Shale gas conversion: Processing and economics
Gennaro J Maffia, gennaro.maffia@manhattan.edu, Alex Bertuccio. Chemical
Engineering, Manhattan College, Riverdale, NY, NY 10471, United States
With the discovery of vast quantities of natural gas available in various shale
formations in Pennsylvania, New York and several adjoining states comes the
opportunity to convert this gas, traditionally used for fuel, into more value added
products. The methane fraction can be converted into intermediates such as
ethylene via oxidative coupling, whereas the ethane/propane fraction can be
converted into ethylene via conventional steam pyrolysis. In this paper the
processing requirements of a variety of technologies starting with methane and
E/P mixes will be presented along with the expected material and energy balances
and production economics.
Prof. Gennaro J. Maffia
“Jerry”
Often called a fracking engineer;
or words to that effect
Jerry Maffia – background
1.
Professor of Chemical Engineering –
Manhattan College
2.
Manager of Technology Development – ARCO
a. Petrochemical & Refining
b. Start-up & Technical Services
gennaro.maffia@manhattan.edu
http://home.manhattan.edu/~gennaro.maffia/ACS2013.pptx
Jerry Maffia – some projects
Energy Related Projects
a. Alaskan Pipeline and Remote Gas
b. Fuel Oxygenates
c. Biofuels/Bioseparations
d. Energy Integration
e. Novel Separations
f. Manufacture of Proppants
Shale Gas – an opportunity
• One point of view
“The outlook for advantaged U.S. natural gas was a significant
factor in Dow’s decision to invest $4 billion to grow our
overall ethylene and propylene production capabilities in the
U.S. Gulf Coast region,” said Jim Fitterling, Dow Executive Vice
President and President of Feedstocks & Energy and Corporate
Development. “Today, 70 percent of the Company’s global
ethylene assets are in regions with cost advantaged feedstocks
– and we’ve seen the benefits this advantage provides given
oil-based naphtha margin pressure in Europe and Asia. This
plan represents a game-changing move to strengthen the
competitiveness of our high-margin, high-growth derivatives
businesses as we continue to capture growth in the Americas.”
Economic Impact
A World Scale Petrochemical
Plant In Pittsburgh
.....are you crazy professor?
Maybe, but ...............
Shale Gas – a curse
• Another point of view
Shale Gas – a textbook
• Call a professor
Mining Natural Gas – Wiley Text (work in progress)
Table of Contents
Chapter
Chapter
Chapter
Chapter
Chapter
Chapter
Chapter
Chapter
Chapter
Chapter
Chapter
Chapter
Chapter
Chapter
Chapter
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Worldwide energy picture
Current domestic energy situation and opportunities
Worldwide carbon dioxide balance – current and anticipated
Review of basic fluid flow
Overview of hydraulic fracturing – all issues
Two phase flow and flow through porous media
Fluidization, sedimentation and suspension of proppants
Details of the hydraulic fracturing process
Composition of fracturing fluids – current and alternatives
Alternative fracturing methods and fluids
Environmental issues and safety concerns
Economic evaluation
Societal impact and safety concerns
Sustainability issues
Future expectations
What is all the fuss about .........
Mining
Methodology…....
hydraulic fracturing ……….how?
drill a vertical well
extend the drilling horizontally
case the well
perforate the casing
pump in high pressure water and sand
to fracture the shale at the perforations
recover/dispose of the water
cap the well bore
send gas to treatment
treated gas to interstate pipeline system
Hey Jerry what’s
the story?
Hey Professor,
would it help if we didn’t use water?
Dry Frac
Atmospheric CO2 – approaching 400 ppm
Flue Gas CO2 – much higher, depends on EA
Light HCs
The FracKINGS Design Group
Morgan, Jimmy, Amanda, Amanda
Drexel University Senior Project Team –
Using CO2 as a Fracking Fluid
Amanda, Amanda
Prof. M. and the FracKINGS
12
10
USD per thousand CF
8
6
4
2
0
0
50
100
150
200
250
Month from April 1976
300
350
400
450
500
SOME HEADLINES.........
Regulations and Current Policy
May 2012 News
Safe Drinking Water Act
Several statutes may be leveraged to protect water quality, but EPA's central
authority to protect drinking water is drawn from the Safe Drinking Water Act
(SDWA).
The protection of USDWs is focused in the Underground Injection Control (UIC)
program, which regulates the subsurface emplacement of fluid.
Congress provided for exclusions to UIC authority (SDWA § 1421(d)), however,
with the most recent language added via the Energy Policy Act of 2005:
May 2012 News
"The term 'underground injection' –
(A) means the subsurface emplacement of fluids by well injection; and
(B) excludes –
(i) the underground injection of natural gas for purposes of storage; and
(ii) the underground injection of fluids or propping agents (other than diesel fuels)
pursuant to hydraulic fracturing operations related to oil, gas, or geothermal
production activities."
While the SDWA specifically excludes hydraulic fracturing from UIC regulation under
SDWA § 1421 (d)(1), the use of diesel fuel during hydraulic fracturing is still regulated
by the UIC program.
May 2012 News
State oil and gas agencies may have additional regulations for hydraulic fracturing. In
addition, states or EPA have authority under the Clean Water Act to regulate
discharge of produced waters from hydraulic fracturing operations.
Clean Water Act
Disposal of flowback into surface waters of the United States is regulated by the
National Pollutant Discharge Elimination System (NPDES) permit program. The Clean
Water Act authorizes the NPDES program.
