Post Combustion CO2 Capture from Natural Gas
Combustion Flue Gas
SOLUTION DESCRIPTION:
Looking for new transformative technology
to capture CO2 from flue gas streams from
natural gas combustion in a once through
steam generator (OTSG) or potentially a
gas turbine.
CHALLENGE SPONSOR:
COSIA’s GHG EPA is sponsoring this
challenge.
Our aspiration is to produce our oil with
lower greenhouse gas emissions than
other sources of oil.
CREATED: October 1st, 2016
All projects are evaluated and actioned
as they are received.
COSIA has four Environmental Priority Areas
(EPAs): Water, Land, Tailings, and Greenhouse Gases
(GHGs).
For more information on this COSIA Challenge please visit www.cosia.ca
Canada’s Oil Sands Innovation Alliance (COSIA) accelerates the pace of environmental performance improvement in
Canada’s oil sands through collaborative action and innovation. COSIA Members represent more than 90 per cent of oil
sands production. We bring together innovators and leading thinkers from industry, government, academia and the wider
public to identify and advance new transformative technologies. Challenges are one way we articulate an actionable
innovation need, bringing global innovation capacity to bear on global environmental challenges.
1
WHAT TO SUBMIT TO COSIA
COSIA requires sufficient non-confidential, nonproprietary information to properly evaluate the
technology.
Some items that will be especially important to
present in your submission are:

Concept and basic unit operations

Technical justification for the approach (e.g.
laboratory batch or continuous experiments; pilot
or demo plants; process modeling; literature
precedent)

Describe quantities and qualities of utilities and
consumables that are required

Energy inputs – quantity and type(s)

Capital and operating cost estimates if available
based on described capacity targets

3rd party verified comparison of your proposed
technology against an MEA baseline. 3rd party
verifiers should be reputable, independent
engineering companies if possible

Basis of cost estimation, including estimation
scope, contingency, etc.

IP status of your proposed technology

What operating environment restrictions might
your technology face:
–
Explosive atmospheres
–
Severe weather
–
Power fluctuations
FUNDING, FINANCIALS, AND
INTELLECTUAL PROPERTY
COSIA Members are committed to identifying
emerging technologies and funding the development
of the technologies to the point of commercialization,
while protecting the Intellectual Property (IP) rights of
the owner of the technology.
COSIA Members have funded over 400 projects to
date, totaling over $1 billion.
Successful proposals can receive funding from
COSIA members to develop and demonstrate the
technology in an oil sands application. Multiple
technologies may be funded, at the discretion of the
Members.
HOW TO SUBMIT TO COSIA
Submit a summary of your solution using COSIA’s
Environmental Technology Assessment Portal (ETAP) Process, available at:
http://www.cosia.ca/initiatives/etap/ideasubmission-form
Please note: ETAP is a staged
submission process. The initial
submission requires only a brief
description and limited technical
information. Upon review by COSIA,
additional information may be
requested. Instructions for
submission are provided on the ETAP site.
All information provided is non-confidential.
COSIA will respond to all submissions.
2
#0016: Post Combustion CO2 Capture from Natural Gas Combustion Flue Gas
DETAILED SOLUTION DESCRIPTION
The successful technology will:






