Report No. COAL R309 BERR/Pub URN 07/1251

Report No. COAL R309 BERR/Pub URN 07/1251
FUTURE CO2 CAPTURE
TECHNOLOGY OPTIONS FOR THE
CANADIAN MARKET
Report No.
COAL R309
BERR/Pub
URN 07/1251
MARCH 2007
by
Bin Xu
Doosan Babcock Energy Limited
Porterfield Road
Renfrew, PA7 8DJ, United Kingdom
Tel: +44 (0)141 885 3901
R. A. Stobbs
Canadian Clean Power Coalition
2901 Powerhouse Drive,
Regina, SK S4N 0A1, Canada
Tel: +1 306 566 3326
Vince White
Air Products PLC
Hersham Place
Molesey Road
Walton-on Thames
Surrey, KT12 4RZ, United Kingdom
Tel: +44(0)1932 249948
R. A. Wall
Alstom Power
Technology Centre
Cambridge Road
Whetstone
Leicester LE8 6LH, United Kingdom
Tel: +44 (0) 116 284 5763
Jon Gibbins
Imperial College
London, SW7 2BX , United Kingdom
Tel: +44 (0) 207 594 7036
Masaki Iijima
Mitsubishi Heavy Industries Ltd
3-3-1, Minatomirai, Nishi-Ku
Yokohama 220-8401, Japan
Tel: +81 45 224 9400
Alex MacKenzie
Neill & Gunter
845 Prospect Street
P. O. BOX 713
Fredericton, NB E3B 5B4, Canada
Tel: +44 (0) 207 594 7036
The work described in this report was carried out under contract as
part of the BERR Carbon Abatement Technologies Programme. The
programme is managed by AEA Energy & Environment. The views
and judgements expressed in this report are those of the contractor
and do not necessarily reflect those of the BERR or AEA Energy &
Environment.
First published 2007
© Crown copyright 2007
EXECUTIVE SUMMARY
The BERR Project 366 investigates ‘Future CO2 Capture Technology Options for the
Canadian Market’ by evaluating the techno-economic feasibility of new-build coalfired advanced supercritical power plant options utilising Oxyfuel and Amine CO2
capture technologies for both capture and capture retrofit solutions.
This BERR 366 project has been undertaken by a project consortium co-ordinated by
Doosan Babcock (formerly Mitsui Babcock). The project consortium comprises the
following members:
•
•
•
•
•
•
•
Doosan Babcock (UK)
Canadian Clean Power Coalition (CCPC) (Canada)
Alstom Power (UK)
Air Products (UK)
Imperial College (UK)
Neill & Gunter (Canada)
Mitsubishi Heavy Industries (MHI) (Japan)
This report presents the final project reportage for the public domain, the contents of
which are provided by and based on the consensus of the project consortium.
Within the BERR-366 project, the evaluation of the conceptual designs for the coalfired ASC power plant with Amine Scrubbing CO2 Capture and CO2 Capture retrofit
options have been established for three different Canadian coals/sites, namely:•
C1: Sub-bituminous/Keephills: TransAlta Power
•
C2: Bituminous/Point Tupper: Nova Scotia Power
•
C3: Lignite/Shand: SaskPower
The main coal/site for this study is C1: sub-bituminous for which techno-economic
assessments have been carried out for each of the conceptual designs summarised as
follows:
•
R0: an air/PF-fired Advanced SuperCritical (ASC) reference power plant (RPP)
with appropriate emissions control; without CO2 capture
•
A1: an oxygen/PF-fired ASC boiler with oxyfuel CO2 capture
•
A2: a retrofit of the base case R0 to oxyfuel CO2 capture (C1 only)
•
B1: an air/PF-fired ASC boiler with post-combustion Amine CO2 capture
•
B2: a retrofit of the base case R0 to post-combustion Amine CO2 capture (C1
only)
The outline scope for all project cases are summarised below:
v
Project Cases
Power Plant Options
ASC Reference Power Plant &
CO2 Capture/Capture Retrofit
C1:
C2:
C3:
Sub-bituminous
Bituminous
Lignite
R0 : ASC Reference PP
Case C1-R0
Case C2-R0
Case C3-R0
A1 : ASC Oxyfuel CO2 Capture PP
Case C1-A1
Case C2-A1
Case C3-A1
A2 : ASC Oxyfuel CO2 Capture Retrofit PP
Case C1-A2
B1 : ASC Amine CO2 Capture PP
Case C1-B1
B2 : ASC Amine CO2 Capture Retrofit PP
Case C1-B2
Case C2-B1
Case C3-B1
-
-
Table 1 ASC Advanced SuperCritical; PP: Power Plant
Within this BERR-366 project, all power plant options are based on ASC boiler/turbine
technology targeting the state-of-the-art steam turbine inlet conditions of
290bara/600°C (HP) and 620°C (IP). All designs are on the basis that proven
technologies be employed wherever possible and appropriate.
For the Canadian market a nominal output of approximately 400MWe (net) is the
target size for an ASC CO2 capture power plant for this project. For the convenience
of benchmarking the various CO2 capture technology options, the performance design
and evaluation of each power plant option are based on assuming the same fuel heat
input rate as that of the reference power plant case R0 which is approximately
500MWe (net) without CO2 capture.
All CO2 capture power plant options in this project have been designed to achieve
approximately 90% CO2 capture rate and conform to all other emission targets
specified by CCPC for this project. The main performance and features of these CO2
capture power plants comparing to the reference power plants are summarised below.
Technical Evaluation Results:
ASC Air/PF-fired Reference Power Plant without CO2 Capture:
For the ASC reference power plants R0 with nominal net output of 500MWe, the
power plant net cycle efficiency achieves respectively as follows:
• C1-R0: 42.9% net (HHV basis): Sub-bituminous PF for Keephills: TransAlta Power
• C2-R0: 44.5% net (HHV basis): Bituminous PF for Point Tupper: Nova Scotia
Power
• C3-R0: 39.7% net (HHV basis): Lignite PF for Shand: SaskPower
vi
ASC PF-fired Power Plant with Amine CO2 Capture Technology Options:
Compared to an ASC air/PF-fired reference power plant without CO2 capture, for the
same fuel heat input, as expected a power plant with CO2 capture results in a
reduction in power plant performance in terms of both plant net efficiency and net
output.
With a nominal target of 90% CO2 capture, the relative reduction in cycle efficiency
for a post-combustion Amine Scrubbing CO2 capture power plant varies slightly
depending on the coal/site conditions. For the main project design fuel C1: subbituminous coal, the reduction in cycle efficiency is estimated at approximately 9.6%
points (HHV basis) compared to the reference power plant C1-R0 without CO2
capture.
Comparatively, approximately 9.0% points (HHV), and 9.3% points (HHV) cycle
efficiency reductions resulting from Amine Scrubbing CO2 Capture option are
estimated for the C2 and C3 coal/site. The overall cycle efficiencies for the Amine
cases considered are as follows:
•
•
•
•
C1-B1:
C1-B2:
C2-B1:
C3-B1:
33.4
33.6
35.7
30.3
%
%
%
%
net
net
net
net
(HHV
(HHV
(HHV
(HHV
basis):
basis):
basis):
basis):
Sub-bituminous : Amine CO2 Capture
Sub-bituminous : Amine CO2 Capture Retrofit
Bituminous : Amine CO2 Capture
Lignite : Amine CO2 Capture
Note that Case C1-B2 defined as the retrofit of C1-R0, is assumed to retain the same
condenser with same cooling water mass flow rate of C1-R0, which is approximately
50% larger than that of C1-B1, hence C1-B2 retrofit option results in a lower
condenser pressure 3.0kPa instead of 4.0kPa of C1-R0 and C1-B1, and gives slightly
higher output than that of C1-B1. This assumption requires an additional auxiliary
cooling water system to meet the requirements of the retrofitted CO2 capture plant.
Compared to what had been presented in previous D4.2 report [3], the performance
and efficiencies of the Amine CO2 Capture cases presented in this D7 final report
have been improved for approximately 1% point resulted from further process and
cycle optimisation by MHI and Alstom Power.
ASC PF-Fired Power Plant with Oxyfuel CO2 Capture Technology Options
With a nominal target of 90% CO2 capture, the overall cycle efficiencies for the
Oxyfuel cases considered are as follows:
•
•
•
•
C1-A1:
C1-A2:
C2-A1:
C3-A1:
34.1
33.4
36.0
31.6
%
%
%
%
net
net
net
net
(HHV
(HHV
(HHV
(HHV
basis)
basis)
basis)
basis)
:
:
:
:
Sub-bituminous : Oxyfuel CO2 Capture
Sub-bituminous : Oxyfuel CO2 Capture Retrofit
Bituminous : Oxyfuel CO2 Capture
Lignite : Oxyfuel CO2 Capture
vii
ASC Power Plant with Oxyfuel or Amine Scrubbing CO2 Capture
C1: Sub-bituminous
C2: Bituminous
(Keephills, TransAlta Power)
Case Ref. No.
C1-R0
CO2 Capture Rate
%
C3: Lignite
(Point Tupper, Nova Scotia Power)
(Shand, Sask Power)
C1-A1
C1-A2
C1-B1
C1-B2
C2-R0
C2-A1
C2-B1
C3-R0
C3-A1
C3-B1
0
90.0
90.0
90.0
90.0
0
90.0
90.0
0
90.0
90.0
Fuel Fired
kg/s
62.74
62.74
62.74
62.74
62.74
35.91
35.91
35.91
84.14
84.14
84.14
Power Plant Gross Output
MWe
542
570.5
568.7
480.5
484.1
546.4
568.1
490.7
542.0
580.0
479.2
Power Plant Net Output
MWe
503.4
400.2
392.3
391.3
394.1
510.5
413.2
409.9
499.5
397.5
382.0
%(HHV)
42.91
34.11
33.43
33.35
33.59
44.48
36.01
35.72
39.68
31.57
30.34
%(LHV)
45.57
36.22
35.50
35.41
35.67
46.46
37.61
37.73
43.71
34.78
33.43
Plant Net Efficiency
Efficiency Penalty on CO2 Capture (percentage points)
%(HHV)
0.0
-8.8
-9.5
-9.6
-9.3
0.0
-8.5
-8.8
0.0
-8.1
-9.3
%(LHV)
0.0
-9.3
-10.1
-10.2
-9.9
0.0
-8.8
-9.2
0.0
-8.9
-10.3
CO2
kg/kWh
0.79
0.08
0.09
0.10
0.10
0.69
0.08
0.09
0.88
0.10
0.12
NOx
g/MWh
44.9
8.0
10.9
47.1
47.1
35.4
2.3
44.6
36.6
4.1
49.6
SOx
g/MWh
49.7
Nil
Nil
5.5
5.4
32.0
Nil
18.3
21.5
Nil
18.5
Emissions
Particulates
Hg
Condenser Pressure
Heat
Rejection/Flue
Gas Discharge
g/MWh
12.6
Nil
Nil
2.6
2.6
10.9
NIl
13.8
10.7
NIl
14.5
mg/MWh
3.5
Nil
Nil
3.3
3.3
2.4
Nil
3.0
4.5
Nil
5.5
kPa
4.0
4.0
5.0
4.0
3.0
Natural Draught Cooling Tower
2.6
4.0
Sea Water Cooling/Stack
Natural Draught Cooling
Tower
Table 2 Performance of Power Plants with or without CO2 Capture Options
viii
Compared to the reference power plant C1-R0 without CO2 capture, for the main project
design fuel C1 Sub-bituminous coal, the reduction in cycle efficiency of the Oxyfuel CO2
capture power plant option C1-A1 is estimated to be approximately 8.8% points (HHV
basis).
The relative reduction in cycle efficiency of the Oxyfuel CO2 capture power plant for the
three coals/sites are approximately 9.0% points on HHV basis despite the different
coal/site conditions.
Note that the retrofit option of C1-A2 indicates approximately 1% point more efficiency
penalty than that of C1-A1, ie 9.5% points (HHV basis) cycle efficiency reduction to the
reference power plant C1-R0 without CO2 capture. This is based on a plant restriction of
constraining the cooling water system to the C1-R0 cooling water mass flow rate,
which is approximately 20% less than that of C1-A1. ith this cooling water restriction,
it was estimated that the increase in condenser heat rejection combined with the
additional cooling water requirements elsewhere would increase the condenser pressure
by some 1.0 kPa at average ambient conditions (ie 5.0 kPa instead of 4.0 kPa).
Supplementing the main cooling water system pumps of the cooling tower (and using
less adiabatic compression) would negate this plant efficiency penalty.
Despite the different coal/site conditions, all the PF-fired power plants with or without
CO2 Capture option have the common block features as listed in Table 3 below.
Steam Generator
Two-pass once-through BENSON steam generator with POSIFLOWTM
vertical tube furnace and appropriate emission reduction systems
Turbine & Generator
Four module reheat steam turbine:Single flow HP reaction turbine
Double flow IP reaction turbine
Two double flow LP reaction turbine
H2 -cooled generator rotor and water-cooled stator windings
85% HP by-pass/50% LP by-pass
Feedwater Heating
10-stage feedwater heating with top heater above reheat point
(HARP), and desuperheater ahead of top heater
5 x LP heaters
1 x Feedwater tank and deaerator
3 x HP heaters + 1 x Desuperheater
Feed Pumps
2 x 70% motor-driven feedwater pumps
2 x 70% motor-driven condensate pumps
Steam Temperature
Control
Superheater steam temperature control to 50%MCR, Reheat steam
temperature control to 70%MCR
Steam Cycle Operation
Sliding pressure in the range 40% ~ 100%MCR
Plant Operation Basis
Base load; Nominal frequency 60 Hz; design life 30 years
Table 3 ASC PF Power Plant: Power Block Feature
ix
Economic Evaluation Results:
The results of the economic and performance analysis for the main design C1 Subbituminous power plant cases as studied are presented in Table 4 below. As is shown,
the levelised costs are found to be reasonably close for all study options. The costs for
the new build CO2 capture power plant options, C1-A1 Oxyfuel and C1-B1 Amine, are
virtually the same. However, the results of this project show a more significant
difference in the total costs of the CO2 capture retrofit power plant options.
C1: Sub-bituminous
(Keephills, TransAlta Power)
OPTION
C1-R0
C1-A1
C1-A2
C1-B1
C1-B2
Capital Cost (CA$ x 10 )
$1,757.9
$2,448.4
$2,837.6
$2,320.2
$2,331.1
Levelized Fuel and O&M Costs
3
(CA$ x 10 ) Per Year
$48,263.4
$48,926.5
$51,020.4
$57,148.1
$59,519.7
6.48
9.86
11.15
9.83
9.92
--
$47.76
$66.76
$48.82
$50.04
6
Levelized Cost of Electricity
(¢ per kWh)
Levelized CO2 Capture Cost
(CA$ per tonne)
Table 4 Summary of Costs (C1-A2 and C1-B2 shown on total plant basis)
As the C1-R0 RPP assumes only minimal capture readiness, the resultant oxyfuel retrofit
case C1-A2 has incurred boiler modifications and subsequent costs that can otherwise
be avoided by ensuring the RPP is made capture ready rather than non-capture ready.
The site preferred boiler series back end arrangement and reheat spray requires boiler
pressure part modifications when retrofitting to oxyfuel. Eliminating the avoidable cost
of boiler modifications through capture ready design will reduce the levelised cost of
CO2 capture for the oxyfuel retrofit case C1-A2 by about 5-10%.
The cost of the retrofit oxyfuel CO2 capture plant (C1-A2) is higher than other options,
partly due to the higher O&M costs for a retrofitted plant due to the less efficient
cooling system and the need to operate an existing FGD plant that is not present in the
C1-A1 oxyfuel capture case. The low sulphur content in the C1 coal does not
necessitate a FGD plant within the boiler island.
The costs for the C1-A2 and C1-B2 do not take into account the lost generation a
retrofitted option would cause while the unit is off line during construction.
The levelized cost of CO2 capture includes the main cost categories of capital, taxes,
O&M, parasitic energy, and credits, but it is assumed that no CO2 credits are received.