Topics
•
•
•
•
•
•
Current Ethylene Business Environment
ODH and Competing Cases – Processing
Economics
Preliminary Reactor Design
CO2 Sequestration and Management
ODH Upside Potential – Energy Upgrade
Ethylene Business Background
• Current Cracking Strategy
• Feedstocks and Leveraging Issues
Ethylene Producers
• Domestic
• North America
• World-wide
US Producers
Petral Information
• Raw data – play it straight
Implications: In the US, with its advantaged natural gas–based feedstock, cash margins
in the next cycle should be 2.4x the average of the past 20 years. Dow and LyondellBasell
should be the main beneficiaries. Asian utilization rates are set to tighten the most from
current low levels. In Asia/Middle East, we prefer companies with exposure to gas-based
feedstocks such as PTT Chemicals and SABIC. Europe should remain structurally weak
due to low demand, high feedstock costs, and proximity to potential Middle East
imports.
Definitions
VC = RMC + Utilities
FC = LC + MC + OVHD + Other
CC = FC + VC
RNB = FC + VC + CR
The US and Europe Have Driven Ethylene Demand
From 1990 to 2000, global ethylene demand growth averaged
5.0%, or 1.9x global GDP growth. However, from 2000 to
2009, it averaged just 2.5%, or 0.9x global GDP growth.
The US and Europe Have Driven Ethylene Demand
From 1990 to 2000, global ethylene demand growth averaged
5.0%, or 1.9x global GDP growth. However, from 2000 to
2009, it averaged just 2.5%, or 0.9x global GDP growth.
The ethane to ethylene program is an offshoot from another related TDC program
which involves alternatives routes to styrene starting from ethane as one of the
components in the feed.
The new reaction concept of ethane to ethylene is a controlled catalytic
oxydehydrogenation (ODH) process at low temperature. This process undergoes
no reaction in the absence of the catalyst till a temperature of 400 C . This new
process provides an alternative to ethylene production compared to naphtha or
ethane cracker. The main driver for this program is that the process has several
potential applications including an alternative to present day ethane cracker,
replacement of recycle cracker and the possibility of feed for EB/SM and EO
plants.
C2H6 + ½ O2
C2H4 + H2O + Heat
The process operates at low temperature
(< 400 oC) and dry run experiments have
proven that there are no reactions without the
catalyst.
To date many ethane ODH processes do exist in literature and sufficient
research efforts have also been given in this regard, but none of them have yet
been commercialized
The catalyst is capable of maintaining high ethane reaction rate, high ethylene
selectivity and self stability. Several phases of improvement have been carried
out with the catalyst and the results have also been promising when compared
with an ethane pyrolysis furnace.
100
TDC DATA: 10 mol% ethane + 8 mol%
oxygen + 10 mol% water + 72 mol%
nitrogen
% C2= Selectivity
95
90
85
Best Literature data (2005 ODH) : 9
mol% ethane + 6 mol% oxygen + 85
mol% helium
80
75
70
30
40
50
60
% C2 Conversion
70
80
Pyrolysis cracker (commercial plants) :
S/O = 0.3
Oxidative Dehydrogenation
Study Cases
Case 1:
Case 2:
Case 3:
Case 4:
Case 5:
Air plus process water recycle
Air plus nitrogen recycle
Oxygen plus process water recycle
Case 3 @ SP Conversion and High Selectivity
Dow ATR
ABB ODH Basis:
90 % conversion, 90% selectivity (Cases 1-3)
CO/CO2 equimolar yield
0.08/0.1/0.82 = O2/C2/Carrier
450 C; 4 bar reactor inlet or as noted in sub-cases
Case Specifics
Case
1-HT
3-HT
3-MT
3-LT
3-MT-A
4-MT
O2 source
Recycle diluent
Rx inlet P, barA
Feed O2 mole%
C2H6 mole%
C2H6 % conv.
% selectivity
Effl mole% O2
Rx exit T, oC
air
H2O
4
8
10
90
90
1.2
450
O2
H2O
4
8
10
90
90
1.2
450
O2
H2O
4
8
10
90
90
1.2
425
O2
H2O
4
8
10
90
90
1.2
375
O2
H2O
4
8
10
90
90
1.2
425
O2
H2O
3
8
by calc.
70
95
1.2
425
Trim Rx
yes
yes
yes
yes
no
yes
Case 1
N2 Purge/Sales
Ethylene
Compression
Drying &
N2 Removal
Ethane
Recycle
CO2
Ethane
Air
ODH/Trim
Quench
Process
Water
Amine System
Net Water
Uses combination of N2/stm as diluent replaced by Case 3 (all stm) as the Base Case
Case 2
Compression, Drying
Purge and Recycle
N2 recycle loop
Ethylene
N2 (net)
CO2
Ethane
Air
ODH/Trim