Perform >50% (preferably > 75%) better than benchmark amines (30% monoethanolamine (MEA)) based
post-combustion capture technologies on an energy and cost basis i.e. >50% reduction in capital
expenses, operating expenses, capture energy requirements and CO2 avoided cost *. CO2 avoided costs
must account for both direct and indirect** CO2 reductions.
Achieve high level of CO2 purity (e.g ~>95vol % CO2), although somewhat lower levels will be acceptable,
depending on the end use of the CO2 and if there are significant CAPEX/OPEX savings.
Capture > 90% of CO2, although lower capture levels will also be considered if there are significant
CAPEX/OPEX savings.
Have a minimal land-based footprint
Have no adverse environmental or safety impacts (e.g. increased NOx emissions, toxic chemical release)
Have minimal impact on or beneficial integration opportunities with existing operations.
Technologies at all stages of technical maturity are of interest.
BACKGROUND
Oil sands operations consume large quantities of natural gas to produce steam for in situ bitumen extraction. A
typical 33,000 BPD in situ facility would operate six once through steam generators (OTSGs) requiring 1600 GJ/h
(LHV) of combined energy input and emitting ~2,200 tonnes CO2 per day. Conventional air supply (containing 21%
O2) for combustion of pipeline specification natural gas in OTSGs produces flue gas with a low CO2 content (~7-8%
by volume) at atmospheric pressure. OTSG flue gas contains 10 to 15% (volume) water, has a temperature ~185
ᵒC, and can have 25 – 30ppm SO2 resulting from burning produced gas from the bitumen reservoir. OTSGs are
also used for steam generation in oil sands mining and extraction operations.
Gas turbines, with heat recovery steam generators, are also applied in some oil sands in situ or mining operations in
place of one or more OTSGs. While gas turbine flue gas is a candidate for CO2 capture, CO2 concentration in the
flue gas is much lower (4% by volume).
COSIA is ideally seeking transformative CO2 capture technologies that significantly outperform today’s state-of-the
art advanced amines. The ultimate fate of the CO2 could be geological storage or conversion to useful products, for
which purity, contaminants, and required delivery pressure may vary. Innovative combinations of post-combustion
capture technologies will also be considered (e.g. “hybrid” approach of using a membrane for initial concentration of
CO2 prior to capture).
Modularization and offsite fabrication is preferable given the remote location of Canada’s Athabasca oil sands.
Material and energy flow diagrams for a standard 33,000 BPD Steam Assisted Gravity Drainage (SAGD) facility are
provided below.
APPROACHES NOT OF INTEREST
The following approaches are not of interest for this specific Challenge Statement:





Incremental improvements to advanced (next generation) amine based capture systems – targeting
significantly better performance as detailed in the “Request for Proposal Description” section;
Pre-combustion technologies;
Oxy-combustion technologies;
CO2 conversion technologies; and
Fuel cell technologies.
ADDITIONAL INFORMATION
3
#0016: Post Combustion CO2 Capture from Natural Gas Combustion Flue Gas
* CO2 Avoided Cost
The CO2 Avoided Cost is the overall cost measure most commonly reported in CCS studies. It compares a plant
with CO2 Capture (CC) to a “reference plant” without CC, and quantifies the average cost of avoiding a unit (typically
in tonnes) of atmospheric CO2 emissions while still producing the same quantity of useful product. The CO2
avoidance cost can be directly compared with market carbon price or regulatory carbon compliance cost. The Cost
of CO2 Avoided ($/tonnes CO2) is calculated as follows.
CostofCO Avoided
CostofPlantwithCC CostofReferencePlant nocapture
CO emissionsfromReferencePlant CO emissionsfromPlantwithCC
Capturing carbon dioxide requires energy which is generally produced by the combustion of a fuel. Therefore, CO2
is created to facilitate the capture process. This additional CO2 produced is not included in the avoided cost
calculation because it is additional emissions to the reference case with no CO2 capture. The Avoided CO2
emissions from Plant with CC is the difference between the amount of CO2 captured and the CO2 emitted by the
operation of the CO2 Capture Plant (including both direct and indirect** CO2 emissions).
The avoided cost of your technology must be compared to a reference case of post combustion CO2 capture at a
SAGD facility using 30% MEA. As COSIA members must compare capture costs on an equal and consistent basis,
use the avoided cost calculations found in the Alberta Innovates – Energy and Environment Solutions report ”ECM
Evaluation Study “ (Case 1B). This report can also inform your key assumptions and avoided cost calculation
methodology.
Case 1B provides you the cost build up and avoided cost calculation methodology for the 30% MEA case as applied
to OTSG flue gas CO2 capture. To evaluate your technology on a comparable basis, please provide the following in
your submission:
Base Case: Your estimate for the avoided cost for the base 30% MEA capture case (Case 1B). If your assessment
of the Base Case is different from Case 1B above, please provide supporting documentation to support your claims.
New Capture Technology Case: provide an assessment of your proposed capture technology using the same
methodology as used to assess the Base Case. A comparison of the avoided cost and operating performance
against the Base Case will be required. The CO2 will be delivered at the facility battery limits at the same operating
and purity specifications as Case 1B.
Ensure to provide COSIA with a breakdown of the cost calculations and assumptions for your technology.
Submissions that do not include an assessment of both the Base Case and New Capture Technology Case using
the referenced methodology described above will be rejected.
** Indirect Emissions
For any power consumption within the capture process, an electricity grid GHG intensity factor of 0.64 t CO2e/MWh
can be assumed, as per the Alberta Government’s “Carbon Offset Emission Factors Handbook, 2015, No.1.”
4
COSIA SAGD TEMPLATE
