CO2 compressor 25
Interest during construction and land site 59
Annualized cost(million USD/year) 162
Capital charges for reference plant 49
Capital charges for CO2 capture components 19
Coal feedstock 63
Operation and maintenance cost for reference plant 22
Operation and maintenance cost for CO2 capture process 9

12. 4.5
5
5.5
6
6.5
7
40 45 50 55 60
Electricity
cost
(cent/kWh)
Coal price ($/ton)
20% CAPTURE
42% CAPTURE
60% CAPTURE
80% CAPTURE
100% CAPTURE
35
40
45
50
55
60
65
70
75
40 45 50 55 60
Capture
cost($/ton)
Coal price ($/ton)
20% CAPTURE
42% CAPTURE
60% CAPTURE
80% CAPTURE
100% CAPTURE
0
20
40
60
80
100
120
140
160
180
5
5.2
5.4
5.6
5.8
6
6.2
0 20 40 60 80 100
CO
2
capture
cost
($/ton)
Electricity
cost
(cent/kWh)
CO2 removal rate (%)
Electricity production cost(cent/kWh) CO2 capture cost($/ton)

13. Data Source:
1. www.apegga.org/Members/Presentations/Baker.ppt

14. ` Field production is a strong function of (P and T)
◦ Lithology of the reservoir
◦ Properties of oil
` Oil could be at a high viscosity that prevents it
from flowing, or it could be strongly attached to the
grains inside the pore spaces where it is
unreachable.
` A mechanism has to take place to make oil more
soluble and be pushed to the production zones.

15. ` As the CO2 comes in contact
with oil, it dissolves in the
droplets of oil and occupies
some volume allowing the oil to
swell
` Oil droplets will merge together
to unite in one body of fluid flow
more easier to reach the
production zones

17. Injection Rate
(MMSCF/D)
Cum. Oil Produced
(MSTB)
Recovery Factor (%)
70 43 35.8

19. Layer # of Active
reservoir blocks
Δx Δy h φ Pore Volume
(ft3)
1 972 300 300 16 0.1373 1.922*108
3 972 300 300 12 0.1622 1.703*108
5 972 300 300 6 0.075 0.394*108
7 972 300 300 6 0.075 0.394*108
Total 4.413*108 ft3
` Formation volume factor for CO2 as 0.0048
` 9.194*1010ft3 CO2 can be sequestered in the reservoir
` Two possibilities
` Entire amount sequestered in the reservoir for nearly 4
years
` Fraction of the captured amount
Pore volume calculations

20. Well
Bottom
hole
pressure
(psia)
` When entire amount of CO2 is
sequestered
◦ Using all five wells
◦ Pressure crossed 7000 psia at the
wells
◦ Formation fracture risks
` A study was designed to inject CO2
for a period of 10 years
` 38.24% of the captured amount
(1.067 lbs/year)

21. ` CO2 movement in
the reservoir at
various times
` Locations of the
wells taken from
literature

22. ` One of the wells was assumed as an abandoned well
and a pressure difference of 20 psia was assumed
◦ 5.43*10-3 percent of the total amount of CO2 sequestered in the
reservoir

23. ` Properties are
assumed to be
homogeneous in
a layer
` CO2 movement
should be
identical
` Leakage
dampens the
movement profile
and low pressure
were observed in
the region

24. ` Site was assumed at a distance of 500 km
` Average permeability was calculated to find the
overall capital cost
◦ Average permeability is 111 mD
◦ 100 mD curve was used
` Initial cost is $290 millions

25. ` No leasing costs were assumed
◦ Exhausted oil field
` No Royalty cost
◦ No production
` Operating cost is assumed to 10% of the cash
flow
` Rate of return is assumed as 5% annually
(0.0137% daily)
` Daily cash flow is found to be $90526
` Cost for sequestration
◦ $0.4976/MSCF (or $7.714/ton of CO2)

26. 2.5
2.7
2.9
3.1
3.3
3.5
3.7
40 50 60 70 80 90 100
D
i
a
m
e
t
e
r
(
f
t
)
Mass Flux (lbs/s)
Diameter vs Mass Flux
0
2000000
4000000
6000000
8000000
10000000
12000000
14000000
16000000
18000000
44 54 64 74 84
C
o
s
t
(
$
)
Flowrate (lbs/s)
Labor
Miscellaneous
Material
ROW
Total

27. 0.4
0.6
0.8
1
1.2
1.4
1.6
1.8
2000 2500 3000 3500 4000
Solubility(lbs/ft^3)
Pressure(psia)
Pressure vs Solubility
Salinity:150g/
L
Salinity:70g/L
Salinity:20g/L

29. 1.79*10^9
lbs/ year
Hydrodynamic
Trapping
(2.32lbs/cubic feet)
Solubility
Trapping
Mineral % of total trapping
Calcite 0.035637955
Dolomite 1.466287055
Siderite 0.037164077
Magnesite 0.009867851
Total 1.548956938