Quench
water
Amine System
Ethane
Recycle
Not pursued further due to N2 loading
Cases 3,4
Ethylene
CO2
Ethane
O2
ODH/Trim
Compression
& Drying
Quench
Process
Water
Amine System
Net Water
Case 3
Case 4
Ethane
Recycle
90/90
70/95
Case 5 – Based on examples in Dow patent
USP 6566573 E-1; looks like an OP
EA/H2
CO2
Quench
dryer
Ethane
RCTR
CaO
Steam
compression
water
Fuel gas
C2= Product
C3s
De-C2
De-C3
chilling train
De-C1
DOW ATR Process
C2 Fract
Summary ( cents/lb C2H4)
Case
1
2
3
3 - LT
4
5
6
7
ODH - air
ODH - N2
ODH
ODH
ODH
Dow
SP - Hi H2
SP - Lo H2
CC
high
high
26.8
27.1
25.8
32.2
24.1
25.8
RNB (20%)
high
high
35
36.8
35.8
46.2
40
41.7
Cash Costs, US cts./lb
Fuel Value conventional conventional
$/1e6 BTU
H2 chem
H2 fuel
6
19
21.2
8
24.1
25.9
10
29.1
30.5
12
34.2
35.1
ODH Case 3 is breakeven CC with
Conventional (H2 as fuel)
CC for ODH will improve greatly with
upgrade of low level heat rejection
Cash Costs, US cts./lb
Fuel Value conventional conventional
Case 3
$/1e6 BTU
H2 chem
H2 f uel
1.2 ethane
6
19
21.2
20.8
8
24.1
25.9
26.2
10
29.1
30.5
31.6
12
34.2
35.1
37
ODH Case 3 is breakeven CC with
Conventional (H2 as fuel)
CC for ODH will improve greatly with
upgrade of low level heat rejection
Case 3
1.23 ethane
21.3
26.8
32.3
37.9
Required Netback, US cts./lb
Cents per Pound Ethylene
Fuel Value conventional conventional
Case 3
$/1e6 BTU
H2 chem
H2 f uel
1.2 ethane
6
29.7
32
26.2
8
34.8
36
31.7
10
40
41.4
37.2
12
45.2
46.1
42.7
Much better capital and plant simplicity
result in favorable RNBs for the ODH case
Case 3
1.23 ethane
26.8
32.4
38.1
43.7
Reactor Heat Balance
• Needs Significant Heat Rejection at a High
Temperature
– Similar to EO (Shell) or ACC Oxidative Coupling
– Current research data puts reactor conditions on
the threshold of the need for molten salt cooling
Case 3 – 420 C coolant
490.000
470.000
temperature, C
450.000
430.000
410.000
390.000
370.000
350.000
0.000
1.000
2.000
3.000
length, m
4.000
5.000
6.000
Case 3
390 C Coolant
440.000
430.000
temperature, C
420.000
410.000
400.000
390.000
380.000
370.000
360.000
350.000
0.000
1.000
2.000
3.000
length, m
4.000
5.000
6.000
Case 3
390 C Coolant
0.120
Ethane, mol fraction
0.100
0.080
0.060
0.040
0.020
0.000
0.000
1.000
2.000
3.000
length, m
4.000
5.000
6.000
Case 3
390 C Coolant
Basis
Conversion
Selectivity
CO/CO2
Production
Scale
3818
kg mol/h
90%
90%
1/1
2978.04
kg mol/h
1500.06
PPY
1.00
to 1.5 BPPY
ethane
<------------------------ kg mols/h --------------------->
S1
S2
S3
S4
S5
0.00
11492.18
11492.18
11492.18
11492.18
0.00
3054.40
477.25
0.00
0.00
0.00
0.00
3092.58
3002.44
3002.44
3818.00
0.00
381.80
371.79
371.79
0.00
0.00
343.62
0.00
0.00
0.00
0.00
343.62
887.53
887.53
0.00
19815.42
23938.86
24149.23
2127.01
0.00
0.00
0.00
0.00
0.00
3818.00
34362.00
40069.91
39903.17
17880.94
114540.00 776199.40 890739.40 890740.43 494340.40
Component
N2
O2
C2H4
C2H6
CO
CO2
H2O
Abs. Oil
Total
MW
28
32
28
30
28
44
18
142
mol/h
kg/h
S6
11492.18
0.00
3002.44
371.79
0.00
0.00
2127.01
0.00
16993.41
455288.98
Component
N2
O2
C2H4
C2H6
CO
CO2
H2O
Abs. Oil
Total
MW
28
32
28
30
28
44
18
142
mol/h
kg/h
<------------------------ kg mols/h --------------------->
S7
S8
S9
S10
S11
S12
11492.18
11492.18
11492.18
11492.18
11492.18
11492.18
0.00
0.00
0.00
0.00
0.00
0.00
3002.44
3002.44
3002.44
3002.44
3002.44
3002.44
371.79
371.79
371.79
371.79
371.79
371.79
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
1076.03
550.14
550.14
265.93
0.00
0.00
0
0
0
0
0
0
15942.43
15416.54
15416.54
15132.33
14866.40
14866.40
436371.323 426905.28 426905.279 421789.6 417002.838 417002.8381
Component
N2
O2
C2H4
C2H6
CO
CO2
H2O
Abs. Oil
Total
MW
28
32
28
30
28
44
18
142
mol/h
kg/h
<------------------------ kg mols/h --------------------->
S13
S14
S15
S16
S17
10799.59 427971.84
0.00
0.00
692.59
0.00
0.00
0.00
0.00
0.00
11.34
114621.71
2978.04
2978.04
11.34
0.01
14194.76
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
10810.94 556788.30
2978.04
2978.04
703.92
302706.446 15618462
83385.12
83385.12 19709.8905
S18
0.00
0.00
0.00
371.87
0.00
0.00
0.00
0.00
371.87
11156.196
Basis
Conversion
Selectivity
CO/CO2
Production
Scale
100
90%
90%
1/1
78
39.29
38.18
Component
MW
N2
28
O2
32
C2H4
28
C2H6
30