The energy losses required to operate equipment directly related to CO2 capture are one
of the largest cost items, closely followed in most cases by capital charges. The O&M
costs in contrast are found to make up a relatively minor portion of the total charges.
x
Compared to the reference power plant, the Oxyfuel CO2 capture power plant C1-A1 is
approximately 40% higher in CAPEX, which is 15% less than that of the retrofit option
C1-A2.
The Amine Scrubbing CO2 capture power plant C1-B1 is approximately 10% lower in
CAPEX, but 20% higher in OPEX than that of Oxyfuel option C1-A1.
Conclusions:
The conclusions drawn for this BERR 366 project based on the technical and economic
analysis results are as follows:Technical:
1.
Compared to a reference power plant without CO2 capture, for a nominal
400MWe (net) ASC power plant with 90% CO2 capture rate, the thermal
efficiency loss due to CO2 capture is approximately 8.0 ~ 9.5% points (HHV
basis) or 9 ~ 10% points (LHV basis).
2.
The relative thermal efficiency penalty due to CO2 Capture using Oxyfuel and
Amine CO2 capture technologies are comparable with variation of approximately
1% point.
3.
For the project main design coal C1:Sub-bituminous, the optimized Oxyfuel CO2
capture power plant C1-A1 thermal efficiency is approximately 1% point higher
than that of the Amine CO2 capture power plant C1-B1 option.
4.
Compared to the optimised Oxyfuel CO2 capture power plant C1-A1, C1-A2 as a
retrofit from the non-capture ready C1-R0 reference, retains the SCR and FGD
plants and full air-firing capability, with thermal efficiency comparable to that of
Amine Scrubbing case C1-B1.
5.
For C2:Bituminous cases, the power plant thermal efficiency for Oxyfuel and
Amine Scrubbing CO2 capture option are comparable, with similar efficiency
penalty of approximately 8.5~8.8% points (HHV).
6.
For C3:Lignite cases, the power plant thermal efficiency penalty for Oxyfuel is
approximately 8% points, which is approximately 1% point less than that of
Amine Scrubbing option.
Economics:
7.
The levelised CO2 capture cost and electricity cost are very much comparable
between the Oxyfuel CO2 capture option C1-A1 and the Amine Scrubbing CO2
capture option C1-B1.
8.
The Oxyfuel CO2 capture option C1-A1 has marginably higher thermal efficiency
and lower levelised cost than the Amine Scrubbing option.
9.
For the main design coal C1: sub-bituminous, the Oxyfuel CO2 capture option is
estimated 10% higher in CAPEX but 20% lower in OPEX than that of an Amine
Scrubbing CO2 capture option, approximately 30 ~ 40% higher in CAPEX than
the reference power plant without CO2 capture.
xi
10.
As a retrofit option, C1-A2 has substantially 33% higher levelised CO2 capture
cost than the Amine Scrubbing C1-B2 option which is marginably higher than that
of C1-B1 new-build option.
xii
Overall:
•
This Project BERR-366 has established Advanced supercritical power plant steam
conditions and net plant output suitable for CO2 Capture Power Plant application
in Canada.
•
Established overall CO2 Capture Power Plant designs and process integration built
on knowledge and experience of proven conventional air/PF firing power plants.
ƒ
Developed conceptual designs and layout for new-build CO2 Capture and CO2
Capture-retrofit PF-fired advanced supercritical power plant based on both Amine
Scrubbing and Oxyfuel CO2 Capture technology, targeting near-term Market, on
proven technology for minimum risk.
•
Established the sensitivity to technical performance of the CO2 capture
technology considered for three different Canadian coal/sites.
•
CO2 Capture and CO2 Capture-ready Power Plant emissions and waste streams
are within the agreed Project BERR-366 design targets.
•
Confirmed technically feasible to “retrofit” carbon capture technology to a coalfired power plant using either Oxyfuel technology or Amine Scrubbing technology
•
Achieved Capture plant performance with CO2 emissions capture level up to 90%.
•
Optimised plant performance through process integration with consideration of
practical plant flexibility and reliability, availability and maintainability.
•
Identified and addressed key specific issues relating to:−
Essential requirements and considerations for Capture-ready Plant
−
CO2 capture plant energy penalty and steam cycle matching
−
CO2 capture rate
−
Waste streams/emissions performance
−
Capture Plant utilities and cooling water requirements
−
Capture Plant footprint/layout requirements
−
Safety and operability
xiii
GLOSSARY
Advanced SuperCritical.
ASC
Best Available Control Technology.
BACT
Department for Business, Enterprise and Regulatory Reform (UK)
BERR
Canadian Dollar, currency used for economic analysis.
CA$
Canadian Clean Power Coalition.
CCPC
Canadian Electricity Association.
CEA
Canadian Environmental Protection Act.
CEPA
Capital Recovery Factor
Current Dollars
Current Levelization
Factor
DCC
Mercury Removal
DeHg
NOx Removal
DeNOx
SOx Removal
DeSOx
Department of Trade and Industry (UK).
DTI
Enhanced Oil Recovery.
EOR
Electrostatic Precipitators.
ESP
Escalation Rate
Engineering and Home
Office Overhead
Fixed Operation and
Maintenance Costs
HARP
HHV
Engineering and office fees associated with electric utility projects.
Flue Gas Desulphurization.
FGD
GHG
Percentage increase in the price of construction components as time progresses.
Flue Gas Conditioning.
FGC
GGH
Factor that transforms a series of escalating costs into a series of uniform costs. It is the
product of the capital recovery factor and the present worth of an escalating series factor. It
is in current dollars, because it uses the after tax discount rate.
Direct Contact Cooler.
Double Contact Flow Scrubber.
DCFS
General
Capital
Factor that converts an initial investment into an annual rate, using the after tax discount
rate and system life time. Also known as the annuity factor.
Costs that include inflation.
Facilities
Costs associated with staff and materials used during operation and maintenance.
Total construction cost of the general facilities including roads, office buildings, and
laboratories.
Gas-Gas Heat Exchanger.
Green House Gas
Heater Above Reheat Point
Higher Heating Value
xiv
High Pressure
HP
High Pressure Turbine
HPT
Interest During Construction. Compound interest on borrowed money over the construction
period. Also known as Allowance for Funds Used During Construction (AFUDC).
Intermediate Pressure
IDC
IP
Intermediate Pressure Turbine
IPT
Lower Heating Value
LHV
Low Pressure
LP
Low Pressure Turbine
LPT
Limestone Forced Oxidation.
LSFO
Mitsubishi Heavy Industries.
MHI
Nitrogen Oxide and Nitrogen Dioxide (NO and NO2).
NOx
Nitrogen Oxides
Process Contingencies
Process
Capital
Facilities
Project Contingencies
PP
RPP
Return on Debt
Return on Equity
RPP
SCR
SNCR
SO2
SOx
TCE
TCR
TPC
TPI
Variable Operating and
Maintenance Costs
Consists of nitric oxide (NO) and nitrogen dioxide (NO2) and are reported as NOx and NO2
mass basis.
Contingencies to cover the uncertainty of the technical performance of newer technologies.
Total construction cost of all on-site processing equipment including all direct and indirect
construction costs and related sales taxes and shipping costs.
Contingencies to cover the uncertainty in the cost estimate.
Power Plant.
Reference Power Plant, the individual plants selected to represent plants burning
on the three types of coal: eastern bituminous, lignite, western sub bituminous.
Cost associated with interest on debt.
Cost associated with return to utility shareholders.
Reference Power Plant.
Selective Catalytic Reduction.
Selective Non-Catalytic Reduction.
Sulphur Dioxide.
Gaseous sulphur dioxide (SO2) for which national and provincial air quality objectives and
regulations have been promulgated. In some cases, emissions may contain small amounts
of sulphur trioxide (SO3) and sulphurous and sulphuric acid vapour. However, particulate or
aerosol sulphate is excluded from emissions totals and is included under particulate
matter. Sulphur oxides are expressed as sulphur dioxides (mass basis).
Total Cash Expended. Capital expenditures escalated to the time in the future where the
cost is incurred.
Total Capital Requirement, which is equal to Total Plant Investment (TPI) plus Owner’s
Costs.
Total Plant Cost. Sum of the process facilities capital adjusted with the retrofit factor,
general facilities capital, engineering and home office overhead, and contingencies. It is in
current dollars.
Total Plant Investment. The sum of the total cash expended and the interest during
construction paid on capital expenditures.
Costs associated with reagent and utility usage, as well as by-product credits and waste
disposal costs.
xv
TABLE OF CONTENTS
EXECUTIVE SUMMARY
V
GLOSSARY
14
1. INTRODUCTION
1.1
1
BACKGROUND
1
2. MARKET REVIEW
2.1
3
KEY DRIVERS AND ASSUMPTIONS
3
2.1.1
Environmental Legislation
3
2.1.2
Industry Model
3
2.2
CO2 LEGISTRATION AND REGULATORY FRAMEWORK
3
2.3
ELECTRICITY INDUSTRY ANALYSIS – BY PROVINCE
3
2.3.1
Alberta
3
2.3.2
British Columbia
3
2.3.3
Ontario
4
2.3.4
Manitoba
4
2.3.5
Saskatchewan
4
2.3.6
The Territories – Nunavut, Yukon and Northwest Territories
4
2.3.7
Prince Edward Island (P. E. I.)
4
2.3.8
Nova Scotia
5
2.3.9
Newfoundland and Labrador
5
2.3.10 New Brunswick
5
2.3.11 Quebec
5
2.4
GENERAL CONCLUSION
6
2.5
RECOMMENDATIONS
6
3. DESIGN BASIS AND GROUND RULES
3.1
3.2
7
BASIS FOR TECHNICAL ANALYSIS
7
3.1.1
Basic Site Conditions
7
3.1.2
Emission Targets
7
3.1.3
Final CO2 Product Stream Specifications
7
3.1.4
Design Fuels
8
3.1.5
Steam Cycle Parameters
9
BASIS FOR ECONOMIC ANALYSIS
9
3.2.1
Capital Costs
9
3.2.2
Curency and Conversions
9
3.2.3
Cost of Services and Utilities
10
3.2.4
Investment Costs
10
3.2.5
Operation and Maintenance Costs
10
3.2.6
Construction Time
10
xvi
3.2.7
Electricity Sales Income
11
3.2.8
Interest Rate
11
3.2.9
Inflation Rate
11
3.2.10 Equity Rate
11
3.2.11 Corporate and Emission Tax Rate
11
3.2.12 Price Basis (year)
11
3.2.13 Depreciation
11
4. POWER PLANT OPTIONS OVERVIEW
4.1
4.2
4.3
13
REFERENCE POWER PLANTS
13
4.1.1
13
Option R0: Reference ASC PF Air-fired Power Plants
ASC PP WITH OXYFUEL CO2 CAPTURE OPTIONS
14
4.2.1
Option A1 : ASC PF Oxyfuel CO2 Capture Power Plant
16
4.2.2
Option A2 : ASC PF Oxyfuel CO2 Capture Retrofit Power Plant C1-A2
18
ASC PP WITH AMINE SCRUBBING CO2 CAPTURE OPTIONS
20
4.3.1
Option B1 : Amine Scrubbing CO2 Capture Power Plant Concept
20
4.3.2
Option B2: ASC Amine CO2 Capture Retrofit Power Plant : for C1
22
5. ASC PF-FIRED POWER PLANTS WITH CO2 CAPTURE OPTIONS
5.1
5.2
5.3
5.4
5.5
23
GENERAL POWER PLANT SITE ARRANGEMENT
23
5.1.1
Reference Power Plant Site Layouts
23
5.1.2
Oxyfuel CO2 Capture Power Plant Layout
25
5.1.3
Post-Combustion Amine Scrubbing CO2 Capture Plant Site Layouts
28
STEAM TURBINE ISLAND (UNIT 700)
31
5.2.1
Summary
31
5.2.2
Aero-Thermal Design
31
5.2.3
Turbine Plant Configuration
45
5.2.4
Modifications Relative to C1-R0 Plant.
74
BOILER ISLAND (UNIT 200)
76
5.3.1
Air/PF-Fired Boiler Island Process Descriptions
76
5.3.2
Oxyfuel Boiler Island Process Descriptions
79
5.3.3
Furnace Design
83
5.3.4
Boiler Design
87
5.3.5
Ancillaries of the Boiler Island
89
AMINE SCRUBBER CO2 CAPTURE PLANT (UNIT 800)
93
5.4.1
General Process Descriptions
93
5.4.2
Design Performance and Features
98
5.4.3
Conceptual Layout of the CO2 Recovery Plant
99
CO2 COMPRESSION PLANT (UNIT 900)
101
5.5.1
General Process and Control Description
101
5.5.2
Control, Start-up and Shut-Down Philosophy
105
xvii
5.5.3
5.6
5.7
5.8
5.9
Design Performance and Features
AIR SEPARATION UNIT (UNIT 1100)
106
5.6.1
ASU Process Description
106
5.6.2
Principle of Cryogenic Air Separation
109
5.7.3
Oxygen Injection System
112
5.6.4
Oxygen Distribution to the Boiler
112
5.6.5
Safety & Operability
113
5.6.6
ASU Plant Process Control
114
5.6.7
ASU Ramping
118
5.6.8
ASU Start-up
118
5.6.9
Plant Flexibility
119
5.6.10 Plant General Layout
120
CO2 COMPRESSION AND PURIFICATION PLANT (UNIT 1200&1300)
124
5.7.1
CO2 Compression and Purification Plant Process Description
124
5.7.2
Safety and Operability
128
5.7.3
Plant Flexibility
128
5.7.4
Plant General Layout Plot
128
EMISSION CONTROLS
130
5.8.1
NOx Emission Control (Unit 300)
130
5.8.2
Mercury Removal (Unit 400)
133
5.8.3
Particulate Removal (Unit 500)
135
5.8.4
Flue Gas Desulphurization (FGD) System (Unit 600)
137
BALANCE OF POWER PLANT (UNIT 2000)
143
5.9.1
Coal and Ash Handling (UNIT 100)
143
5.9.2
Civil Works (Unit 2000)
153
5.9.3
Electrical Systems (Unit 2000)
157
5.9.4
Instrumentation and Control (Unit 2000)
159
5.9.5
Heat Rejection System (Unit 2000)
160
5.9.6
List of Major Equipment
166
5.10 PROJECT SCHEDULE
167
6. ECONOMIC ANALYSIS
6.1
6.2
106
169
PLANT CAPITAL COST
169
6.1.1
Basis of Estimate
169
6.1.2
Cost Estimates
170
6.1.3
Discussion Of Results
170
PLANT O&M COSTS
171
6.2.1
O&M Cost Parameters
172
6.2.2
Summary of O&M Costs
172
6.2.3
Solid and Liquid Wastes
172
xviii
6.3
ECONOMIC ANALYSIS
173
6.3.1
Economic Model
173
6.3.2
Economic Analysis Results
174
7. RECOMMENDATION FOR FUTURE R&D
177
8. CONCLUSIONS
183
8.1
TECHNICAL ANALYSIS RESULTS
183
8.2
ECONOMIC ANALYSIS RESULTS
192
8.3
CONCLUSIONS
194
ACKNOWLEDGMENT
197
REFERENCES
199
xix
1.
INTRODUCTION
1.1
BACKGROUND
The BERR Project 366 aims to investigate future CO2 capture technology options for
the Canadian market by evaluating the techno-economic feasibility of new-build
coal-fired power plants, utilising Advanced SuperCritical (ASC) boiler and steam
turbine technology together with consideration of oxyfuel and post-combustion CO2
capture technologies.
This project has been undertaken by a consortium including:
•
•
•
•
•
•
•
Doosan Babcock
Alstom Power
Air Products
Imperial College London
Canadian Clean Power Coalition (CCPC)
Neill & Gunter
Mitsubishi Heavy Industries (MHI)
UK
UK
UK
UK
Canada
Canada
Japan
The project activities co-ordinated by Doosan Babcock are organised into seven
tasks led by an Task Leader assigned as follows:Task 1: Market Review of ASC CO2 Capture Market Scenarios (CCPC)
Task 2: Project Specification/Ground Rules (Doosan Babcock)
Task 3: Plant Design Considerations and Integration Issues (Imperial College London)
Task 4: Conceptual Designs of ASC CO2 Capture & Capture-ready Plants (Doosan
Babcock)
Task 5: Capital and O&M Costs & Economics (CCPC/NG)
Task 6: Recommendations for Future R&D and Future Collaboration (Doosan Babcock)
Task 7: Project Management and Reporting (Doosan Babcock)
This BERR 366 project orchestrates with the primary objective of the Canadian
Clean Power Coalition (CCPC) to develop a project to demonstrate currently
available and emerging technologies to control coal-fired power plant CO2 emission.