Base Case
Mechanical Lift - 2200 kPa
Warm Lime Softening - OTSG
10,210
BPSD
Diluent
27,765
3,018
53.7
BPSD
m3/d
API
8,783
BPSD
Dilbit
51,941
8,258
21.3
BPSD
m3/d
API
Oil Treating
Diluent lost to Fuel
42
BPSD
m3/d
7
Well Pad Facilities
Air Cooler
Vapour Recovery
PADS
Emulsion
122,948 BPSD
3
19,547 m /d
Fluid Water Knock-Out
1 Vessel
Preflash
Vessel
Treaters
2 x Mechanical
Chemicals
Produced Gas
Composition
H2
0.3 Mol%
CO2 30.0 Mol%
N2
1.3 Mol%
H2S 0.13 Mol%
C1
63.6 Mol%
C2
1.63 Mol%
C3
1.98 Mol%
C4
0.3 Mol%
C5+ 0.88 Mol%
Reservoir
SOR:
GOR:
3.00 (wet)
5.00
Bitumen
33,000
5,247
7.08
5.05
Produced Water
589,710
14,182
1,492
188
14
300
Produced Gas
0.93
26,233
BPSD
m3/d
API
% Sulfur
(comp at test separator)
kg/h
m3/d
mg/L TDS
mg/L Silica
mg/L Hardness
mg/L TOC
Sour CPF Produced Gas
1.85
MMSCFD
Sm3/d
52,283
0.21
Sulfur (metric t/d)
Composition (Dry Basis)
H2
0.2
Mol%
CO2
Mol%
43.1
N2
Mol%
0.9
H2S
Mol%
0.3
48.9
C1
Mol%
C2
1.4
Mol%
C3
2.0
Mol%
C4
0.3
Mol%
6.7
C5+
Mol%
Skim Tank
Produced Water
591,682 kg/h
3
14,234 m /d
1,492
mg/L TDS
188
mg/L Silica
14
mg/L Hardness
300
mg/L TOC
Water Treatment
MMSCFD
Sm3/d
Chemicals
Lime
MagOx
Soda ash
PW
Tank
WLS Feed
856,388
20,587
6,160
152
10
530
kg/h
m3/d CWE
kg/h
m3/d
% Losses
Steam Generation
Ion
Exchange
86
Flue Gas (includes Glycol Heater)
CO2
2,191
metric t/d
SO2
0.06
metric t/d
NOx
0.38
metric t/d
NOx emission:
9.66
g/GJ
Energy
101
GJ/h (LHV)
Flow Rate
MMSCFD
462
O2 in Fuel Gas
Wt%
2.1%
WLS Overflow
855,905 kg/h
3
20,576 m /d
6,062
mg/L TDS
34
mg/L Silica
3
mg/L Hardness
mg/L TOC
515
kg/h
m3/d
mg/L TDS
mg/L Silica
mg/L Hardness
mg/L TOC
Clarifier Waste
980
259
22,945
Make-up Water
149,027 kg/h
m3/d
3,584
7,172
mg/L TDS
7
mg/L Silica
204
mg/L Hardness
mg/L TOC
6
363 kg/h
96 kg/h
37 kg/h
WLS
1 x WLS Treater
Water Losses to Reservoir:
Method 1 Water Recycle:
Recycled Recovered Diluent
0
BPSD
m3/d
0
Chemicals
IGF/ISF/ORF Units
1 Train
De-oiled Water
589,560 kg/h
3
14,175 m /d
1,492
mg/L TDS
188
mg/L Silica
14
mg/L Hardness
300
mg/L TOC
Steam
65,522
1,576
10
CPF Dilbit
16.1 API
De-Oiling
Electricity (ESP)
2.6 MW
655,220
15,757
Water lost to Dilbit
13
BPSD
m3/d
2
BFW
Tank
Backwash
Summary Table
MU TDS (ppm)
PW TDS (ppm)
PW TOC (ppm)
LP Flash BD (%)
BD Recycle (%)
TDS to Boiler (ppm)
Boiler TOC (ppm)
MU Flowrate (kg/h)
WLS Sludge (kg/d)
Disposal Type (L,S)
Disposal Rate (kg/h)
Disposal Solids (kg/d)
Service Water
4,280
kg/h
m3/d
103
7,172
1,492
300
8%
60%
6,059
515
149,027
23,530
L
63,435
51,662
Regeneration
kg/h (dry basis)
m3/d
mg/L TOC
Waste to Disposal
Stream
HP Steam
100
655,220
15,757
10.0
Utility Steam
35.0 GJ/h
15,133 kg/hr
Afterfilters
WAC Polishers
3 x WAC Units
2 x Polishers
Blowdown to WLS
117,811 kg/h
m3/d
2,829
28,493 mg/L TDS
158
mg/L Silica
0
mg/L Hardness
mg/L TOC
2,346
HPS
% Quality
kg/h
m3/d CWE
MPag
Wet Steam
77
% Quality
851,624 kg/h
3
20,474 m /d CWE
Efficiency
Duty (abs)
Duty (fired)
91.5
1,437
1,362
1,570
1,488
OTSG
6 x OTSG Boilers
Radiation Losses
32.1
GJ/hr
% (LHV)
BFW
GJ/h
851,624
MMBTU/h
20,474
GJ/h (LHV)
6,059
MMBTU/h (LHV)
34
0
170 °C
515
LP Steam
Flash
Blowdown to Disposal
63,435 kg/h
m3/d
1,523
28,472 mg/L TDS
2153
kg/h solids
kg/h
m3/d
mg/L TDS
mg/L Silica
mg/L Hardness
mg/L TOC
BFW Pump (LP&HP) Power
5.5 MW
%
Treated Produced Gas
1.85
MMSCFD
92
679,396
63
Air Blower
3.7 MW
Steam to reservoir
Losses to reservoir
Produced Water
Losses to production