CO
28
CO2
44
H2O
18
Total
kg mol/h
kg/h
kg mol/h
ethane
kg mol/h
PPY
to 1.5 BPPY
<------------------------ kg mols/h --------------------->
S1
S2
S3
S4
S5
S6
0.00
0.00
0.00
0.00
0.00
0.00
0.00
3040.00
0.00
3040.00 475.00
0.00
0.00
0.00
0.00
0.00
3078.00 2988.30
3800.00
0.00
0.00
3800.00 380.00
370.00
0.00
0.00
0.00
0.00
342.00
0.00
0.00
0.00
0.00
0.00
342.00
883.30
0.00
0.00
31160.00 31160.00 35264.00 35473.00
3800.00 3040.00 31160.00 38000.00 39881.00 39714.60
114000.00
97280.00
560880.00
772160.00
772160.00
Component
MW
N2
28
O2
32
C2H4
28
C2H6
30
CO
28
CO2
44
H2O
18
Total
kg mol/h
kg/h
<------------------------ kg mols/h --------------------->
S7
S8
S9
S10
S11
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
2988.30
0.00
2988.30 2988.30
0.00
370.03
0.00
370.00
370.00
0.00
0.00
0.00
0.00
0.00
0.00
883.30
0.00
0.00
0.00
0.00
477.20
3836.00 1177.22
186.97
290.25
4718.83 3836.00 4535.52 3545.27 290.25
142228.1 69048 115962.4 98137.86 5224.5
Component
MW
N2
28
O2
32
C2H4
28
C2H6
30
CO
28
CO2
44
H2O
18
Total
kg mol/h
kg/h
<------------------------ kg mols/h --------------------->
S13
S14
S15
S16
S17
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
2988.30
0.00
2988.30 2986.90
1.37
370.00
0.00
370.03
0.00
370.02
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
5.09
79.15
0.00
0.00
0.00
3363.39
79.15
3358.33 2986.90 371.39
94864.02 1424.7
94773.3 83633.2 11138.96
772151.60
S12
0.00
0.00
2988.30
370.00
0.00
0.00
186.97
3545.27
98137.86
water
69048
ethane
114000
oxygen
97280
CO2
38865.2
CASE 3
water 11,14,15
8589.96
ethylene
83633.2
ethane
11139
211280
211275.4
overall material balance
ethane 1.229906 -1.229906305
oxygen 1.163174 -1.163174433
water 0.928315 0.928315071
ethane recycle
ethylene
1
1
CO2
0.46471 0.464710187
-5.54804E-05
7
LEL
O2/fuel
5.04
9.34
1.19
15.94
11.46
10.40
1.54
6.79
7.57
6.15
29.79
5.04
11.46
11.46
26.37
15.70
14.79
29.79
3.99
19.79
18.88
12.52
13.79
9.79
10.29
18.88
17.29
18.88
UEL
O2/fuel
0.14
0.04
0.54
2.75
2.29
1.97
0.07
1.48
0.37
0.90
3.99
0.07
1.98
2.12
3.33
2.08
2.55
3.99
1.19
2.92
2.59
2.52
2.48
1.87
1.68
3.23
2.75
2.79
O2/C2
O2/C2
feed
exit
0.8
0
(LEL/LFL)
(UEL/UFL)
(%)
(%)
Acetaldehyde
4
60
Acetylene
2.2
85
Ammonia
15
28
Benzene
1.3
7.1
Butane
1.8
8.4
Butylene
1.98
9.65
Carbon Monoxide
12
75
Ethane
3
12.4
Ethylene
2.7
36
Ethyl Alcohol
3.3
19
Fuel Oil No.1
0.7
5
Hydrogen
4
75
Isobutane
1.8
9.6
Isobutene
1.8
9
Isooctane
0.79
5.94
Isopentane
1.32
9.16
Gasoline
1.4
7.6
Kerosine
0.7
5
Methane
5
15
n-Heptane
1.05
6.7
n-Hexane
1.1
7.5
n-Pentene
1.65
7.7
Pentane
1.5
7.8
Propane
2.1
10.1
Propylene
2
11.1
Styrene
1.1
6.1
Toluene
1.2
7.1
p-Xylene
1.1
ODH
Case 3
LEL
fuel/O2
0.20
0.11
0.84
0.06
0.09
0.10
0.65
0.15
0.13
0.16
0.03
0.20
0.09
0.09
0.04
0.06
0.07
0.03
0.25
0.05
0.05
0.08
0.07
0.10
0.10
0.05
0.06
0.05
UEL
fuel/O2
7.14
26.98
1.85
0.36
0.44
0.51
14.29
0.67
2.68
1.12
0.25
14.29
0.51
0.47
0.30
0.48
0.39
0.25
0.84
0.34
0.39
0.40
0.40
0.53
0.59
0.31
0.36
0.36
"Low er Explosive
or Flam m able
Lim it"
"Upper Explosive
or Flam m able
Lim it"
(LEL/LFL)
(%)
(UEL/UFL)
(%)
1.8
8.4
Butylene
1.98
9.65
LEL
UEL
Fuel/O2 Fuel/O2
0.087285 0.436681
0.09619 0.508604
Ethane
3
12.4
0.147 0.674
Ethylene
2.7
36
Hydrogen
4
75
Isobutane
1.8
9.6
Isobutene
1.8
9
Gasoline
1.4
7.6
Kerosine
0.7
5
Methane
5
15
Methyl Alcohol
6.7
36
n-Hexane
1.1
7.5
n-Pentene
1.65
Fuel Gas
Butane
7.7
0.132139
0.198413
0.087285
0.087285
0.067613
0.033568
0.250627
0.341959
0.052964
0.07989
2.678571
14.28571
0.505689
0.470958
0.391672
0.250627
0.840336
2.678571
0.3861
0.397255
ABB
Wang
Lopez
Suzaki
% C2
10
30
30
10
C2/O2
>1
1
1
1
EO Reactor
90
9
Section 100
R-101
R-102
E-101
E-102
E-103
E-104
F-101
F-102
F-103
D-101
D-102
D-103
D-104
ODH Primary Reactor
ODH Trim Oxidizer
ODH Primary Reactor Cooler
ODH Trim Oxidizer Cooler
Effluent Cooler # 1
Effluent Cooler # 2
Ethane Preheat Furnace
O2 Preheat Furnace
PS Preheat Furnace
ODH Primary Reactor Cooler Steam Drum
ODH Trim Oxidizer Cooler Steam Drum
Effluent Cooler # 1 Steam Drum
Effluent Cooler # 2 Steam Drum
Duty, MM kJ/h
704
245
704
245
175
175
108
35
1710
30000 gal
10440 gal
7500 gal
7500 gal
net energy, MM kJ/h (upper end)
$/lb C2H4
555
0.024
Quench Drum (2 reqd)
Quench Water Coolers