Within this project, the evaluation of the conceptual designs for the coal-fired
Advanced SuperCritical power plant with CO2 Capture and CO2 Capture Retrofit
options have been established for three different Canadian coals/sites, namely:• C1: Sub-bituminous/Keephills : TransAlta Power
• C2: Bituminous/Point Tupper : Nova Scotia Power
• C3: Lignite/Shand : SaskPower
The main coal/site for this study is C1: sub-bituminous for which techno-economic
assessment is carried out for each of the conceptual designs summarised as
follows:
• R0: an optimised air-fired Advanced SuperCritical (ASC) PF reference power
plant (RPP) with appropriate emissions control; without CO2 capture
• A1: an optimised oxygen-fired ASC PF boiler with oxyfuel CO2 capture
1
• A2: a retrofit of the base case R0 to oxyfuel CO2 capture (C1 only)
• B1: an optimised air-fired ASC PF boiler with post-combustion CO2 capture
• B2: a retrofit of the base case R0 to post-combustion CO2 capture (C1 only)
Within the BERR-366 project scope, the studies of C2 and C3 cases are limited to
technical evaluation of overall power plant performance. An overall agreed design
basis for this project is the utilisation of proven technologies where possible and
appropriate. The technologies employed in the power plant designs presented in
this final report are summaried below:
Boiler Island: Doosan Babcock’s two pass, single reheat, once-through, Advanced
Supercritical (ASC) POSIFLOWTM PF boiler technology.
Turbine Island: Alstom Power’s latest technology for supercritical steam turbines
and turbine island balance-of-plant.
ASU & CO2 Compression & Purification Plant: Air Products’ latest cryogenic
oxygen plant technology and CO2 compression and purification technology (for
Oxyfuel cases only).
Amine Scrubbing and CO2 Compression Plant: Mitsubishi Heavy Industries
(MHI) KS-1 Amine scrubbing CO2 removal technology (for Amine Scubbing cases
only).
Particulate Removal Plant: state-of-the-art technology in current market place.
DeNOx: state-of-the-art SCR technology in current market place.
DeHg: state-of-the-art mercury removal technology.
DeSOx: state-of-the-art FGD technology in current market place.
The ASC boiler/turbine technology level targets state-of-the-art steam turbine inlet
conditions of 290bara/600°C/620°C for the reference air-fired power plant and those
power plants with CO2 capture or CO2 capture retrofit.
A nominal output of approximately 400MWe (net) is the target size for an ASC CO2
capture power plant for this project. For convenience of benchmarking the various
CO2 capture technology options the design, performance and evaluation of each
power plant option are based on assuming the same fuel heat input rate as that of
the reference power plant case R0 which is of approximately 500MWe (net).
2
2.
Market Review
2.1
KEY DRIVERS AND ASSUMPTIONS
2.1.1 Environmental Legislation
Canada signed up to the Kyoto Protocol in December 2002 and now is trying to cut
its GHG emissions to 6% below 1990 levels. Canada has not yet released a
definitive plan on how it will approach its Kyoto commitment. The solution will likely
comprise several elements, namely: target setting and reinforcement through
regulatory and financial backstops; initiation of domestic and international permit
trading; cost shared strategic investments into renewable energy, clean coal
demonstration projects, and CO2 capture technology. The vital part of the approach
is a close cooperation between the Government, industry representatives, lobbying
groups and other stakeholders.
2.1.2 Industry Model
Currently, most of the Canadian electricity corporations are vertically integrated
monopolies, encompassing generation, transmission and distribution.
2.2
CO2 LEGISTRATION AND REGULATORY FRAMEWORK
On December 17, 2002, the Government of Canada announced that it has ratified
the Kyoto Protocol.
Negotiations are currently underway to determine the reductions required by the
Large Industrial Emitters group, which is composed of several industries, namely:
oil and gas firms, electricity generators, mining and heavy manufacturing.
2.3
ELECTRICITY INDUSTRY ANALYSIS – BY PROVINCE
2.3.1 Alberta
According to National Energy Board (NEB), in 1999 Alberta generated about 79% of
its electricity from coal, 15% from gas and the remainder from all other sources.
Alberta is leading the way in Canada’s quest to reach its Kyoto target. The province
has the country’s largest LFE group, and thus has a lot of interest to be the leader
and the trendsetter versus reactively complying with the future GHG legislation.
There is still tremendous potential for coal, and it is believed that coal and gas will
have an equal important share in the Alberta’s energy mix.
The CCPC and EPCOR have initiated a FEED study for a 400MWe IGCC plant with
CO2 capture. The Front End Engineering Design (FEED) study will be complete in
2009 and the plant could be constructed by 2015.
2.3.2 British Columbia
According to NEB, in 1999, British Columbia (BC) generated 90% of its electricity
from hydro resources with the remainder split between wood, wood waste and
natural gas.
3
In the 2006 call for proposals for generating capacity, BC Hydro has awarded
contracts for the supply of power from two coal-fired projects. As the province is
currently the second largest producer of coal in Canada and has over 23 billion tons
of coal reserves, it is now a fact that environmentally clean coal fired electricity
production technology coal will become an alternative to supplementing the existing
energy mix.
2.3.3 Ontario
The situation in Ontario is still unclear. The government’s commitment to phase out
coal plants in 2007 has been extended to 2009, and recently to 2015. The main
issue is the time required to install sufficient replacement capacity. As a result, the
opportunity for coal-fired power plants in Ontario is unknown.
2.3.4 Manitoba
Manitoba is abundant in hydro resources. 99% of the electricity consumed in
Manitoba is from hydro power plants. Manitoba also produces a surplus of hydrosourced energy, and exports about half of the electricity to Ontario, Saskatchewan
and the United States.
From the information above, it is believed that the opportunity for coal-fired power
plant in Manitoba is minimal. Manitoba has enough hydro resources to cover its
capacity needs.
2.3.5 Saskatchewan
Saskatchewan is the second largest oil producer and the third largest natural gas
and coal producer in Canada. The Saskatchewan Power Corporation (SaskPower),
the sole provider of electricity in the province, tends to be a relatively high-cost
supplier of electricity in Western Canada due to its low customer density, long
transmission distance to end-users, and minimal hydro resources.
Coal will remain a part of the generation mix in the province. SaskPower is actively
working on a clean coal plant with CO2 capture to be in operation by 2011.
2.3.6 The Territories – Nunavut, Yukon and Northwest Territories
The large land area and small populations in the Yukon Territory, Northwest
Territories and Nunavut (the Territories) have precluded the development of an
integrated electrical network. Yukon has the lowest electricity demand among all
jurisdictions, followed by Northwest. Instead of a centralized system, northern
Canada has a mixture of isolated small hydro plants, oil-fired turbines and internal
combustion plants located at northern communities and industrial developments.
Coal electricity generation in the Territories is considered unlikely.
2.3.7 Prince Edward Island (P.E.I.)
According to NEB, although Maritime Electric has sufficient capacity on the island to
meet P.E.I. electricity demand, it has been purchasing over 90 percent of its
electrical needs from New Brunswick Power via a 200MW submarine cable to offset
its high cost oil-fired generation.
It is strongly believed that at this moment, there is a limited opportunity for coal-fired
projects in Prince Edward Island. It mainly due to the small demand of electricity,
4
the long-term contract of transfers from New Brunswick, and the Renewable Energy
Strategy of the province.
2.3.8 Nova Scotia
Nova Scotia’s electrical energy mainly comes from coal-fired power plants, with
waterpower and oil-fired plants providing the rest. More than 90% of Nova Scotia’s
electrical energy comes from coal-fired power plants, with waterpower and oil-fired
plants providing the balance.
It is expected that coal will remain a significant factor in meeting electricity demand
in the future. Nova Scotia still depends largely on coal as a source of electricity. The
Provincial government has committed to reducing emissions associated with power
production (mercury, SOx and NOx). However, they also state: “Coal is the primary
fuel that generates Nova Scotia’s electricity and will be for many years to come”.
Therefore, it is strongly believed there will be many chances left for new coal-fired
generation project in Nova Scotia in the near future, to satisfy the demand.
2.3.9 Newfoundland and Labrador
Newfoundland and Labrador produce large amounts of hydro-electricity, and much
of it is exported. Most of the electricity used by residents of Newfoundland and
Labrador is produced from hydroelectricity, with a smaller but still significant amount
coming from burning fuel oil. It is expected that hydro and oil will remain the
significant factors in meeting electricity demand in the future. From current research
and according to the provincial energy strategy, the province does not intend to
establish any new coal-fired plants in the near future.
2.3.10
New Brunswick
New Brunswick (NB) has one of North America’s most diverse generating systems
and interconnected transmission networks. Electricity is generated at 15 facilities
using oil, uranium, water, coal, Orimulsion®, and diesel as fuel.
Between now and 2015, the additional electricity demand can be met by existing
hydro-electricity resources, new natural gas-fired generation which will further add
to the diversity of fuels used in NB power. New Brunswick has easy access to
natural gas since Maritimes & Northeast Pipeline, the transportation facility
delivering natural gas from the Sable Offshore Energy Project to markets in Atlantic
Canada and the Northeast United States.
It is estimated that in the near future coal generation will not increase its market
share because of the province’s commitment to regional set by New England and
Eastern Canadian Premiers Agreement in 2001 to a Climate Change Action Plan.
2.3.11
Quebec
Quebec boasts the largest water resources and hydropower in Canada, 97% of
electricity output in this province is from hydro. Electricity is now the leading form of
energy in Quebec, followed by oil and natural gas.
Quebec has the largest untapped hydro resources in Canada. Hydro remains the
preferred development approach for the producer and predominant thirst of
electricity can be satiated by this resource especially beyond 2011 in Quebec when
5
many hydro projects will be online to supply power. Understandably, coal-fired
generation project can hardly gain support in Quebec.
2.4
GENERAL CONCLUSION
In the market study report, CCPC have performed an extensive analysis of the
Canadian electricity industry and provided a forecast as to the electrical power
supply mix. CCPC have also attempted to predict the role of coal-fired generation
on the province-by-province basis. According to CCPC’s analysis, there is some
limited potential for new coal-fired plant construction, and better opportunities for
brown field retrofitting.
2.5
RECOMMENDATIONS
CCPC’s recommendations for short-term and long-term strategies are summarised
as follows:
Short-Term (2005-2010)
• Establish presence on the Canadian market as quickly as possible.
• Alberta and Nova Scotia are attractive entry points. The situation in the province
of Ontario remains unclear.
• SaskPower is actively working on a clean coal plant to be in operation by 2011.
• Apply for Federal funding to develop a brown-retrofit pilot project.
• Focus on marketing brown-field retrofit solutions.
• Together with other members of the industry, engage in actively marketing
clean-coal technology as a viable source of energy.
• Commission an independent benchmarking analysis of Company’s products
versus IGCC technology.
• Ameliorate the existing product offering to make it more competitive.
• Look into potential partnerships with local companies and organizations.
Long-Term (2010-2035)
• Focus on securing profitable maintenance and service contracts with the
existing client base.
6
3.
Design Basis and Ground Rules
The BERR-366 project design basis and ground rules for the three coal/site
conditions are summarised below. The power plant designs are governed by the
site conditions, fuel properties, emission control targets and the general operational
requirements.
3.1
BASIS FOR TECHNICAL ANALYSIS
3.1.1 Basic Site Conditions
The basic site conditions are summarised in Table 3.1-1. Both C1 and C3 cases are
of inland Greenfield site and as such feature heat rejection via natural draught
cooling tower, with condenser pressure at 4kPa. Case C2 is of coastal site hence
utilising seawater cooling for heat rejection, with condenser pressure at 2.6kPa.
Project Coal/Site Reference
C1:
Sub-bituminous
Site Location
C2:
Bituminous
C3:
Lignite
Inland
Coastal
Design Dry Bulb Temperature
°
C
1.9
6.1
Inland
2.8
Design Wet Bulb Temperature
°
C
18.6
20.3
20.9
Ambient Relative Humidity
%
60
60
60
Condenser Pressure
kPa
4.0
2.6
4.0
Table 3.1-1: Basic Site Conditions
3.1.2 Emission Targets
All power plant options were designed to meet the emission targets with appropriate
emission control technologies. The major emission target levels listed in Table 3.1-2
are based on what can be achieved using available emission control technologies,
and are much more stringent than current regulations in Canada.
Parameter
Units
Target Level
C1:
C2:
Sub-bituminous Bituminous
C3:
Lignite
Primary Targets
NOx
g/MWh (net)
50
50
50
SOx
g/MWh (net)
55
55
55
Particulates, PM10, PM2.5
g/MWh (net)
28
28
28
Mercury
mg/MWh (net)
3.5
3.0
5.5
Table 3.1-2: Emissions Targets
3.1.3 Final CO2 Product Stream Specifications
The final CO2 product specification assumptions are presented in Table 3.1-3. The
requirements on the CO2 quality are defined by the requirements from CO2
transport, storage, environmental regulations and the cost. There are generally no
strong technical barriers to provide high purity of captured CO2, however, high
purity requirements are likely to induce additional costs and energy requirements
resulting in a loss of power plant efficiency. The key issue is to economically reduce
the concentration of other compounds than CO2 in the captured stream to
acceptable levels for transport and storage and to meet given environmental and
legal requirements.
7
With respect to the CO2 specifications related to Enhanced Oil Recovery (EOR)
projects, the main objective is to increase the oil recovery from near exhausted oil
fields through injection of CO2. These specifications mainly address aspects on
transport of CO2 and effects on the oil extraction process (miscibility with oil). Many
of the specifications have been developed mainly through acceptance of the
existing compositions of the used CO2 sources, rather than by actual limits based
on technical or environmental aspects. Note that target values of SO2 and H2S in
the CO2 product stream were not specified by CCPC for this project since they have
no negative impact for EOR and there are no limits for SO2 and H2S other than
safety concerns.
With the project aim of developing cost efficient processes for CO2 capture, the
project power plant sites with CO2 capture should be designed with no more
cleaning of the captured CO2 stream than needed to reduce the concentration of
the impurities in the captured stream to acceptable levels for compression, transport
and storage. Ultimately, this will need to include consideration to meet given
environmental and legal requirements.
C1:
Sub-bituminous
Limit/Basis
C2:
Bituminous
EOR
Coal Bed Methane
C3:
Lignite
CO2 Disposal
Destination
CO2
EOR
≥95%
≥95%
≥95%
N2
≤4%
≤4%
≤4%
Hydrocarbons
≤5%
≤5%
≤5%
H2O
-40°C
-40°C
-40°C
O2
≤100ppmv
≤100ppmv
≤100ppmv
CO
≤0.1%
≤0.1%
≤0.1%
Glycol
0.174 m3/106 m3
0.174 m3/106 m3
0.174 m3/106 m3
Temperature
≤50 C
≤50 C
≤50 C
Pressure
13.8MPa
13.8MPa
13.8MPa
°
°
°
Table 3.1-3: Final CO2 Product Stream Specification
3.1.4 Design Fuels
Table 3.1-4 below summarises the fuel analysis for the three coal/site conditions.
C1:sub-bituminous coal is the main project design coal.
Design Coal
Fuel Analysis
Proximate
Ultimate
CV
Moisture
Ash
Volatile Matter
Fixed Carbon
C1:
C2:
Sub-bituminous
Bituminous
(%w/w, as received)
20.00
11.23
15.10
5.15
27.03
29.79
37.87
53.83
Moisture
Ash
Total Carbon
Hydrogen
Nitrogen
Oxygen
Sulphur
GCV (MJ/kg)
20.00
15.10
48.01
2.77
0.59
13.32
0.21
18.70
11.23
5.15
73.63
4.78
1.50
2.45
1.26
31.96
Table 3.1-4: Design Fuel Analysis
8
C3:
Lignite
33.54
13.46
24.39
28.61
33.54
13.46
39.58
2.57
0.67
9.7
0.49
14.96
3.1.5 Steam Cycle Parameters
The steam cycle parameters with state-of-the-art turbine inlet steam conditions are
based on single reheat with the condenser pressure as stated in Section 3.0. All
power plant options considered under this BERR-366 project are based on ASC
boiler/turbine technology level targeting the state-of-the-art steam turbine inlet
conditions of 290 bara/600°C (HP) and 620°C (IP). Turbine island feedwater train
utilises electrically driven feedwater pumps.