De-oiled Water
Make-up Water
Supernatant
WLS Feed
WLS Overflow
Clarifier Waste to Land
Blowdown to Disposal
LP Steam to WT
LP Steam to Header
Service Water
BFW
kgmol/hr
kJ/kgmol (LHV)
GJ/h
Source
OTSG Flue Gas
Recovered Sulfur
Natural Gas to CPF
37.33
MMSCFD
kgmol/hr
1,859
810,745 kJ/kgmol (LHV)
1,508
GJ/h
32.8 GJ/hr
Glycol Heater
0.81
40
MMSCFD
Kgmol/hr
Natural Gas (Total)
38.14
MMSCFD
kgmol/hr
1,900
Flow
kg/h
655,220
65,522
591,682
85
589,560
149,027
856,388
855,905
980
63,435
0
15,133
4,280
851,624
Water Balance
Flow
m3/d
15,757
1,576
14,234
2
14,175
3,584
20,587
20,576
259
1,523
0
363,198
103
20,474
TDS
ppm
1,492
1,492
7,172
Silica
ppm
188
188
7
Hardness
ppm
14
14
204
6,160
6,062
152
34
10
3
28,472
0
0
6,059
6,059
158
0
0
34
34
0
0
0
0
0
CO2
metric t/d
2191
-
NOx
metric t/d
0.38
-
Emissions Summary
SO2
S
metric t/d
metric t/d
0.06
0.03
0.00
ENERGY FLOW DIAGRAM
Base Case: WLS - OTSG
Glycol Air Cooler
125 GJ/h
Total Air Cooler Heat Released to Atmosphere
GJ/hr
128.2
(relative to ambient air)
Glycol Return
71 °C
50 °C
40 °C
H
Produced Gas Cooler
2.4 GJ/h
1.2 GJ/h
Diluent
5.8 °C
4.41 GJ/h
128 °C
55 °C
55 °C
Produced
Gas
Emulsion / BFW
PADS
Exchanger
137 GJ/h
133 °C
Preflash Emulsion
175 °C
Vessel
Vapor
Recovery
Oil Treating
129 °C
131 °C
Sales Oil Coolers
43.9 GJ/h
Dilbit
50 °C
Heat Exchangers Legend
Process to Process
C
129 °C
106 °C
H
Hot Glycol
C
Cold Glycol
144 °C
Skim Tank
Produced Water Cooler
13.4 GJ/h
85 °C
90.3 °C
C
PW / BFW Exchanger
85 GJ/h
Direct Contact/Quench
97.2 °C
106 °C
Reservoir
69 °C
De-Oiling / Water Treatment
40 °C
18.1 GJ/h
PW / MU water exchanger
BFW
Make-up Water Heater
22 GJ/h
Make-up Water
H
5 °C
Exchangers
Air Glycol Heater 2
13 GJ/h
55 °C
82 °C
H
BD Water to Disposal
80 °C
Water Heat to Earth
20 GJ/hr
80 °C
Blowdown Cooler
(based on 5°C Ground Temp)
79.3 GJ/h
Air Glycol Preheater
9.16 GJ/h
Forced Draft Fan
Air
20 °C
Fan
C
5 °C
H
Stack Losses
100.9
GJ/hr
(LHV basis)
Stack
195 °C
33 °C
Emulsion / BFW
Produced Water Glycol Cooler
PW / BFW Exchanger
Produced Gas Air Cooler (s)
Diluent Glcyol Heater
Sales Oil Coolers
Make-up Water Glycol Heater
PW / MU water exchanger
Blowdown Glycol Cooler
BFW Preheaters
OTSG Air Glycol Heaters (two services)
OTSG Air Preheater (Flue Gas)
Utility Coolers
Glycol Air Cooler
Electrical Loads
HP Steam
310 °C
BFW
170 °C
HPS
Radiation Losses
32.1
GJ/hr
(relative to ambient)
310 °C
Utility Steam
15,133 kg/h
OTSG
BFW Preheaters
86.7 GJ/h
186 °C
LP Steam
Flash
Duty
GJ/h
136.9
13.4
84.5
3.5
4.4
43.9
21.8
18.1
79.3
86.7
22.7
N/A
11.4
124.7
HP BFW Pump
LP BFW Pump
Downhole Pumps
Pad Auxiliaries
Forced Draft Fan
Misc Users
VRU Compressors
WLS/Evaporator
Glycol System
Total
Power
MW
4.8
0.8
2.6
1.3
3.7
1.9
2.1
0.5
0.4
17.9
Direct CO2 Generation
Indirect CO2 Generation
Total CO2 Emissions
2,191 MT/day
328 MT/day
2,519 MT/day
220 °C
35.0 GJ/h
55 °C
Inputs
HP BFW Pump
146 °C
Natural Gas
Electrical Power
Produced Gas
63 GJ/h (LHV)
40 °C
30 GJ/hr (LHV)
Glycol Heater
Natural Gas Glycol Heater
1.16 GJ/h
H
1.8 GJ/h
H
11.4 GJ/h
Tracing &
Building Heat
C
Utility
Coolers
5 °C
Natural Gas
Heat Input (LHV)
1538
GJ/h
417.6
62.5
480.1
kg/m3 Bitumen
kg/m3 Bitumen
kg/m3 Bitumen
Assumes electricity grid CO2 emissivity of 763 kg CO2eq / MW-hr
Direct Emissions from Combustion only
Combustion Air
C
Equivalent Heat
GJ/h
31.1
5.2
17.0
8.5
24.0
12.2
13.7
3.1
2.5
117.3
Energy
GJ/h
1538
117.3
51.1 °C
Total
1655