Amine Interchanger
CO2 Stripper Reboiler
Amine Scrubber
Amine CO2 Stripper
Quench Water Pump
Amine Interchange Pump
Amine Recycle Pump
60000 gal
1650
package
package
package
package
2150 SHP
package
package
SA m2
26107
9075
6519
2269
1620
1620
per 1.5 in tube
0.96
0.96
0.96
n tubes
27195
9453
TIC, $ MM
56.17
19.53
7.01
2.44
1.74
1.74
10.84
3.53
25.65
0.75
0.25
0.2
0.2
130.07
Section 200
D-201
E-201
E-202
E-203
T-201
T-202
P-201
P-202
P-203
1.5
13
10
20
1
-
60000
45.5
Section 300
C-301
C-302
E-301
E-302
E-303
D-301
D-302
D-303
T-301
P-301
DR-301
DR-302
DR-303
Charge Gas Compressor Stg 1
Charge Gas Compressor Stg 2
Stage 1 After Cooler
Stage 2 After Cooler
Stage 2 After Chiller
C2 Gas KO Pot #1
C2 Gas KO Pot #2
C2 Gas KO Pot #3
Caustic Gas Scrubber
Caustic Solution Circulating Pump
C2 Gas Primary Dryer
C2 Gas Guard Dryer
C2 Gas Dryer - Regen Cycle
26.7
16.1
11.1
4000 gal
2500 gal
2500 gal
package
package
3000 gal
3000 gal
3000 gal
5500 BHP
4400 BHP
320
200
135
4.1
3.3
1
0.65
0.5
0.08
0.06
0.06
3
0.5
0.5
0.5
20 ton dscnt
20 ton dscnt
20 ton dscnt
14.25
Section 400
T-401
C-401
E-401
E-402
E-403
E-404
P-401
P-402
P-403
D-401
D-402
Ethylene Fractionator
Heat Pump
Ethylene Fractionator Condenser
Ethylene Product Heater
Ethylene Fractionator Reboiler
Ethane Recycle Heater
Ethylene Product Pump
Ethane Recycle Pump
Reflux Pump (may not be required)
Ethylene Product Drum
Ethylene Fractionator Reflux Drum
5 m x 60 m
6000
160
18
140
2
400 SHP
25 SHP
80 stages
5
4
1
0.25
0.15
0.05
0.02
2400 m2
0.15
0.25
10.87
Total TIC
200.69
capital cost
100
BTPB
4.5
cost/y
22.22222
tax rate
45%
ATCF
project life inflation
12.22222222
15
3%
1
2
3
4
5
6
7
year 1
year 2
year 3
year 4
year 5
year 6
year 7
12.22222222 12.58888889 12.96656 13.35555 13.75621879 14.16891 14.59397
10.96118488 10.12516374 9.352907 8.639551 7.980603081 7.371914 6.80965
8
9
10
11
12
13
14
15
year 8
year 9
year 10
year 11
year 12
year 13
year 14
year 15
15.03179169 15.48274544 15.94723 16.42564 16.91841398 17.42597 17.94875 18.48721
6.290271167 5.810505544 5.367332 4.95796 4.579811215 4.230504 3.907839 3.609784
ROR
ROR
PW capital
PWCF
Ratio
0.115045714
11.50
100
99.99498133
1.000050189
BTPB
4.5
4
3.5
3
2.5
ATROI, %
11.51
13.58
16.11
19.31
23.57
Procedure: define a PB period, inflation rate and tax rate
goal seek cell B20 to be 1 by changing
cell A16
26.00
24.00
BTPB, y
22.00
20.00
18.00
16.00
14.00
12.00
10.00
2
2.5
3
3.5
ATROR, %
4
4.5
5
Production Economics - Ethane ODH 9090
O2 Case
Variable Costs
Fixed Costs
Capital Recovery
RNB
raw material, utilities
labor, overhead, depreciation, taxes, insurance
amount of cost associated with the capital equipment
[MARR; hurdle rate]
Production Capacity
Plant Costs
Property/Value Bases
420 C Coolant
0.324 $/lb C2H4
IBL+OBL
+20%
1500
$201
$80
$281
$338
MMPPY
MM
IBL
MM
OBL
MM
MM
Fuel
Hydrogen
Ethane
FG, LHV
Fuel eff
$8.00
190
3.1
18
85
per MMBTU
SCF/lb
lb/gal
MBTU/lb
% firing efficiency
Production Costs
Raw Materials/By-products
Ethane
3.1 lbs/gal
O2
Process Steam
Nitrogen
CO2
Process Water
Cat/Chem
miscellaneous
Basis
lb
lb
lb
lb
lb
lb
lb
Unit, $
0.18
0.02
na
na
na
na
1.00
lb/lb C2H4
1.230
1.17
0
0
0
0
0.001
Total Raw Material Costs
Utilities
Power, KWH
Cooling Water, M Gal
Steam, M lb
Refrigeration, MM BTU
Natural Gas, lbs (net)
usage
0.08
0.03
0
0
0.15
$/unit
0.1
0.15
10
10
0.1
Total Utility Costs
0.2214
$/lb C2H4
0.008
0.005
0.000
0.000
0.015
0.028
Total Variable Cost
Fixed Costs
usage
shifts
Labor
6
4
Foremen (@ 33 %)
Supervision (@ 7.5 %)
Maintenance Matl & Labor (6 % 0f ISBL)
Direct Overhead (50 % of L & S)
Plant Overhead (65 % L & M)
Insurance (1.5 % Plant Investment)
$/lb C2H4
0.221
0.023
0.000
0.000
0.000
0.000
0.001
rate
50000
0.249
$/lb C2H4
0.0008
0.00026
0.00006
0.00804
0.00056
0.00596
0.00338
Total Fixed Costs
0.01906
Total Cash Costs (FC + VC)
0.268
Capital Recovery (ATROI based on BTPB)
BT Payback, y
ATROI, %
4.500
4
3.5
3
11.500
13.6
16.1
19.3
Capital Recovery
0.05003 0.05628
0.06432
0.075
0.332
0.343
Total Cost of Production (minus SGA)
0.318
plus 2 % SGA
Required Netback
0.324
0.32435 0.33072 0.338925 0.3499
0.324
0.331
0.339
0.350
Production Economics - Ethane ODH 9090
O2 Case
Variable Costs
Fixed Costs
Capital Recovery