Overall plant performance is maximised through process integration of boiler island,
steam turbine island, balance of power plant and CO2 capture plant including,
where appropriate, low grade heat utilisation in the thermal cycle.
3.2
BASIS FOR ECONOMIC ANALYSIS
In order to be able to evaluate the economic influence of the different CO2 capture
technologies, the economic assumptions made for this project are divided into two
groups:
•
•
Cost related assumptions: investment costs, operation and maintenance
costs, fuel costs, construction time, allocation of investment.
Financial assumptions: interest rate, inflation rate, equity rate, corporate tax
rate, price basis, depreciation, duration of investment.
The cost related assumptions include all costs related to the power plant both
during construction and during operation.
In this project, it has been decided to use the net present value method based on
cash flow in real terms, using the above mentioned cost related and financial
assumptions.
The net present value cost is calculated into a break-even electricity price where the
influence of a reduced electricity output is taken into account. This method also
allows for taking into account additional costs for transport and storage of captured
CO2 or income from CO2, as delivered to Enhanced Oiler Recovery (EOR) or
Enhanced Gas Recovery (EGR) sites. Various levels of CO2 emission trading
values can also be taken into consideration.
Besides the net present value, the specific investment, the specific CO2 emission
and the specific CO2 emission avoidance costs are also calculated.
3.2.1 Capital Costs
The capital costs are estimated in Canadian Dollars based on Q4 2006 price.
3.2.2 Curency and Conversions
Unless otherwise specified all currency figures in the study are Canadian Dollars
specified as CA$. US dollars are specified as US$. The following currency
conversions were used in the project:
•
•
•
1.00 US$
1.00 €
1.00 ₤
= $1.15 CAN
= $1.5 CAN
= $ 2.20 CAN
9
3.2.3 Cost of Services and Utilities
The unit costs of various services and utilities for the main coal/site C1 are shown in
Table 3.2-1 below. Fuel costs traditionally vary within a factor of two over only a few
years. Fuel prices have a major impact on the results, sensitivity analyses with
respect to fuel prices have been considered as part of the economic evaluation.
Service and Utility Cost
Electricity : for start-up only
Natural Gas
Raw Water
Labour (including overhead and burden)
Alberta Sub-Bituminous coal
C1:
Sub-bituminous
(CA$/MWh)
(CA$/GJ)
(CA$/kgal)
(CA$/hr)
(CA$/GJ)
50
5.0
0.02
80
0.75
Table 3.2-1: Cost of Services and Utilities
3.2.4 Investment Costs
Investment costs include costs of all installations on the site to the fence (excluding
harbour and mining facilities but including coal yard for 30 days storage and coal
handling equipment). Total investment costs also include owner’s costs of planning,
designing and commissioning the plant and contingency.
The EPC price is determined for each reference power plant, and the owners’ costs
(including contingency) are added as a percentage of the EPC cost as follows:
•
Owners’ costs (including contingency) = 15% of EPC price for 500MWe (net)
RPP.
Investment costs are allocated to each year they are paid.
3.2.5 Operation and Maintenance Costs
Operation and maintenance costs (O&M costs) include all costs related to the
operation and maintenance of the plant during the whole plant life, such as:
•
•
•
•
•
•
Personnel
Administration
Spare parts
Overhaul
Consumables
Disposal
The O&M costs are divided into:
•
•
Fixed O&M costs (CA$/kWe per year)
Variable O&M costs (CA$/MWh gross)
Fixed O&M costs include costs of personnel, administration, spare parts and
overhaul.
Variable O&M costs include costs of consumables (e.g. water, limestone) and
disposal (e.g. ash, gypsum).
3.2.6 Construction Time
The construction times of the reference plants are assumed to be 60 months.
10
3.2.7 Electricity Sales Income
The net present value cost is used to calculate a break-even electricity price taking
into account the anticipated reduced electricity production.
3.2.8 Interest Rate
As the CO2 capture methods investigated are expected to be realised on a
commercial scale at the earliest in 2012 and the life of a plant is set to 30 years, an
estimate of the interest rate is consequently highly uncertain.
In this project, a combined interest rate is used taking into account equity rate,
inflation and required rate of equity, defined as a weighted average cost of capital =
8% with variations from 11 to 12%.
3.2.9 Inflation Rate
The inflation rate is assumed to be equal for all costs and income in the project life,
and is included in the real terms interest rate.
3.2.10
Equity Rate
As the objective of this study is to evaluate different CO2 capture methods, the
comparison is based on pre-tax and pre-equity payments. The equity rate is
consequently included in the average real term interest rate.
3.2.11
Corporate and Emission Tax Rate
Corporate and emission tax rate depends on the emission taxes on NOx and SO2.
As there are no common Canadian emission taxes, emission taxes are not included
in the calculations.
3.2.12
Price Basis (year)
Although none of the CO2 capture technologies included in this study are assumed
to be commercially available before 2012, all investment costs are based on the
price level of year 2006.
3.2.13
Depreciation
The comparison is based on pre-taxation payments, no depreciation calculations
are included in this study.
11
12
4.
Power Plant Options Overview
This section presents the configurations of the power plant options R0, B1, B2
as defined in Section 1.1. An outline description for each ASC power plant
option together with indicative block diagrams of the power plant concepts are
provided below. Note that within the scope of this BERR-366 project, R0, A1
and B1 power plant options are studied for all three coal/sites; whilst the A2
and B2 power plant retrofit options are only studied for C1 coal/site.
4.1
REFERENCE POWER PLANTS
4.1.1 Option R0: Reference ASC PF Air-fired Power Plants
Within this BERR-366 project the generic reference power plant (RPP) is
defined as an advanced supercritical air/PF-fired (ASC PF) power plant.
The RPP designs (ie C1-R0, C2-R0 & C3-R0) are based on state-of-the-art
boiler/turbine technology together with emission control plant including
DeNOx, particulate removal, DeHg, DeSOx plant. The RPP can be considered
as a conventional ASC air/PF power plant or as one which represents the
bare minimum requirement of a CO2 capture-ready power plant, namely:•
•
RPP as a conventional ASC air/PF-fired power plant only; without any
consideration for CO2 capture plant.
RPP as a capture-ready ASC air/PF-fired power plant; with consideration
for the minimum requirement for a capture-ready power plant; ie ensuring
sufficient space allocated on site for the future addition of CO2 capture
plant.
For each of the coals/sites considered the RPP case is used as the
benchmark within the project to allow the relative comparison of the new-build
post-combustion Amine scrubbing CO2 capture power plants for C1, C2 and
C3 coal/sites.
The schematic block diagram of a generic ASC PF RPP presented in Figure
4.1-1a applies to the C1 and C3 coals/sites on the basis of inland greenfield,
heat rejection and flue gas discharge via cooling towers (ie no flue stack).
13
Cooling
Water
Unit 700
Steam Turbine Island
HP
Steam
IP
Steam
Rotary
Airheater
Unit 2000
BoP,
Electrical,
I&C
FD Fan
Air
PA Fan
Cold
R/H
Unit 100 Coal
Coal & Ash
Handling
Feed
Water
Flue Gas
Unit 200
ASC Boiler
MILL
Unit 600
FGD & Handling
Plant
Unit 500
ESP
ID Fan
Cooling
Tower
Flyash
Bottom Ash
Unit 300
DeNOx Plant
Unit 400
DeHg Plant
Figure 4.1-1a: ASC Air/PF-fired Reference Power Plant for C1-R0 and C3-R0
Comparatively, the schematic block diagram presented in Figure 4.1-1b below
applies to C2 coal/site which is of coastal site, heat rejection by sea water
cooling and flue gas discharged via a dedicated flue stack.
Cooling
Sea Water
Unit 700
Steam Turbine Island
HP
Steam
IP
Steam
Rotary
Airheater
Unit 2000
BoP,
Electrical,
I&C
FD Fan
Cold
R/H
Unit 100
Coal & Ash
Handling
Air
PA Fan
Coal
MILL
Unit 200
ASC Boiler
Feed
Water
Flue Gas
Unit 500
ESP
Unit 600
FGD & Handling
Plant
ID Fan
Stack
Flyash
Bottom Ash
Unit 300
DeNOx Plant
Unit 400
DeHg Plant
Figure 4.1-1b: ASC Air/PF-fired Reference Power Plant for: C2-R0
The philosophy of the reference power plants’ arrangement is to maximise the
use of conventional plant equipment and layout with respect to milling plant,
regenerative preheaters, particulate removal plant (eg ESP) and emission
control equipment.
4.2
ASC PP WITH OXYFUEL CO2 CAPTURE OPTIONS
Oxyfuel combustion is based on combustion of PF using a mixture of oxygen
and recycled flue gas instead of using air. Due to the exclusion of N2 in the
combustion, the flue gases consist of mainly CO2 (~75%wt) and moisture
14
(~12%wt). The CO2 rich flue gases from the boiler are de-ashed by particulate
removal plant (e.g. ESP), cooled and moisture condensate removed as
condensate. Approximately 65 to 70% flue gas is recycled and mixed with
oxygen to form a primary flue gas recycle (PFGR) stream and a secondary
flue gas recycle (SFGR) stream which together support coal combustion in
furnace. Note that the PFGR and SFGR are equivalent to and operate in a
similar manner of the primary air (PA) and secondary air (SA) stream of an
air/PF-fired boiler. The balance of the total flue gas from the boiler is fed to a
CO2 purification & compression plant where the inerts and acids are removed
yielding purified CO2 that can be passed to storage.
With the current Canadian target for CO2 capture power plants to be in
operation by about 2012, it is envisaged that due to the relatively short
timescale such CO2 capture power plant designs will be based on proven
air/PF-fired technology wherever feasible and appropriate. Therefore within
this BERR-366 project, the ASC PF Oxyfuel CO2 capture power plant designs
have been based on maximising the application of current state-of-the-art
proven technologies. Within this project, in establishing the Oxyfuel CO2
capture power plant configurations the following aspects have been
considered:
•
Oxyfuel combustion system design to be based on air fired experience;
•
Power plant components to be based on proven technologies where
applicable and appropriate;
•
Build on air-fired boiler and power plant experience.
With respect to the three design coals as defined for the project, ie C1: subbituminous, C2: bituminous and C3: lignite, it is recognised that the
configuration / layout of the Oxyfuel CO2 capture power plant flue gas
components is influenced by coal quality, primarily the sulphur,chlorine and
moisture content. The key consideration relates to minimising or mitigating the
potential for both high- and low-temperature corrosion.
For an Oxyfuel boiler, compared to an air/PF-fired boiler, the exclusion of N2
replaced by CO2 enriched flue gas recycle (ie approximately 65% to 70% of
the main flue gas at boiler outlet), results in increased concentration levels of
sulphur and chloride components of flue gas, hence the potential for increased
acid corrosion of the boiler island components which are exposed to the flue
gases. Such considerations of the Oxyfuel boiler island has dictated the
preferred location for the flue gas recycletake-off point. Essentailly three basic
Oxyfuel power plant concepts have been established, utilising the most
appropriate air-like mill/burner/boiler configuration.
15
4.2.1 Option A1: ASC PF Oxyfuel CO2 Capture Power Plant
4.2.1.1
ASC PF Oxyfuel CO2 Capture Power Plant for C1-A1: Subbituminous
For the low sulphur coal C1:Sub-bituminous coal (ie 0.21%w/w S and 20%w/w
H2O), the indicative Oxyfuel CO2 Capture Power Plant configuration is shown
in Figure 4.2-1 below.
Heat to Steam Cycle
Unit 700
Steam Turbine Island
Cooling
Water
HP
Steam
IP
Steam
Unit 1100
Cryogenic ASU
Unit 2000
BoP, Electrical,
I&C
Start-up
air intake
Air
Start-up
PFGR Heat
Revovery
PFGR Fan
Cooling
Tower Vent
Unit 550
Start-up air intake
Cold
R/H
TAH
Feed
Water
SFGR Fan
Flue Gas
Unit 100 Coal
Coal & Ash
Handling
MILL
Unit 200
ASC Boiler
Tempering bypass
Unit 500
Particulate
Removal
Plant
Unit 550A
Heat
Recovery A
Unit 550B
Heat
Recovery B
Unit 650
DCC
Cooling &
Drying
ID Fan
Flyash
Unit 1200
Inerts Removal &
Unit 1300
CO2 Compresion
Bottom Ash
Figure 4.2-1: Case C1-A1: Oxyfuel CO2 Capture Plant Concept for C1:Sub-bituminous
Due to the ‘low sulphur’ content of the C1 coal, it was concluded that FGD
plant is not a necessary requirement for flue gas recycle (FGR) treatment as
far as the Boiler Island is concerned since SO2/SO3 levels will be comparable
to air-firing experience. Therefore instead of utilising a wet scrubber FGD plant
to clean and cool the flue gas, a flue gas Direct Contact Cooler (DCC) is
employed. The DCC plant ensures the necessary reduction in moisture
content and HCl content of the returning FGR stream meets the requirements
of the boiler plant. The exclusion of FGD plant will restrict plant operation to
oxyfuel mode as the plant will not be allowed to operate on air-firing unabated,
except for start-up and shutdown purposes.
Three flue gas heat recovery units are employed to maximise the cycle heat
integration. The PFGR stream is taken off at the ID fan outlet with the balance
of flue gas being fed to the downstream Unit 1200 & 1300 for CO2 purification
and compression during normal operation, or discharged through by-pass
ductwork to cooling towers during start-up/shut-down operation.
In order to minimise the oxygen cross-leakage in particular and also air inleakage, tubular airheaters (TAH) instead of rotary air heaters (RAH) are
employed.
4.2.1.2
ASC PF Oxyfuel CO2 Capture Power Plant for C2-A1: Bituminous
The project C2: Bituminous ‘coal’ is defined as a design coal blend of 80%
coal and 20% petcoke. This fuel blend results in a relatively high sulphur fuel
with relatively low moisture content (ie 1.26% S and 11.23% H2O).
16
The indicative Oxyfuel CO2 capture power plant configuration for this ‘high
sulphur’ fuel is shown in Figure 4.2-2 below.
Heat to Steam Cycle
Unit 700
Steam Turbine Island
Cooling
Water
HP
Steam
Unit 1100
Cryogenic
ASU
IP
Steam
Start-up
Air Intake
Air
Startup
Stack
O2
PFGR Heat
Revovery
Unit 2000
BoP,
Electrical,
I&C
PFGR Fan
Unit 550
Cold
R/H
Unit 100
Coal & Ash
Handling
Coal
MILL
Unit 200
ASC Boiler
Feed
Water
TAH
Flue Gas
FGD
GGH
SFGR Fan
Unit 500
Particulate
Removal
ID Fan
Unit 550A
Heat
recovery
Unit
600
FGD
Unit 1200
Inerts Removal &
Unit 1300
CO2 Compresion
Flyash
Bottom Ash
Figure 4.2-2: Case C2-A1: Oxyfuel CO2 Capture Plant Concept for C2: Bituminous
Unlike the C1-A1 configuration, the C2 coal sulphur content dictates the need
for a FGD plant to be employed to control SOx and HCl concentrations in the
furnace to acceptable levels that are comparable to those for air firing
experience. This is to ensure that there is no increased risk of high
temperature gas side acid corrosion during Oxyfuel firing. To achieve this both
the primary flue gas recycle (PFGR) and secondary flue gas recycle (SFGR)
stream take-offs are located downstream of the FGD plant to ensure the
PFGR and the SFGR streams are “clean” in terms of particulates and acidic
gaseous components. As with the C1-A1 case, a tubular airheater (TAH)
instead of rotary air heater (RAH) is employed.