RNB
0.338 $/lb C2H4
raw material, utilities
labor, overhead, depreciation, taxes, insurance
amount of cost associated with the capital equipment
[MARR; hurdle rate]
Production Capacity
Plant Costs
Property/Value Bases
IBL+OBL
+20%
1500
$240
$96
$336
$403
MMPPY
MM
IBL
MM
OBL
MM
MM
Fuel
Hydrogen
Ethane
FG, LHV
Fuel eff
$8.00
190
3.1
18
85
per MMBTU
SCF/lb
lb/gal
MBTU/lb
% firing efficiency
390 C Coolant
Production Costs
Raw Materials/By-products
Ethane
3.1 lbs/gal
O2
Process Steam
Nitrogen
CO2
Process Water
Cat/Chem
miscellaneous
Basis
lb
lb
lb
lb
lb
lb
lb
Unit, $
0.18
0.02
na
na
na
na
1.00
lb/lb C2H4
1.230
1.17
0
0
0
0
0.001
Total Raw Material Costs
Utilities
Power, KWH
Cooling Water, M Gal
Steam, M lb
Refrigeration, MM BTU
Natural Gas, lbs (net)
usage
0.08
0.03
0
0
0.15
$/unit
0.1
0.15
10
10
0.1
Total Utility Costs
0.2214
$/lb C2H4
0.008
0.005
0.000
0.000
0.015
0.028
Total Variable Cost
Fixed Costs
usage
shifts
Labor
6
4
Foremen (@ 33 %)
Supervision (@ 7.5 %)
Maintenance Matl & Labor (6 % 0f ISBL)
Direct Overhead (50 % of L & S)
Plant Overhead (65 % L & M)
Insurance (1.5 % Plant Investment)
$/lb C2H4
0.221
0.023
0.000
0.000
0.000
0.000
0.001
rate
50000
0.249
$/lb C2H4
0.0008
0.00026
0.00006
0.0096
0.00056
0.00697
0.00403
Total Fixed Costs
0.02229
Total Cash Costs (FC + VC)
0.271
Capital Recovery (ATROI based on BTPB)
BT Payback, y
ATROI, %
4.500
4
3.5
3
11.500
13.6
16.1
19.3
Capital Recovery
0.05973
0.0672
0.0768
0.0896
0.331
0.338
0.348
0.361
Total Cost of Production (minus SGA)
plus 2 % SGA
Required Netback
0.33754 0.34516 0.354948
0.338
0.345
0.355
0.368
0.368
Production Economics - Ethane Steam Cracker
results of analysis: RNB
Variable Costs
Fixed Costs
Capital Recovery
0.348 $/lb C2H4
raw material, utilities
labor, overhead, depreciation, taxes, insurance
amount of cost associated with the capital equipment
[MARR; hurdle rate]
Production Capacity
Plant Costs
SP H2 Chem
Property/Value Bases
IBL+OBL
+20%
1500
$405
$162
$567
$680
MMPPY
MM
IBL
MM
OBL
MM
MM
Fuel
Hydrogen
Ethane
FG, LHV
Fuel eff
$8.00
190
3.1
18
85
per MMBTU
SCF/lb
lbs/gal
MBTU/lb
% firing efficiency
Production Costs
Raw Materials/By-products
Ethane
3.1 lbs/gal
Hydrogen
380 SCF/lb mol
Fuel Gas
18MBTU/lb, 85%
Propylene
< Chem grade
Cat/Chem
miscellaneous
Basis
lb
lb
lb
lb
lb
Unit, $
0.18
0.50
0.12
0.35
1.00
lb/lb C2H4
1.275
-0.072
-0.163
-0.020
0.001
Total Raw Material Costs
Utilities
Power, KWH
Cooling Water, M Gal
Steam, M lb
Refrigeration, MM BTU
Natural Gas, lbs
usage
0.008
0.036
0
0
0.3
$/unit
0.1
0.15
10
10
0.1
Total Utility Costs
Total Variable Cost
Fixed Costs
usage
shifts
Labor
10
4
Foremen (@ 33 %)
Supervision (@ 7.5 %)
Maintenance Matl & Labor (6 % 0f ISBL)
Direct Overhead (50 % of L & S)
Plant Overhead (65 % L & M)
Insurance (1.5 % Plant Investment)
rate
50000
$/lb C2H4
0.230
-0.036
-0.020
-0.007
0.001
0.167
$/lb C2H4
0.001
0.005
0.000
0.000
0.030
0.036
0.203
$/lb C2H4
0.001
4E-04
1E-04
0.016
9E-04
0.012
0.007
Total Fixed Costs
0.038
Total Cash Costs (FC + VC)
0.241
Capital Recovery ( Linked ATROI and BTPB)
Before Tax Pay Back, y
ATROI, %
Capital Recovery
Total Cost of Production (minus SGA)
4.5
11.5
3.5
16.1
3
19.3
0.101 0.1134 0.1296
0.1512
0.342
plus 2 % SGA
Required Netback
4
13.8
0.354
0.370
0.392
0.348 0.3612 0.3777
0.3997
0.348 0.361 0.378 0.400
Production Economics - Ethane Steam Cracker
results of analysis: RNB
Variable Costs
Fixed Costs
Capital Recovery
0.366 $/lb C2H4
raw material, utilities
labor, overhead, depreciation, taxes, insurance
amount of cost associated with the capital equipment
[MARR; hurdle rate]
Production Capacity
Plant Costs
Property/Value Bases
IBL+OBL
+20%
1500
$405
$162
$567
$680
MMPPY
MM
IBL
MM
OBL
MM
MM
Fuel
Hydrogen
Ethane
FG, LHV
Fuel eff
$8.00
190
3.1
18
85
per MMBTU
SCF/lb
lbs/gal
MBTU/lb
% firing efficiency
Production Costs
Raw Materials/By-products
Ethane
3.1 lbs/gal
Hydrogen
380 SCF/lb mol
Fuel Gas
18MBTU/lb, 85%
Propylene
< Chem grade
Cat/Chem
miscellaneous
Basis
lb
lb
lb
lb
lb
Unit, $
0.18
0.26
0.12
0.35
1.00
lb/lb C2H4
1.275
-0.072
-0.163
-0.020
0.001
SP H2 Fuel
Total Raw Material Costs
Utilities
Power, KWH
Cooling Water, M Gal
Steam, M lb
Refrigeration, MM BTU
Natural Gas, lbs
usage
0.008