4.2.1.3
ASC PF Oxyfuel CO2 Capture Power Plant for C3-A1
The C3-Lignite coal contains 0.49%w/w S and 33.5%w/w H2O, corresponding
a fairly low sulphur content fuel. However, due to the low fuel CV value, for
the same fuel heat input as per C1-R0 case, the C3-A1 fuel firing rate is
approximately 2.5 times that of C1-R0. Therefore while C3-A1’s SFGR stream
take-off point is the same as per C1-A1, the C3-A1 PFGR stream is required
to be cleaned by a FGD plant in order to reduce the risk of acid corrosion
within the furnace and boiler as to that of C2-A1.
However, compared to the C2-A1 configuration, due to the high moisture
content of the Lignite fuel, the C3-A1 design requires an additional DCC to be
employed downstream of the FGD to enable further flue gas drying. This in
order to satisfy the dryness requirements of the PFGR stream due to the
milling plant and further flue gas cooling to approximately 30°C as required by
the downstream CO2 compression plant.
The indicative Oxyfuel CO2 capture power plant configuration for C3: Lignite is
shown in Figure 4.2-3 below:
17
Heat to Steam Cycle
Unit 700
Steam Turbine Island
Cooling
Water
HP
Steam
IP
Steam
Unit 1100
Cryogenic ASU
Unit 2000
BoP, Electrical,
I&C
Start-up
air intake
Air
Start-up
PFGR Heat
Revovery
PFGR Fan
Cooling
Tower Vent
Unit 550
Start-up air intake
Cold
R/H
TAH
Feed
Water
SFGR Fan
Flue Gas
Unit 100 Coal
Coal & Ash
Handling
MILL
Unit 200
ASC Boiler
Tempering bypass
Unit 500
Particulate
Removal
Plant
Unit 550A
Heat
Recovery A
Unit 550B
Heat
Recovery B
Unit 600
FGD
Unit 650
DCC
ID Fan
Flyash
Unit 1200
Inerts Removal &
Unit 1300
CO2 Compresion
Bottom Ash
Figure 4.2-3: C3-A1: Oxyfuel CO2 Capture Plant Concept for C3: Lignite
With the secondary flue gas recycle (SFGR) take-off point upstream of the
FGD unit and the PFGR take-off from downstream of the DCC, this conceptual
arrangement allows acceptable SOx and HCl concentrations to be maintained
in the furnace ensuring no increased risk of high temperature gas side
corrosion for Oxyfuel firing compared with that for air firing. Also, the
requirement to ensure the PFGR stream is “clean” in terms of particulates and
acidic gaseous components.
4.2.1.4
Common Features of ‘Low’ & ‘High’ Sulphur Oxyfuel Power Plant
Concepts
The common key features of the ‘High Sulphur’ (C2 cases) and ‘Low Sulphur’
(C1 and C3 Cases) Oxyfuel power plant concepts are:
•
Air-firing for start-up and shut-down is only limited by allowable emissions.
•
DeNOx, DeHg not required within the Boiler Island;
•
FGD or DCC as appropriate sized only based on FGR requirement of the
Boiler;
•
DeNOx, DeHg, DeSOx to be handled by CO2 Compression and
Purification Plant.
For both Oxyfuel conceptual arrangements, the key areas for consideration of
process integration include flue gas heat recovery for condensate or feed
water heating and/or for integration with the Inerts Removal and CO2
Compression plant. The PFD philosophy for Option A1 aims at maximising
power plant performance.
4.2.2 Option A2: ASC PF Oxyfuel CO2 Capture Retrofit Power Plant C1A2
The concept of C1-A2 power plant option is based on an initial minimum captureready reference case C1-R0 which is subsequently retrofitted with the appropriate
Oxyfuel CO2 capture plant, as per Case C1-A1. For this project, Option A2 is only
investigated for the Sub-Bituminous (C1) coal. Figure 4.2-4 below shows the
indicative Oxyfuel CO2 capture-retrofitted power plant concept. The philosophy for
18
defining the C1-A2 power plant configuration is aimed at maximising the overall
power plant performance
Heat to Steam Cycle
Unit 700
Steam Turbine Island
Cooling
Water
Unit 1100
Cryogenic ASU
HP
Steam
IP
Steam
Start-up
Air Intake
Air
Startup
Cooling
Tower
O2
Unit 2000
BoP,
Electrical,
I&C
PFGR Fan
Cold
R/H
Unit 100
Coal
Coal & Ash
Handling
MILL
Unit 200
ASC Boiler
SFGR Fan
Feed
Water
RAH
Flue Gas
Unit 500
ESP
Unit 550A
Heat recovery
Unit 600
FGD
ID Fan
Unit 1200
Inerts Removal &
Unit 1300
CO2 Compression
Flyash
Bottom Ash
Terminal Boundary for Boiler Island
Unit 300
DeNOx Plant
Unit 400
DeHg Plant
Figure 4.2-4: Case C1-A2: ASC PF Oxyfuel CO2 Capture Retrofit Power Plant
C1: Sub-bituminous
The ASC boiler and turbine of Case C1-A2 power plant are similar to the
corresponding minimum capture-ready Case C1-R0, with the following major
considerations for conversion to Oxyfuel CO2 capture-retrofitted power plant:
•
Installation of:
- Flue Gas Recycle system
- Unit 550A: Main Flue Gas Heat Recovery down stream ESP
- Unit 1100: ASU Oxygen plant
- Unit 1200: Flue Gas Inerts Removal
- Unit 1300: CO2 Compression Plant
•
Process integration to ensure optimised power plant; especially with
respect to the steam turbine island and retrofitted oxyfuel CO2 capture
plant.
Retain and maximise the use of existing equipment and layout with respect
to the boiler plant, milling plant, air heaters and ESP, FGD, DeNOx, DeHg
plant and turbine island as appropriate. Note: the performance of any unit
plant retained from the RPP will need to be reconsidered for oxyfuel flue
gas.
•
The major differences in the conceptual power plant configuration between
Case C1-A2 (oxyfuel capture-retrofitted PP) and to that of Case C1-A1
(oxyfuel capture PP) are summarised below:-
19
Power Plant
C1-R0
C1-A1
Configuration Features
Air-fired
Oxyfuel
C1-A2
Oxyfuel retrofit of
C1-R0
SCR
Yes
No
Yes
DeHg
Yes
No
Yes
Air Heater: Rotary or Tubular
RAH
TAH
RAH
ESP
Cold
Hot
Hot
FGD
Yes
No
Yes
DCC (Direct Contact Cooler)
NA
Yes
No
Primary FGR take-off
NA
cold
cold
Secondary FGR take-off
NA
warm
cold
Primary FGR Heat Recovery
NA
yes
no
Main Flue Gas Heat Recovery
NA
yes
yes
O2 Injection location
NA
AH inlet
AH outlet
O2 preheating
NA
No
Yes
LP Steam required for O2 preheating
NA
No
Yes
Table 4.2-1 Power Plant Configuration Comparison for R0, A1 and A2 Options
•
•
•
•
4.3
The existing emission control equipment (ie DeNOx, DeHg, ESP, FGD)
of the RPP case C1-R0 power plant are retained.
Oxyfuel PFGR and SFGR is cleaned, cooled and reheated by FGD
plant as appropriate; instead of replacing the FGD plant with a DCC
plant.
Case C1-A2 boiler retains as per Case C1-R0 with minimum
modication, Oxyfuel combustion performance is expected to be poorer
than Case C1-A1 Boiler which is optimised for Oxyfuel firing.
All equipment retained from Case C1-R0, such as milling plant,
combustion system, fans, feedwater heating system airheater, and
emission control equipment, which are optimised for air-firing, will need
to be upgraded or modified accordingly to meet the requirements for
Oxyfuel firing operation.
ASC PP WITH AMINE SCRUBBING CO2 CAPTURE OPTIONS
4.3.1 Option B1: Amine Scrubbing CO2 Capture Power Plant Concept
Option B1 is defined as an ASC air/PF-fired power plant with CO2 Capture
utilising Amine Scrubbing and CO2 Compression Plant. The power plant
includes DeNOx DeHg, particulate removal and DeSOx as per the air/PF-fired
reference power plant R0.
The block diagram for the Option B1: Amine scrubbing CO2 capture power
plant concept is presented in Figure 4.3-1 (for C1-B1 & C3-B1) and Figure
4.3-2 (for C2-B1) respectively below:
20
CO2 Compressor Heat to Steam Cycle
Heat to Steam Cycle
Unit 700
Steam Turbine Island
Cooling
Water
LP Steam for Reboiler
IP
Steam
HP
Steam
Rotary
Airheater
Unit 2000
BoP,
Electrical,
I&C
FD Fan
Air
PA Fan
Cold
R/H
Feed
Water
Flue Gas
Unit 100 Coal
Coal & Ash
Handling
Unit 500
ESP
Unit 200
ASC Boiler
MILL
Unit 600
FGD & Handling
Plant
ID Fan
Unit 800
CO2 Amine
Scrubber
Unit 900
CO2
Compression
CO2 to
Storage/EOR
Flyash
Bottom Ash
Cooling
Tower
Unit 300
DeNOx Plant
Unit 400
DeHg Plant
Figure 4.3-1: ASC PF Amine CO2 Capture Power Plant: C1-B1 & C3-B1
CO2 Compressor Heat to Steam Cycle
Heat to Steam Cycle
Unit 700
Steam Turbine Island
Cooling
Sea Water
HP
Steam
LP Steam for Reboiler
IP
Steam
Rotary
Airheater
Unit 2000
BoP,
Electrical,
I&C
FD Fan
Air
PA Fan
Cold
R/H
Unit 100 Coal
Coal & Ash
Handling
MILL
Unit 200
ASC Boiler
Feed
Water
Flue Gas
Unit 500
ESP
Unit 600
FGD &
Handling
Plant
ID Fan
Unit 800
CO2 Amine
Scrubber
Flyash
Unit 900
CO2
Compression
CO2 to
Storage/EOR
Bottom Ash
Stack
Unit 300
DeNOx Plant
Unit 400
DeHg Plant
Figure 4.3-2: ASC PF Amine CO2 Capture Power Plant (C2-B1)
Compared to the R0 reference power plant, the majority of the power plant
components of the B1 are the same as per R0, except for the Turbine Island
(Unit 700), which is optimised for heat integration with the additional Unit 800
Amine Scrubber and Unit 900 CO2 compression plant. The process flow
philosophy for Option B1 aims at maximising power plant performance with
the following considerations:•
•
Plant arrangement: concept to maximise the use of conventional plant
technology, equipment and layout with respect to milling plant, burner,
regenerative preheaters and electrostatic precipitators;
DeHg and DeSOx (FGD) plant design to meet Unit 800 Amine
Scrubbing plant requirements;
21
•
Integration: Heat utilisation of the Unit 800 Amine Scrubbing, Unit 900
CO2 Compression with Unit 700 steam cycle condensate and
feedwater heating to maximise plant performance;
Steam Turbine optimised for steam extraction for the Unit 800 Amine
plant.
•
4.3.2 Option B2: ASC Amine CO2 Capture Retrofit Power Plant : for C1
Within the scope of work of BERR366 project, the B2 option is only studied for
the main design coal C1:sub-bituminous. Case C1-B2 plant is defined as a
retrofit plant of the C1-R0 PP using post-combustion Amine scrubbing CO2
capture technology as per Case C1-B1.
The block diagram of the B2 power plant concept is presented in Figure 4.3-3
below. The components indicated by a dashed line represent the retrofitted
unit plant components, which transform the capture-ready R0 plant to the B2
Amine CO2 capture-retrofitted power plant.
CO2 Compressor Heat to Steam Cycle
Heat to Steam Cycle
Unit 700
Steam Turbine Island
Cooling
Water
HP
Steam
LP Steam for Reboiler
IP
Steam
Rotary
Airheater
Unit 2000
BoP,
Electrical,
I&C
FD Fan
Retrofit
Components
Air
PA Fan
Cold
R/H
Unit 100 Coal
Coal & Ash
Handling
MILL
Unit 200
ASC Boiler
Feed
Water
Flue Gas
Unit 500
ESP
Unit 600
FGD &
Handling
Plant
ID Fan
Unit 800
CO2 Amine
Scrubber
Unit 900
CO2
Compression
Flyash
CO2 to
Storage/EOR
Bottom Ash
Cooling
Tower
Unit 300
DeNOx Plant
Unit 400
DeHg Plant
Figure 4.3-3: Case C1-B2: ASC PF Amine CO2 Capture Retrofit Power Plant
Comparing to C1-B1 case, as a retrofit from C1-R0, the majority of the power
plant components of C1-B2 are same as per C1-B1, with some differences
envisaged mainly within the turbine island as the following:
•
With Amine CO2 Capture retrofit, the steam turbine of Case R0 needs to
be modified to allow extraction of steam to Amine plant from IP/LP
crossover;
•
Condensate heating system to be modified to integrate heat recovery
from the Amine scrubber system;
•
Feed water heating system need to be modified to integrate heat recovery
from the Amine scrubber and CO2 Compression plant as appropriate;
•
FGD plant to be upgraded to meet Amine scrubbing requirements as
appropriate.
22
5.
ASC PF-fired Power Plants With CO2 Capture Options
The major power plant unit components utilised as appropriate in the various ASC
power plant configurations, with and without CO2 capture, considered within this
project together with the project unit ‘owner’, are summarised below :
•
Unit 100 :Coal & Ash Handling (NG/CCPC)
•
Unit 200 :Boiler Island (Doosan Babcock)
•
Unit 300 :DeNOx Plant (Doosan Babcock/NG/CCPC)
•
Unit 400: DeHg Plant (MHI for air/PF-fired cases, Air Products for oxyfuel
cases)
•
Unit 500 :Particulate Removal Plant (NG/CCPC)
•
Unit 550 :Main Flue Gas Heat Recovery (Doosan Babcock)
•
Unit 600: FGD & Handling Plant (MHI for air/PF-fired cases, NG/ for Oxyfuel cases)
•
Unit 650: Flue Gas Direct Contact Cooler (Oxyfuel cases only, Air Products)
•
Unit 700 :Steam Turbine Island including STI BoP (Alstom Power)
•
Unit 800 :CO2 Amine Scrubbing Plant (Amine CO2 capture cases only, MHI)
•
Unit 900 :CO2 Compression Plant for Amine CO2 Capture Plant (MHI)
•
Unit 1100 :Cryogenic Oxygen ASU (Oxyfuel cases, Air Products)
•
Unit 1200 :Inerts Removal CO2 Purification Plant (Oxyfuel cases, Air Products)
•
Unit 1300: CO2 Compression Plant for Oxyfuel cases (Air Products)
•
Unit 2000 :BoP, Civils, Electrical, I&C; excluding STI BoP Items (NG/CCPC)
Based on outline design specifications for each individual unit the design and
performance of each unit was undertaken by the appropriate unit ‘Owner’ as
indicated.
5.1
GENERAL POWER PLANT SITE ARRANGEMENT
5.1.1 Reference Power Plant Site Layouts
The conceptual plant layouts for each of the reference power plant (RPP), cases
C1-R0, C2-R0, and C3-R0 were planned using the criteria and guidelines listed
below. Accommodation of specific for retrofitted post-combustion CO2 capture were
not addressed in these layouts.
•
•
High pressure piping from the boiler to the turbine is minimized to reduce
friction and heat losses, as well as capital cost.
The material handling systems and the associated heavy truck traffic were
separated from the main plant area as much as possible. This limited potential
site congestion, dust and noise in the powerhouse area, and concentrated
material handling operations, improving expected material handling
efficiencies.
23
•
•
•
Coal and limestone deliveries and gypsum and ash removal are located where
possible at the outer plant boundary to provide good vehicle accessibility, and
allow sufficient space for material storage.
Material storage requirements, and conveyor configuration and redundancy
The distance from the FGD plant to the cooling tower, or stack was minimized
to reduce the duct capital costs. In the case of the C1 and C3 sites this resulted
in a large distance between the cooling tower and the turbine condenser, and
corresponding long Cooling Water pipelines.
The power block consists of two independent building assemblies. The first consists
of the Turbine Hall; with auxiliary bays for the boiler feed pumps, LP heater area,
and electrical annex. The second structure houses the coal mill bay, boiler house,
and air heater/SCR area. While the buildings are structurally independent, with fire
separation, they are physically joined to provide easy weather protected access
between them.