0.036
0
0
0.3
$/unit
0.1
0.15
10
10
0.1
Total Utility Costs
Total Variable Cost
Fixed Costs
usage
shifts
Labor
10
4
Foremen (@ 33 %)
Supervision (@ 7.5 %)
Maintenance Matl & Labor (6 % 0f ISBL)
Direct Overhead (50 % of L & S)
Plant Overhead (65 % L & M)
Insurance (1.5 % Plant Investment)
rate
50000
$/lb C2H4
0.230
-0.019
-0.020
-0.007
0.001
0.184
$/lb C2H4
0.001
0.005
0.000
0.000
0.030
0.036
0.220
$/lb C2H4
0.001
4E-04
1E-04
0.016
9E-04
0.012
0.007
Total Fixed Costs
0.038
Total Cash Costs (FC + VC)
0.258
Capital Recovery ( Linked ATROI and BTPB)
Before Tax Pay Back, y
ATROI, %
Capital Recovery
Total Cost of Production (minus SGA)
4.5
11.5
3.5
16.1
3
19.3
0.101 0.1134 0.1296
0.1512
0.359
plus 2 % SGA
Required Netback
4
13.8
0.371
0.388
0.409
0.366 0.3788 0.3953
0.4174
0.366 0.379 0.395 0.417
Production Economics - Ethane Steam Cracker
results of analysis: RNB
Variable Costs
Fixed Costs
Capital Recovery
0.418 $/lb C2H4
raw material, utilities
labor, overhead, depreciation, taxes, insurance
amount of cost associated with the capital equipment
[MARR; hurdle rate]
Production Capacity
Plant Costs
Dow ATR E-1
Property/Value Bases
IBL+OBL
+20%
1500
$350
$140
$490
$588
MMPPY
MM
IBL
MM
OBL
MM
MM
Fuel
Hydrogen
Ethane
FG, LHV
Fuel eff
$8.00
190
3.1
18
85
per MMBTU
SCF/lb
lbs/gal
MBTU/lb
% firing efficiency
Production Costs
Raw Materials/By-products
Ethane
3.1 lbs/gal
Oxygen
Hydrogen
380 SCF/lb mol
Fuel Gas
18MBTU/lb, 85%
Propylene
< Chem grade
Cat/Chem
miscellaneous
Basis
lb
lb
lb
lb
lb
lb
Unit, $
0.18
0.02
0.25
0.12
0.35
1.00
lb/lb C2H4
1.330
1.890
0.127
-0.300
-0.057
0.001
Total Raw Material Costs
Utilities
Power, KWH
Cooling Water, M Gal
Steam, M lb
Refrigeration, MM BTU
Natural Gas, lbs
usage
0.008
0.036
0
0
0.3
$/unit
0.1
0.15
10
10
0.1
$/lb C2H4
0.239
0.038
0.032
-0.036
-0.020
0.001
0.253
$/lb C2H4
0.001
0.005
0.000
0.000
0.030
Total Utility Costs
0.036
Total Variable Cost
0.289
Fixed Costs
usage
shifts
Labor
10
4
Foremen (@ 33 %)
Supervision (@ 7.5 %)
Maintenance Matl & Labor (6 % 0f ISBL)
Direct Overhead (50 % of L & S)
Plant Overhead (65 % L & M)
Insurance (1.5 % Plant Investment)
rate
50000
$/lb C2H4
0.001
4E-04
1E-04
0.014
9E-04
0.01
0.006
Total Fixed Costs
0.033
Total Cash Costs (FC + VC)
0.322
Capital Recovery ( Linked ATROI and BTPB)
Before Tax Pay Back, y
ATROI, %
Capital Recovery
Total Cost of Production (minus SGA)
plus 2 % SGA
Required Netback
4.5
11.5
4
13.8
3.5
16.1
3
19.3
0.087
0.098
0.112
0.1307
0.409
0.420
0.434
0.453
0.418 0.4286 0.4429
0.4619
0.418 0.429 0.443 0.462
Comparison
0.42
conventional
Ethylene RNB, cts/lb
4.5
4
3.5
3
Required Netback, cents/lb
conventional
ODH
0.3483317 0.324346
0.3611837 0.330724
0.3777077 0.338925
0.3997397 0.349859
ODH
0.4
0.38
0.36
0.34
0.32
0.3
3
3.5
4
Payback, y
4.5
Fuel Value Hydrogen
Comparison
0.44
Ethylene RNB, cts/lb
4.5
4
3.5
3
Required Netback, cents/lb
conventional
ODH
0.3666917 0.324346
0.3795437 0.330724
0.3960677 0.338925
0.4180997 0.349859
0.42
conventional
ODH
0.4
0.38
0.36
0.34
0.32
0.3
3
3.2
3.4
3.6
3.8
BTPB, y
4
4.2
4.4
Summary Economics –
Cash Costs
• Conventional Pyrolysis
– Byproduct value result in lower CC than Case 3
– With byproduct H2 (conventional) taken as fuel, then
the CCs are approximately equivalent
• ODH - Case 3
– No byproducts and significant heat is rejected to the
atmosphere during recovery of process water
– Potential for heat pump on the quench system
Suggestions for Economic Improvement of the
ODH Process
• Low level heat upgrade
– power and/or steam generation
• Higher reactor operating pressure
– higher level of waste heat
– lower capital due to reduced compression
• Reduced excess oxygen required
– reduced oxidation required beyond CO conversion
to CO2
• Reduced process steam
Waste Heat Upgrade
• Many Options
– Rankine cycle
– Thermo-electric Exchangers
– Chemical Heat Pump
– Absorptive Refrigeration
– Stirling Engine
Waste Heat Upgrade
• Rankine Cycle
– Compressor
– Condenser (high level heat recovery)
– Let-down Valve
– Evaporator (waste heat)
Impact of Reactor Pressure on the
Temperature of the Quench Water
Conclusion – higher pressure will allow a hotter
quench water with the same amount of
water going forward
kg mols/h water .