The layout of FGD plant separated the limestone preparation, absorber and waste
handling areas. A single building was provided sized to house these FGD functions
in one location.
Figure 5.1.1-1: General Site Arrangement for C1-R0 and C3-R0
24
Figure 5.1.1-2: General Site Arrangement for C2-R0
5.1.2 Oxyfuel CO2 Capture Power Plant Layout
A1: Oxyfuel CO2 Capture Power Plant Layout
The conceptual plant layout for the Oxyfuel CO2 capture power plants options
including three A1 cases (Oxyfuel CO2 Capture Plant) and one A2 case (Retrofitted
Oxyfuel Plant), were developed using the similar criteria and guidelines as per base
case reference plant layout listed above with the following additional considerations
specifically for Oxyfuel power plant layout:
•
The ASU block was located next to the Boiler House to limit the length of the
oxygen piping between the facilities.
•
The CO2 Compression plant was placed next to the Direct Contact Cooler
(DCC) and ID Fan to limit flue gas duct length, and close to the ASU to minimize
the duct length for recirculated CO2.
•
The cooling tower/stack was positioned between the DCC and CO2
Compression plant limiting overall “cool side” duct length.
Figures 5.1.2-1, 2 and 3 below present the C1-A1 Oxyfuel CO2 Capture Power
Plant Site layouts for C1-A1, C2-A1 and C3-A1 respectively.
25
Figure 5.1.2.1-1: C1-R0 ASC Air/PF-Fired Reference Power Plant Site Layout
(C1: Sub-bituminous/Keephills : TransAlta Power)
Figure 5.1.2-2: C1-A1 Oxyfuel CO2 Capture Power Plant Site Layout
(C1: Sub-bituminous/Keephills : TransAlta Power)
26
Figure 5.1.2-3: C2-A1 Oxyfuel CO2 Capture Power Plant Site Layout
(C2: Bituminous/Point Tupper : Nova Scotia Power)
Figure 5.1.2-4: C3-A1 Oxyfuel CO2 Capture Power Plant Site Layout
(C3: Lignite/Shand : SaskPower)
27
A2: Oxyfuel CO2 Capture Retrofit Power Plant Site Layout
Within this project, the A2 retrofit oxyfuel CO2 capture technology option has been
only considered for the main design coal C1. The C1-A2 plant layout (Figure 5.1.25) utilizes the C1-R0 site plan as is, reflecting the limitations of a retrofit situation.
While the A2 layout cannot be fully optimized for an Oxyfuel case, the criteria used
for the A1 layout was followed as close as possible.
•
In the A1 layout the ASU block is located next to the Boiler House to limit the
length of the oxygen piping between the facilities.
•
The major difference in layout between the A1 and A2 cases is the existing
positioning of the FGD plant and cooling tower/stack. This results in
increased duct lengths, often in corrosive conditions, to service the CO2
compression plant and recirculation facilities.
Figure 5.1.2-5: C1-A2 Oxyfuel CO2 Capture Retrofit Power Plant Site Layout
(C1: Sub-bituminous/Keephills : TransAlta Power)
5.1.3 Post-Combustion Amine Scrubbing CO2 Capture Plant Site Layouts
The Amine Scrubbing based plant layouts for the three B1 cases (Post-Combustion
CO2 Capture Plants), and one B2 case (Retrofitted Post-Combustion Plant) were
planned using the base case criteria and guidelines,
B1: Post-Combustion CO2 Capture Plant Site Layouts
Similar to the R0 case, the R0 plant upstream of the precipitators remained largely
unchanged for the B1 amine scrubber plant. The downstream plant was also largely
28
rearranged to optimize duct lengths. The footprint for the amine based CO2 capture
plant followed a MHI plot plan. The plant is located on the opposite side of the
powerhouse as the material handling plant using the following criteria and
guidelines.
•
•
The distance from the FGD plant to the amine scrubbers was minimized to
reduce the duct capital costs. The retrofitted intake ducting tied into the existing
system between the FGD plant and the cooling tower/stack, with the discharge
duct returning the waste flue gas downstream of the intake, just before the
cooling tower/stack.
The CO2 compression plant was placed close to the turbine hall to limit the
steam piping between the two buildings, and as close as feasible to the amine
scrubbers to reduce the ducting and related costs between those facilities.
B2: Retrofitted Post Combustion CO2 Capture Layout
The B2 retrofitted plant layout starts with the C1-R0 site plan. The criteria noted for
B1 were also followed to optimize the B2 plant layout.
Figure 5.1.3-1: General Site Layout for C1-B1, C1-B2 and C3-B1
(C1: Sub-bituminous/Keephills : TransAlta Power)
(C3: Lignite/Shand : SaskPower)
29
Figure 5.1.3-2: General Site Layout for C2-B1
(C2: Bituminous/Point Tupper : Nova Scotia Power)
Figure 5.1.3-1: General Site Layout for C1-B2
(C1: Sub-bituminous/Keephills : TransAlta Power)
30
5.2
STEAM TURBINE ISLAND (UNIT 700)
Within the BERR-366 project, the steam turbine island design is based on Alstom
Power’s latest technology for supercritical steam turbines and turbine island
balance-of-plant.
5.2.1 Summary
Steam Turbine Island designs for Advanced Supercritical Boiler Plant, with and
without alternative CO2 capture methods, are evaluated for Thermo Economic
comparison.
CO2 is captured with both Cryogenic and Amine Scrubbing methods using Oxyfuel
Fired and Air Fired Boilers respectively.
Amine Scrubbing requires that approximately 50% of LP steam flow is extracted
from between the IP and LP Turbines in order to evaporate CO2 from Amine fluid
saturated with CO2 from the Flugas.
Performance sensitivity to C1:Sub-Bituminous, C2:Bituminous and C3:Lignite coals
associated with three different operating environments at Keephills (TransAlta),
Point Tupper (Nova Scotia Power) and Shand (SaskPower) respectively in Canada
is evaluated.
Optimised Design is compared to a Retrofit Derivative of Reference Plant for both
Cryogenic and Amine methods of capturing CO2 using Sub-Bituminous coal.
5.2.2 Aero-Thermal Design
5.2.2.1 Design Characteristics
5.2.2.1.1 Configuration Design
Configuration design cases are typical for Super Critical Steam Boiler plant with
single High Pressure and Intermediate Pressure Turbines connected in series to
parallel twin spool Low Pressure Steam Turbines.
High Pressure Turbine discharge is Reheated in the Boiler prior to entry into the
Intermediate Pressure Turbine to maximise efficiency and power output for the
given hardware arrangement.
Low Pressure Turbine flow discharges to a Condenser saturation pressure
compatible with heat removal with available cooling water temperature.
Condensate is re-circulated as Boiler Feed Water and is pre-heated to 300°C at a
pressure of 319bar by Turbine Steam extractions and Waste Heat Recovery prior to
entry into the SuperCritical Boiler.
Feed Water heaters operate at two different pressure levels upstream and
downstream of the De-Aerator. Low Pressure Feed water Heaters operate at 30bar
downstream of the Condenser and High pressure Feed water heaters deliver at
319bar to the Boiler.
31
Intermediate Pressure Turbine Inter-stage Bleed is extracted for De-Aeration of Low
pressure condensate.
Reheat Desuperheater spray is extracted from the high pressure feed water pump.
Turbine is designed to deliver power at 60Hz for this particular application and
performance is constrained by rotating blade mechanics.
Flow capacity, and therefore power, is limited by aerofoil root stress at temperature
for mechanical life and Low Pressure Turbine blade materials are typically made of
Titanium for last stage blade durability.
Mechanical constraints can degrade turbine aerodynamic efficiency if flow Mach no.
becomes too high for efficient blade aerodynamics with excessive volumetric flow
rate to avoid any cost increase due to an additional LP Turbine module.
Figure 5.2-1: Typical Supercritical Steam Turbine Configuration
5.2.2.1.2 Gross Turbine Performance
Turbine Gross Efficiency results shown in Figure 5.2-2 indicate that Oxyfuel Fired
cases are better than Amine cases largely due to abundance of Waste heat in the
Oxyfuel Fired cases and the penalty of Steam extraction from the IPT/LPT interface
for Amine Re-boiling.
32
Figure 5.2-2: Turbine Gross Efficiency comparison
Gross Power output comparison shows that again Oxyfuel Firing cases are better
than Amine capture cases.
Figure 5.2-3 below shows the contributions made by HP IP and LP Turbines for all
the cases. Amine capture cases reflect the reduction of mass flow entering the LP
Turbine due to Amine Re-boiler Off-take (45%). IP Turbine increased power for
Amine cases reflects the strategy adopted for matching the Retrofit LP Turbine
Non-Dimensional design point to match swallowing capacity.
Figure 5.2-3: Turbine Gross Power contributions
5.2.2.1.3 Feed Water Heating
Figure 5.2-4 below illustrates the inherently greater utilisation of waste heat for
Feed Water heating in Oxyfuel Fired Configurations derived from CO2 compression
and the Air Separation Unit and contributing to improved performance.
33
Figure 5.2-4 Waste Heat Recovery comparison
Figure 5.2-5 below shows the distribution of HP, IP and LP Turbine Bleed
extractions for Feed Water heating. Oxy Fired cases exhibit the most reduction of
Bleed extraction due to the inherently greater potential for Waste Heat Recovery
from the other parts of the Plant.
Figure 5.2-5 Turbine Bleed Extractions for Feed Water Heating
5.2.2.1.4 Turbine Performance
Impact of configuration design on IP Turbine Adiabatic efficiency is shown in Figure
5.2-6 below. Most notable is performance of the Over-extracted Retrofit IP Turbine
C1-B2 (C1-R0 derivative).
34
Figure 5.2-6 IP Turbine Aerodynamic Performance
Figure 5.2-7 below illustrates the impact of configuration design on LP Turbine
Adiabatic efficiency. Most notable feature here is the impact of mechanical design
W. T.
. Turbine
constraints on LP Turbine adiabatic efficiency at high flow function
P
exit flow area is constrained by Turbine Aerofoil root stress and flow Mach is
increased above the optimum for max efficiency.
Alternative solution to this approach would be to increase the number of LP Turbine
modules to reduce the volumetric flow rate per Turbine and therefore reduce Mach
to improve performance at the expense of capital cost.
Figure 5.2-7 LP Turbine Aerodynamic Performance
5.2.2.1.5 Condenser Design
Figure 5.2-8 below illustrates the Boundary conditions adopted for the Condenser
design for each of the study cases. All labels relate to coal type for the design cases
except for the Retrofit cases C1-A2 and C1-B2 where the cycle is tuned to the mass
flow rate associated with the Reference case, C1-R0, hardware capacity.
35
LP Turbine is expanded to the Saturation curve in all cases and coolant exit
temperature difference is approximately constant. Coolant mass flow is therefore
determined by coolant temperature rise and LP Turbine exhaust mass flow for
condensation.
Figure 5.2-8 Condenser Design
Figure 5.2-9 below illustrates the variation of the relationship between Coolant
temperature rise and Coolant/Steam Flow ratio.
Figure 5.2-9 Condenser Cooling Flow
Figure 5.2-10 below illustrates the actual coolant mass flows associated with each
case.
36
Figure 5.2-10 Condenser Cooling Performance
5.2.2.2
Thermal Cycle Heat & and Mass Balance
Reference Power Plant
C1-R0: Figure 5.2-11 shows the Heat & Mass Balance Diagram for C1-R0. This
case represents the basis for each of the Retrofits for comparison to design cases
using Sub-Bituminous coal. Turbine module pressure distribution is designed to
facilitate Turbine module off-design performance when operating in a Retrofit
application for CO2 capture using Amine Scrubbing system which requires IPT/LPT
interface bleed without adverse effect on LP Turbine performance.
C2-R0: Figure 5.2-12 shows Heat & Mass Balance Diagram for C2-R0, the
Reference case utilising Bituminous coal. C2-R0 expands to lower Condenser
pressure than C1-R0 and the LP Turbine loses performance due to higher velocities
in flow area restricted by Turbine Blade mechanical life considerations. An extra LP
Turbine module would effectively reduce LP Turbine flow by one third and is worth
approximately 10MW, due to improved adiabatic efficiency, at the expense of
increased Turbine module capital cost.
C3-R0: Figure 5.2-13 shows Heat & Mass Balance diagram for C3-R0 utilising
Lignite coal. Design is very similar to C1-R0.
Oxyfuel CO2 Capture Power Plant
C1-A1: Heat Recovery integration optimised for maximum Heat Rate. Number of
Feed Water Heaters is reduced relative to Reference cases due to abundance of
Waste Heat available for recovery from the Air Separation Unit, Boiler Flue Gas
Recirculation, Inerts Removal and CO2 compression.
C2-A1: C2-A1 has lowest LP Turbine adiabatic efficiency due to minimum
Condenser Pressure constraint on LP Turbine expansion ratio. Flow-path velocity
37
increases towards Turbine exit due to Mechanical life constraints on LP Turbine
flow-path area.
C3-A1: Heat & Mass Balance for the Lignite design case is similar to the Subbituminous design case, C1-A1.
C1-A2: As the C1-R0 Retrofit for Oxy Firing, C1-A2 Condenser pressure has to be
increased relative to C1-A1 due to higher heat rejection with predetermined C1-R0
hardware cooling flow rate.
Amine Scrubbing CO2 Capture Power Plant
For C1-B1, C2-B1, and C3-B1, the heat & mass balance of water/steam cycle were
optimised to maximise the heat integration between the turbine island and Amine
Scrubber and CO2 compression plants.
IP Turbine is over-expanded to match the LP Turbine Non-Dimensional design
requirements with Amine Re-boiler Steam extraction.
Retrofit C1-B2 over-expanded IP Turbine mechanics have not been analysed since
that was considered to be beyond the scope of this project and would require
design action to provide mechanical integrity for Reference Plant IP Turbine if used
in a Retrofit mode.
38
Figure 5.2-11 C1-R0 Heat & Mass Balance Diagram
39
Figure 5.2-12 C2-R0 Heat & Mass Balance Diagram
40
Figure 5.2-13 C3-R0 Heat & Mass Balance Diagram
41
5.2.2.3 Amine Scrubbing Capture Plant
5.2.2.3.1 Design Approach
Amine capture relies on extraction of approximately 45% of turbine steam from IP
Turbine exit for Reboiling the Amine saturated with CO2 captured from the Flugas.
Figure 5.2-18 below shows Turbine mass flow distribution within the cycle as a
function of Cycle Pressure Ratio for Reference, Design and Retrofit case designs.
Figure 5.2-14 Turbine Flow Distribution for Amine CO2 Capture
Both design and retrofit configurations have been created to suit the extraction of
such a significant amount of flow.
Retrofit (C1-B2) is based on C1-R0 hardware which requires that flow extraction is
done in such a way as to preserve LP Turbine non-dimensional design parameters
as far as possible.
General principal of flow extraction, for the Retrofit (C1-B2), is to ensure that
resultant Expansion Ratio and LP Turbine entry/exit flow Mach are the same as C1R0 design.
This is achieved by over-extraction of the IP Turbine to a lower pressure and
W. T.
that maintains flow
temperature to be consistent with design flow function
P
Mach for the design flow area. Figure 5.2-19 below illustrates this concept and
shows Retrofit and Design relative to the Reference Turbine C1-R0.
42
Figure 5.2-15 Turbine Flow Function matching for Amine CO2 Capture
Impact of these changes on LP Turbine Stage Loading is illustrated in the Figure
5.2-20 below which shows the difference between Amine plant Turbines and Oxy
Fired / Reference plant Turbines in terms of Non dimensional work done; ΔH / Tin
(DHQT) and non-dimensional speed; RPM / Tin (NQRT).
These parameters relate to Turbine Stage Velocity Vector Triangles, in terms of
ΔH / (U ) 2 (DHQUSQ) and Axial Velocity/Blade Speed (VXQU), for fixed hardware
and rotational speed, indicating that the change to blade relative aerodynamics and
therefore performance is likely to be small.