6000
1.8 bar
5000
5 bar
4000
10 bar
3000
2000
1000
0
50
60
70
80
90
100
Quench Tem perature, C
X-axis
Y-axis
Quench Temperature
Amount of water in the product gas
Temperature of Waste Heat
79.5
C
Energy Cost, kJ/100
kJ recovered
Temperature of Heat Recovery Energy Spent per 100 kJ recovered
114
17.88
127
27.19
139
39.46
150
61.56
80.00
60.00
40.00
20.00
0.00
110 120 130 140 150
Temperature Upgrade, C
DOE Data - First Purchase Prices
1977
1982
1987
1992
1997
2002
2005
average
Crude
Nat Gas
$/crude
$/MCF
22.2
2.05
50.2
4.3
23.17
2.51
20.3
2.21
19.72
2.66
23.74
3.11
50.3
7.51
29.94714 3.478571
Ratio
10.82927
11.67442
9.231076
9.18552
7.413534
7.633441
6.697736
8.952142
average 8.952142
std dev 1.837358
% std dev 20.52422
14
12
10
8
6
4
2
0
1970
1990
2010
(LEL/LFL)
(UEL/UFL)
(%)
(%)
Acetaldehyde
4
60
Acetylene
2.2
85
Ammonia
15
28
Benzene
1.3
7.1
Butane
1.8
8.4
Butylene
1.98
9.65
Carbon Monoxide
12
75
Ethane
3
12.4
Ethylene
2.7
36
Ethyl Alcohol
3.3
19
Fuel Oil No.1
0.7
5
Hydrogen
4
75
Isobutane
1.8
9.6
Isobutene
1.8
9
LEL
O2/fuel
5.04
9.34
1.19
15.94
11.46
10.40
1.54
6.79
7.57
6.15
29.79
5.04
11.46
11.46
26.37
15.70
14.79
29.79
3.99
19.79
18.88
12.52
13.79
9.79
10.29
18.88
17.29
18.88
UEL
O2/fuel
0.14
0.04
0.54
2.75
2.29
1.97
0.07
1.48
0.37
0.90
3.99
0.07
1.98
2.12
3.33
2.08
2.55
3.99
1.19
2.92
2.59
2.52
2.48
1.87
1.68
3.23
2.75
2.79
LEL
fuel/O2
0.20
0.11
0.84
0.06
0.09
0.10
0.65
0.15
0.13
0.16
0.03
0.20
0.09
0.09
0.04
0.06
0.07
0.03
0.25
0.05
0.05
0.08
0.07
0.10
0.10
0.05
0.06
0.05
UEL
fuel/O2
7.14
26.98
1.85
0.36
0.44
0.51
14.29
0.67
2.68
1.12
0.25
14.29
0.51
0.47
0.30
0.48
0.39
0.25
0.84
0.34
0.39
0.40
0.40
0.53
0.59
0.31
0.36
0.36
Inlet
mol %
10
8
82
Outlet
kgmol/h
380
475
35264
Outlet
mol %
0.95
1.19
88.42
Isooctane
0.79
5.94
Isopentane
1.32
9.16
Gasoline
1.4
7.6
Kerosine
0.7
5
Methane
5
15
n-Heptane
1.05
6.7
n-Hexane
1.1
7.5
n-Pentene
1.65
7.7
Pentane
1.5
7.8
Propane
2.1
10.1
Propylene
2
11.1
Styrene
1.1
6.1
Toluene
1.2
7.1
p-Xylene
1.1
7
ODH
Case 3
Ethane
Oxygen
Water
Inlet
kg/h
114000
97280
560880
Inlet
kgmol/h
3800
3040
31160
sum
772160
38000
O2/C2
0.8
39881
1.25
T, oC
323.0
252.0
194.0
138.0
32.0
1.7
-20.6
-40.0
-59.4
-76.1
-101.1
-115.0
-134.4
$/MM kJ
14.7
9.0
5.8
3.6
0.8
13.2
20.1
27.3
39.8
50.1
71.9
99.5
133.5
SPS 1700
HPS 600
MPS 200
LPS 50
CW
C3
C3
C3
C2
C2
C2
C1
C1
200
400
160
140
120
100
Value, $/MM kJ
Value/Cost in Typical OP Cycles
T, oF
613.4
485.6
381.2
280.4
89.6
35.0
-5.0
-40.0
-75.0
-105.0
-150.0
-175.0
-210.0
80
60
40
20
0
-200
0
-20
Level, F
600
CO2 Sequestration, Removal
and Recovery/Removal Options
Amine
Membrane
CaO
Ryan Holmes
Comparison between base case catalyst (29524CCG) and base case+ H2O2 treated catalyst
(240-15C )
Ethylene selectivity (%)
98
96
94
92
240-15C
catalyst
90
Base case
catalyst
88
Target
86
20
30
40
50
60
Ethane conversion (% )
70
80
Student Researchers
– they do all the work
and so on.............
Thank you