Retrofit C1-B2 LP Turbine Stage Loading, ΔH / (U ) 2 (DHQUSQ) is effectively
reduced by approximately 13% due to the increase in Non-Dimensional speed,
RPM / Tin , due to over-expansion of the IP Turbine to a lower exit Temperature, to
achieve the design non-dimensional flow function
W. T.
at LP Turbine inlet/exit.
P
Flow velocities are also reduced for constant V / T (Mach) since temperatures in
the LP Turbine flow are reduced as a result of IP Turbine over expansion. This
translates into a reduction of Axial Velocity/Blade Speed (VXQU).
43
LP Turbine Design Loading
3
2.9
Nominal
DHQUSQ
2.8
DHQT
2.5
Stator
C1-B2
C1-B1
2.7
2.6
C2-B1
C2-R0
C3-B1
C1/C3-R0
C2-A1
C1-A1
C3-A1
C1-A2
Rotor
2.4
2.3
2.2
DHQUSQ
13% less
DHQNSQ
VXQU
2.1
2
160
Turbine Stage Vector Triangles
170
180
190
200
210
NQRT
Figure 5.2-16 LP Turbine Design Loading for Amine CO2 Capture
Figure 5.2-21 below illustrates the impact of IPT/LPT flow extraction and IP Turbine
over-expansion on cumulative work done by the turbines as a function of cycle
pressure ratio.
Amine capture LPT work done is approximately 50% of the Reference plant LP
Turbine due to the inherent flow reduction and IP Turbine over-expansion. This loss
is offset by the increased work done by the over expanded IP Turbine with 100%
flow.
Figure 5.2-17 Turbine Expansion Power for Amine CO2 Capture
44
220
5.2.3 Turbine Plant Configuration
5.2.3.1 Scope of Supply and Services (C1-R0)
General
The scope of equipment supply mainly comprises the items listed below, complete
with all necessary ancillary equipment such as:
−
−
−
−
−
−
−
−
−
−
−
−
−
equipment supports, base plates and anchor bolts,
piping, valves and fittings,
hangers, supports, drains and vents,
ductwork,
driving motors of pumps and actuator of valves,
equipment and piping heat insulation and material lagging,
final painting of equipment and piping,
equipment hoods for general protection and noise reduction as necessary,
power and control cables and cable routing systems only when attached to
equipment,
local instrumentation only,
control systems only as provided for local control of equipment,
functional labelling for plant items identification.
1 (one) 550 MW four module reheat steam turbine including:
Main components
− 1 single flow high pressure (HP) reaction turbine, welded drum type rotor,
horizontally split inner casing fitted with skrink rings, horizontally split outer
casing with bolted flange connection,
− 1 double flow intermediate pressure (IP) reaction turbine with welded drum type
rotor, inlet scroll, horizontally split inner and outer casings, all with bolted flange
connections,
− 2 double flow low pressure (LP) reaction turbine with welded drum type rotor,
inlet scroll, horizontally split inner and outer casings, all with bolted flange
connections,
− 2 live steam valve casings flanged to the HP-turbine outer casing, containing 1
stop valve and 1 control valve each,
− 2 intercept valve blocks flanged to the IP-turbine casing, containing 1 stop valve
and 1 control valve each,
− 1 shaft turning gear, AC motor driven, mounted on the thrust bearing pedestal,
Combined lube and control oil system
−
−
−
−
−
1 oil tank, common for lube oil and control oil, instrumentation and valving,
1 x 100 % main oil pump, turbine shaft driven,
1 x 100 % auxiliary lube oil pump, AC motor driven,
1 x 40 % emergency lube oil pump, DC motor driven,
jacking oil pump for each high loaded bearing, AC motor driven,
45
−
−
−
−
−
−
1 x 100 % oil vapour exhaust fan, AC motor driven,
2 x 100 % lube oil filters with manually operated change-over valves,
2 x 100 % lube oil coolers with manually operated change-over valves,
1 lube oil temperature control valve,
1 lube oil pressure control valve,
1 oil purifier system.
Control oil system
−
−
−
−
−
−
−
−
−
−
2 x 100 % control oil pumps, AC motor driven,
2 x 100 % control oil filters with manually operated change-over valves,
1 control oil pressure control valve,
1 control oil pressure accumulator.
Gland steam system
1 gland steam condenser with 1 x 100 % exhaust fan, AC motor driven,
1 pneumatically operated gland steam admission valve,
1 pneumatically operated gland steam pressure control valve,
1 pneumatically operated gland steam temperature control valve,
1 gland steam desuperheater.
Other auxiliary systems
−
−
−
−
1 electro-hydraulic safety system,
1 LP turbine exhaust spray system,
1 turbine internal drain system,
1 steam back flow protection system.
Accessories
− 1 thermal insulation for steam turbine,
− the turbine dry air preservation system.
− 1 (one) fully packaged generator with H2 cooling of the rotor and water cooling of
the stator windings including:
− neutral bar connection,
− the static excitation system with transformers and voltage control cubicle,
− generator synchronisation system,
− generator and transformer protection panel,
− the seal oil system including tank, gas exhauster, pumps,
− the hydrogen cooling system including heat exchangers,
− the hydrogen filling, removal and make-up system,
− the stator cooling water system including water/water exchanger, deioniser,
pumps and tanks,
− the hydrogen and carbon dioxide expansion and distribution.
5.2.3.1.1 Auxiliary steam distribution system
Pressure reducing device, header, piping and valves.
46
5.2.3.1.2 Condensing and feedwater heating system
− 1 (one) double-pass stainless steel twin tube bundle, underslung solid mounted
condenser, with its flexible joint,
− the condenser protection system,
− 2 x 100 % duty vacuum pumps of liquid ring type,
− 2 x 100 % duty condensate extraction pumps,
− 1 (one) feedwater storage and deaerator tank,
− 5 (five) horizontal LP heaters (LP1/LP2 duplex heaters located in condenser
necks) and 4 (four) horizontal HP heaters,
− the assisted check-valves on bled steam lines,
− 2 (two) identical duty variable speed drive feedwater pump sets comprising main
pump of barrel pull-out type and booster pump,
− the HP feedwater piping,
− the 50% LP bypass system (2 x 2 LP reducing valves with pneumatic actuator
and desuperheaters),
− the drain and condensate recovery system.
5.2.3.1.3 Main cooling system
− the continuous tube cleaning system,
− the auxiliary cooling water piping inside turbine hall
− Main CW pipework inside turbine hall
5.2.3.1.4 Condensate polishing system
− 2 x 50% filters,
− 3 x 50% mixed bed polisher vessels,
− resin trap,
− 2 effluents transfer pumps.
5.2.3.1.5 Condensate polishing regeneration station
−
−
−
−
−
Anion regeneration/separation vessel,
Cation regeneration/mid and hold vessel,
Separation/isolation vessel,
Regeneration pumps,
Air blowers,
− One set of acid and caustic dosing for regeneration and effluents neutralisation.
5.2.3.1.6 Chemical conditioning system
Storage tanks, dosing pumps, piping and valves for ammonia and hydrazine dosing
plus oxygen bottle racks and injection system.
47
5.2.3.1.7 Monitoring and sampling system
1 (one) complete monitoring and sampling system installed on a metallic frame in
the turbine hall (excepted for local monitoring instrumentation).
5.2.3.1.8 Typical Plant Arrangement
Refer to drawings below, which show a typical 500MW supercritical plant.
Figure 5.2-26 - RP 601 MB 03 --- GA 002
Figure 5.2-27 - RP 601 MB 03 --- GA 004
Figure 5.2-28 - RP 601 MB 03 --- GA 007
Figure 5.2-29 - RP 601 MB 03 --- GA 009
Figure 5.2-30 - RP 601 MB 03 --- GA 013
The overall configuration of the power block features the turbine building
perpendicular to the corresponding boiler. The referenced drawings are for a typical
unit. The exact scope may vary.
The turbine building, an independent steel-framed structure, houses the turbine
generator set and the mechanical auxiliaries. The auxiliary bay accommodates the
LP heater platform, the boiler feed pumps annex and the electrical annex dedicated
to the turbine hall. Each boiler feedwater pump is provided with its dedicated
handling crane for maintenance purpose. The feedwater tank is supported on a
steel structure above the motor-driven boiler feed pumps.
The turbine hall features a reserve passageway running its full length for under floor
routing of cables.
Each turbine hall is equipped with a travelling crane for the handling of heavy
components; only the generator stator requires handling with special apparatus.
The different floors are steel structures. The turbine hall is closed off by airtight
cladding and kept under slight overpressure to prevent ingress of dust.
48
Figure 5.2-26 Steam Turbine Hall Plan View 0.0m Level
49
Figure 5.2-27 Steam Turbine Hall Plan view 13.0m level
50
Figure 5.2-28 Steam Turbine Hall Longitudinal section in front of LP Casing and Condenser
51
Figure 5.2-29 Steam Turbine Hall Transversal Section in front of Heaters
52
Figure 5.2-30 Steam Turbine Hall Transversal Section through LP Casing
53
5.2.3.2 Turbine And Turbine Valves (Reference Case C1-R0)
5.2.3.2.1 High Pressure (HP) Turbine
The high-pressure (HP) turbine converts the thermal energy contained in the steam
into mechanical energy. This rotational energy finally is transformed into electric
energy by the turbogenerator. Coupled with further turbine modules, e.g.
intermediate-pressure (IP) or low-pressure (LP) turbines it constitutes a specific
turbine train.
After passing the stop and control valves the steam flows through the prolonged
valve diffuser to the inlet scrolls of the inner casing. Those scrolls are designed to
harmonize the steam flow up stream of the first blading row. In addition the first
stationary radial blade-row optimizes the steam flow for most efficient expansion.
After expansion through the axial blading the steam is exhausted via a nozzle at the
bottom of the turbine casing. A balance piston in front of blading is used to
compensate the axial thrust caused by the rotor blading.
The steam passes the main valves and is then fed directly into the blading path.
Prolonged valve diffusers connect the valves with the inner casing. After expansion
in the axial blading the steam is exhausted via a nozzle at the turbine casing lower
part.
5.2.3.2.1.1 Top Heater Extraction
The extraction point will be provided to take steam from the HP turbine for
feedwater heating. The steam will be extracted via a slot within the HP blading path.
A circular tube is used to lead the extracted steam out of the turbine casing.
5.2.3.2.2 Intermediate Pressure (LP) Turbine
The single-flow intermediate-pressure (IP) turbine converts the thermal energy
contained in the steam into mechanical energy. This rotational energy finally is
transformed into electric energy by the turbo generator. When coupled with
additional turbine modules, such as a high-pressure (HP) or low-pressure (LP)
turbines the configuration constitutes a specific turbine train.
After passing the stop and control valves, the steam flows through an intermediate
pipe to the inlet scrolls of the inner casing. These scrolls are designed to harmonize
the steam flow up stream of the first blading row. In addition, the first stationary
radial blade-row optimizes the steam flow for the most efficient expansion. After
expansion through the axial blading, the steam is exhausted via a nozzle at the top
of the turbine casing. A balance piston in front of the blading is used to compensate
the axial thrust caused by the rotor blading.
The inlet valve casings are connected to the IP-turbine via an intermediate pipe on
either side of the turbine.
54
5.2.3.2.3 Low Pressure (LP) Turbine
5.2.3.2.3.1 LP Turbine Module
The double-flow low-pressure (LP) turbine converts the thermal energy contained in
the steam into mechanical energy. This rotational energy finally is transformed into
electric energy by the turbogenerator. When coupled with additional turbine
modules, such as a high-pressure (HP) or intermediate-pressure (IP) turbines, it
constitutes a specific turbine train.
After passing through the crossover pipe, the steam enters the LP turbine inlet
section via an inlet scroll, which distributes the steam smoothly to both LP flows.
After expansion, the steam is exhausted downwards to the condenser.
The LP inlet section is designed with a 360° inlet scroll ensuring efficient and
harmonized steam flow to the blading. The first stationary blade row is radially
arranged and distributes the steam evenly to both LP flows.
5.2.3.2.3.2 Cross Over Pipe
The cross over pipe connects the Intermediate Pressure (IP) exhaust nozzle(s) with
the Low Pressure (LP) turbine(s).
The IP steam leaving IP turbine cylinder is led through the cross over pipe to the
inlet nozzle of the LP turbine(s).
The cross over pipe is of welded design made-off rolled steel plates. It will be
delivered with pre-manufactured sections that are finally welded together at site. A
compensator is applied in the vertical section downstream of the IP exhaust to
compensate thermal expansion. Fittings with bolted flanges are used to connect the
cross over pipe to the turbine cylinders.
5.2.3.2.4 Main Steam Valves
The stop valve immediately interrupts the steam flow into the turbine in case of a
turbine trip. The stop valve is an open / close valve. Its actuator is connected to the
turbine protection system. In case of a turbine trip, the pressure in the hydraulic
system drops and the stop valve will be closed. The closing time is 300 ms. Prior to
start-up, the turbine stop valve has to be opened by the protection system.
5.2.3.3 Steam Turbine Auxiliaries & Generator (Case C1-R0)
5.2.3.3.1 Steam Turbine Auxiliaries
5.2.3.3.1.1 General
This description gives an overview of the different steam turbine auxiliary systems
and the connections to each other.
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5.2.3.3.1.2 Lube oil and hydraulic oil system
Lube oil system
During normal operation, the entire lube oil flow is supplied by a shaft driven main
oil pump located in the front turbine pedestal. This self-priming pump takes the oil
from the lube oil tank. During runup, shutdown and turning gear operation the main
oil pump is supplemented by the AC motor driven auxiliary oil pump.
For cleaning the lube oil, a lube oil purifying unit is installed in a bypass
arrangement at the main oil tank.
Jacking oil system
The journal bearings of the turbine shaft are supplied with jacking oil. Jacking of the
rotor with highly pressurized oil during start-up and turning of the rotor prevents
metal contact between shaft and bearing. Thus, the coefficient of friction in the
bearings is largely reduced leading to a considerably lower torque to be produced
by the turning gear.
The jacking oil pumps are fed by the lube oil system with cooled and filtered oil.
Turning gear
Continuous rotation of the shaft with the turning gear generates adequate
ventilation which prevents temperature differences and thus deformation of the rotor
and the turbine casing.
Turning gear operation is required:
− prior to turbine start-up (from vacuum raising to run-up),
− during shutdown.
The turning gear mounted on the thrust bearing pedestal between the HP and IP
turbines consists mainly of the AC electric drive motor and the coupling-gear.
The operation of the turning gear is interlocked with the operation of the AC
auxiliary lube oil pump and the jacking oil pumps.
Hydraulic system of the turbine
Two AC motor driven screw type pumps mounted on the common hydraulic oil and
lube oil tank are provided for the hydraulic oil supply of the turbine. One of these
pre-selected pumps runs during normal operation and the second one serves as
standby. If the pressure in the hydraulic system decreases below 90 % of nominal
pressure, a pressure switch starts the second pump. The pressure switch can be
tested locally during operation by using a test valve.
A constant pressure valve keeps the hydraulic system pressure constant. The
output from the pump is passed through one of the 2 x 100 % capacity hydraulic oil
double filters into the hydraulic system of the turbine. This system serves to supply
the safety and control circuits of the turbine. Two accumulators compensate for
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short-time pressure drops which occur during pressure transients or following a
pump trip.
5.2.3.3.1.3 Gland steam system
Gland steam system function
The function of the gland steam system is to prevent both air ingress and steam
leakage from turbine casings and valves through shaft and spindle penetrations.
Gland steam system components
Gland steam suction circuit
The outermost sealing pockets of each turbine casing and valve spindle are
connected to the gland steam suction circuit. This system is maintained at a
pressure slightly below atmospheric by ventilating fans which draws the steam and
air mixture through the gland steam condenser where the steam condenses and the
remaining air is vented.
Gland steam sealing system
The sealing steam pressure controller maintains a pressure slightly above
atmospheric in this system. During normal operation the sealing system is self
sustaining with steam supplied from HP and IP turbine leakages. During standstill,
no-load and low-load operation of the turbine the leakage steam flowing from the
HP and IP sections into the gland steam system via the glands is insufficient to
maintain the desired sealing system pressure.
Gland steam relief system
The relief system is provided for the collection of higher pressure leakage steam
from the inner most sealing pockets of the HP turbine. The steam is discharged into
a feedheater bled steam line. The pressure in this system depends on the turbine
load.
5.2.3.3.2 Control and safety systems
The turbine control system is based on the electro-hydraulic principle, ie its control
functions are performed electronically and the servomotors of the various valves are
actuated hydraulically.
Control system of the turbine
Electro-hydraulic transducers
The control valve position controllers are designed to match the electrical control
signals with the appropriate electro-hydraulic transducers.
The output of these transducers is the hydraulic controlling variable, which is
proportional to the electrical controlling signal and actuates the pilot controls of the
corresponding control valve servomotors.
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The electro-hydraulic transducers are fed from the turbine safety system, ie when
the safety system is depressurized, the output of the transducer causes closure of
the control valves.
Live steam control valves
The live steam control valves are of the single seat type. They are operated by
hydraulic servomotors according to the "fail safe" principle, ie hydraulic pressure to
open - spring force to close. The electrical signal to the transducers is proportional
to the live steam control valve stroke. The stroke-dependent feedback is carried out
with a position transducer mounted in the servomotors.
The live steam control valves open sequentially with increasing of the electrical set
value of the electrohydraulic transducers. A linear relationship between electrical
set value and steam flow is performed in the turbine controller.
Intercept control valves
The intercept control valves are of the single-seat type. They are operated by
hydraulic servomotors according to the "fail safe" principle, ie hydraulic pressure to
open, spring force to close. The electrical signal to the transducers is proportional to
the intercept control valves stroke. The stroke-dependent feedback is carried out
with a position transducer mounted in the servomotors.
The intercept control valves open in parallel with increase of the electrical set value
of the electrohydraulic transducers. A linear relationship between electrical set
value and steam flow is performed in the turbine controller.
Connection with the turbine safety system
The pressure in the hydraulic safety system of the turbine is monitored by a
pressure transmitter. If the pressure in this system drops, the limit transmitter
immediately applies a reference input to the valve position controllers. This causes
the live steam and the intercept control valves to close.
5.2.3.3.3 GENERATOR
5.2.3.3.3.1 General
The purpose of the generator is to convert the mechanical power delivered from the
turbine to the rotor coupling into electrical power at the main generator terminals, in
the form of voltage and current. The generator is built to withstand not only normal
but also a wide range of abnormal operating conditions including e.g. negative
sequence loads and sudden short circuits.
The design described is of a two pole three phase synchronous turbo-generator
with hydrogen gas cooling of all internal components, except the stator winding and
its connections, which are cooled by water. All aspects of design and construction
will at least meet and often exceed the relevant requirements of the present
standards IEC 34, ANSI C50 and VDE 0530.
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5.2.3.3.3.2 Cooling
There are two main cooling circuits within the generator:
− direct gas cooling of field winding (rotor) and iron core,
− liquid cooling of the armature winding (stator), winding connections and terminal
bushings.
5.2.3.3.3.3 Cooling of stator core and rotor winding
The generator casing is filled with hydrogen gas to a pressure of several bar. This
gas, chosen for its favourable cooling properties, is circulated through the main
components by a single-stage radial-flow fan mounted on the non-driven end of the
rotor. This fan delivers cold gas to both end regions of the generator. The gas flows
axially through separate parallel paths in stator core, rotor winding and rotor endwinding/airgap to the mid-plane of the machine where it leaves through radial vents.
The now warm gas passes through the hydrogen-coolers prior to returning to the
fan through casing ducts. The water flow to the coolers is regulated to maintain a
constant cold gas temperature, normally in the range 40°C to 45°C, independent of
load or external conditions.
By virtue of the cold gas flow, the outside of the stator casing is overall cooled
uniformly.
2.2.3.3.3.4 Cooling of stator winding
The stator winding is cooled by deionised water, flowing in a closed circuit. The
water flows through all stator bars in parallel, entering and leaving the winding over
insulating teflon hoses and water manifolds. The overall temperature rise of the
water and the local temperature differences between conductors and water in the
bars are both very low, so that thermal expansion of the bars relative to the slot is
minimal.
2.2.3.3.3.5 Stator casing
The main part of the stator casing is a rigid fabricated steel cylinder which is
designed to:
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−
−
withstand the operating hydrogen pressure,
withstand the explosion pressure of a hydrogen-air mixture
prevent hydrogen leakage,
transmit steady-state and fault torques to the foundation,
support the weight of the stator core and absorb a large part of the core
vibration.
The casing contains gas ducts for the transport of cooling gas to various parts of the
generator. Flanges on the casing are supplied for attachment of:
− cooler casings to the sides,
− end shields which close the casing and house the hydrogen seals and
manholes,
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− the terminal box underneath at the slip ring end,
− stator water tank on the top.
5.2.3.3.3.6 Stator core
The stator core is built from low-loss silicon-alloy electrical sheet-steel stampings
which are deburred and given multiple coats of a highly heat-resistant, insulating
varnish on each side.
The core is maintained under permanent axial pressure by insulated tension-bolts
which pass through it from end to end. The load applied by these bolts is
distributed over each end of the core by press-plates. The high eddy current loss
densities associated with the traditional solid pressplates are drastically reduced in
the laminated pressplate, giving the following advantages:
− low losses and therefore a contribution to better efficiency,
− low pressplate temperature rise (due to the low loss density) and hence,
− no limitation on underexcited operation because of end-region heating ie the
power chart may be utilised right out to the stability limits.
5.2.3.3.3.7 Stator winding
The stator winding is the electrical heart of the generator. It is here that the
converted power emerges in electrical form as three-phase alternating voltage and
current.
The basic configuration of the winding is a two-layer lap with conical end-winding
structure sloped at 20° to the main axis.
The stator bars are mounted in equally sized, evenly spaced slots around the stator
bore. They are composed of many solid copper strands or subconductors. Each
subconductor is individually insulated with a very thin synthetic impregnated glass
tape, and the complete bundle is twisted along the entire length of the bar. This
configuration of conductor bar is known as the Roebel bar (invented by the
Company in 1912). It effectively reduces all parasitic losses (due to induced
circulating currents and eddy currents) to an entirely acceptable minimum.
5.2.3.3.3.8 Terminals
The ends of the stator winding are brought out of the generator at the terminal box
which is fixed to the underside of the stator casing near to the non-driven end. Each
end of each of the phase windings is brought out through gas-tight bushings, ie six
terminals in all.
The lower half of the terminal box is of non-magnetic steel of high electrical
resistivity, in order to minimize eddy-current losses in the walls near to the
conductors. The terminals and their connections from the winding are directly
cooled by demineralised water in parallel to the stator winding supply.
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5.2.3.3.3.9 Generator rotor
The rotor carries a D.C. field winding whose object is purely to set up a magnetic
field in the generator. This field which crosses the airgap between rotor and stator
serves two purposes:
− by virtue of its rotation with the rotor it induces the output voltage in the stator
winding,
− it acts as a medium for transferring (ie reacting) the torque (supplied to the driveend coupling by the turbine) from rotor to stator.
The stator currents (ie the electrical load) also affect the airgap magnetic field, and
the D.C. current to the field winding has to be varied to compensate this effect and
maintain terminal voltage.
The rotor body is a one-piece forging of heat-treated high permeability alloy steel.
Integrally forged couplings are supplied at each end, for attachment to the turbine
and of an extension shaft for the slip rings. The rotor body has no central bore.
To minimize double frequency vibration the design includes transverse slots in the
poles to equalize rotor bending stiffness in the direct and quadrature axis planes.
5.2.3.3.3.10 Shaft seals
In turbogenerators that are cooled by pressurized hydrogen, an oil seal is provided
around the shaft at the drive end and the non-drive end where the shaft passes
through the ends of the stator housing.
Each seal contains one ring placed around the shaft and having a certain clearance
from it. The ring is guided axially in the stator seal oil housing which is attached to
the generator front wall.
5.2.3.3.3.11 Stator cooling-water unit
In all higher rated turbogenerators ALSTOM use direct water-cooling of the stator
winding.
By virtue of its high specific heat-capacity and low viscosity, water is a highly
effective cooling agent. When thoroughly deionised, its insulating properties are
fully sufficient to allow its direct application to the winding conductors of
turbogenerators.
5.2.3.3.3.12 Gas unit
A standard gas unit is used for all ALSTOM hydrogen gas cooled generators.
All system components are mounted on a common skid and are connected by
pipework to the hydrogen supply line or bottle rack and to the generator.
The gas unit provides all the necessary facilities to fill and empty the generator of
hydrogen gas, and to maintain the required gas pressure and purity during normal
operation.
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The process of filling with hydrogen gas involves firstly displacing the air inside the
generator by carbon dioxide gas introduced from underneath. The gas unit includes
the CO2 evaporation module and distribution equipment.
The CO2 is then displaced by filling in hydrogen gas from above. This procedure,
using the inert CO2 gas, prevents the possible formation of explosive hydrogen-air
mixtures.
This procedure is applied in reverse sequence when the generator is emptied.
5.2.3.3.3.13 Sliprings and brushgear
The D.C. supply to the rotor winding is introduced to the rotor by brushgear and
sliprings.
The main components are:
− two steel sliprings with spiral grooved surfaces, shrunk on to an insulated
section of the slipring extension shaft,
− two corresponding sets of brushgear with individually removable brush-holders
which permit brushes to be changed quite easily and safely during full load
operation.
5.2.3.3.3.14 Generator excitation system
The synchronous generator is excited in the form of shunt excitation. The necessary
excitation power is taken from the generator terminals and is fed via the excitation
transformer and the controlled rectifier units to the rotor winding. The voltage
regulator contains digital elements. The automatic voltage regulator (AVR) controls
the thyristors via the gate control unit and the final stages in such a way that the
generator voltage is practically at a constant value between no-load and rated load.
The rectifier is a fully controlled three-phase bridge which allows reversing the field
voltage polarity during build-up as well as during reduction of the field current.
5.2.3.4 Mechanical Equipment (Case C1-R0)
5.2.3.4.1 Drain Recovery System
Will include a turbine flash box integrated within the condenser and composed of
two zones:
− a steam zone which receives turbine normal drains,
− a liquid zone which receives liquid and steam at low enthalpy.
Within the steam zones are installed spray nozzles working in parallel and each is
capable of a flow sufficient to bring the high temperature drains to a saturation
temperature. After the expansion, the water phase is fed to the condenser hotwell,
while the steam phase is fed to the condenser neck.
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5.2.3.4.1.1 Turbine low pressure by-pass system
The turbine IP/LP casing steam by-pass circuit is especially useful during transient
modes (e.g. start-up, tripping). It is intended to satisfy the thermal balance between
steam, boiler and turbine metal temperature (e.g. start-up).
Whatever the running mode of the power plant is (e.g. tripping, house load
operation), it allows recovery of steam to the condenser.
− start-up: due to the by-pass circuit, the boiler can operate to condition piping and
steam turbine prior to the turbine run-up, either from a cold or hot state,
− tripping: on tripping of the turbine-generator set, the by-pass circuit open
automatically. It allows the boiler to reduce load and then operate at its minimum
technical value ,
− house load: the by-pass system is sized to allow house load operation, with the
boiler at its coal technical minimum firing load.
Each LP by-pass system will include:
− the pipes for connection between the pressure reducing valves and the desuperheating system,
− one pressure reducing valve with pneumatic actuator, which also acts as the
isolating valve
− one de-superheating device with appropriate number of spray nozzles and the
water injection control valve,
− one pressure control and governing loop for the pressure reducing valve and desuperheating water injection valve control.
De-superheating water is injected downstream of the by-pass valve. Desuperheating water flow is regulated by a regulating valve on function of by pass
steam flow and enthalpy with correction of steam pressure measured between the
bypass valve and the downstream dump tube.
The de-superheated steam is dumped to the condenser by means of the dump
tube.
5.2.3.4.2 Condensing Systems
5.2.3.4.2.1 Condensation extraction and make-up
The condensation-extraction system processes all fluids, water and steam, from the
condensers through the condensate polishing plant, up to the inlet of the low
pressure heating system. It comprises:
− the two condensers with the normal and quick make-up water on-off valves,
− the balance pipe between the two condenser hotwells,
− two vertical condensate extraction pumps equipped with minimum flow
recirculating water pipe,
− two condenser level control valves,
− the piping network of condensate water up to the inlet of the low pressure
feedwater heating plant and miscellaneous make-up and de-superheating.
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Each condenser is designed with a large water reserve. A level control of the
indirect type ensures a high operating flexibility. The hotwell level is kept constant
by action on cage-type control valves located at the discharge of the condensate
pumps. The condenser make-up valve is controlled by the feedwater tank level.
Normal make-up is introduced through a spraying rack mounted above the bundles.
Quick make-up is directly to the hotwell.
Pumping is carried out by two vertical 100 % duty pumps, arranged for automatic
start.
The combined LP1/LP2 heaters are located in the exhaust neck.
Condenser is designed to condense the total bypass flow, corresponding to bypass
steam flow, plus de-superheating water, and to receive the drains flows.
The Condensate pump design flowrate is based on cycle design flow at TMCR
conditions with LP drains recovery pump out of operation and includes cycle losses,
drain tank de-superheating and turbine seal, plus 5 % margin
Condenser:
Each of the two condensers are designed to be supported on the concrete block
and comprise:
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1 steam turbine exhaust neck,
shell including the hotwell,
2 tube bundles with tube support plates,
tube sheets,
4 water-boxes with man access,
miscellaneous nozzles, make-up and drains dispersers,
inlet and outlet cooling water nozzles,
expansion below on the exhaust neck,
tube leakage detection device,
one flash box for drains returns (only for one condenser).
Steam dump diffuser
Support structure for the duplex LP1/LP2 heaters
The tube bundle pattern is a radiant-type tube bundle designed to:
− minimise the steam pressure drop,
− obtain approximately the same steam velocities in each lane between the tube
lobes.
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Condensate extraction pumps
The pumps are vertical, wet pit, can type. By installation in a suction can of
sufficient depth, the net positive suction head allows satisfactory operation. Vertical
construction requires a minimum of floor space.
The pump is driven by a constant speed, medium voltage, asynchronous motor
flanged on the pump head. The weight of the pump rotor together with the
generated thrust, is borne by a thrust bearing. The connection between the pump
and the motor is a flexible coupling.
5.2.3.4.2.2 Condenser tube cleaning system
The condenser tube cleaning system is provided to maximise the heat transfer
across the condenser by on-load cleaning of the internal surfaces of the tubes, thus
maintaining overall cycle efficiency.
For each CW pass, the cleaning system is composed of:
− the ball injector,
− the strainer section,
The recirculation unit is composed of:
− the ball recirculation pump,
− the ball collector,
− the automatic control panel.
The recirculation pump is a motor driven horizontal non-clogging unit specially
designed to recycle the balls without damage. The pump and motor are mounted on
a rigid base plate.
5.2.3.4.2.2 Condenser vacuum
The condenser vacuum system removes air and non-condensable gases from the
condenser to establish and maintain the required condenser vacuum at start-up and
during normal operation. The system also provides condenser vacuum breaking so
as to provide a turbine fast deceleration in case of tripping.
The condenser vacuum system consists of two 100 % duty motor-driven water ring
type vacuum pumps for the unit. At start-up, both pumps operate simultaneously for
quick vacuum build-up. In normal operation, one pump is in operation while the
other is on standby.
Each motor-driven vacuum pump set comprises:
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−
−
−
−
liquid ring vacuum pump connected to the electrical motor by a flexible coupling,
air/water discharge separator tank,
heat exchanger,
suction inlet valve with pneumatic actuator,
air discharge non return valve
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−
−
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−
water make-up system for air/water separator tank,
valves, piping and instrumentation air and water side,
marshalling box and all electric control connections,
common structural steel base plate.
The pump comprises:
− one casing,
− one rotor (two stages type),
− one suction and discharge casing.
5.2.3.4.3 Feedwater Heating And Deaerating Systems
5.2.3.4.3.1 LP and HP feedheating systems
LP heaters function is to increase condensate water temperature before entry into
the feedwater tank by using steam bled from the from IP and LP steam turbines.
LP heaters system includes five low pressure heater stages supplied with steam
from the IP/LP turbines. The first LP1 and LP2 heaters are arranged in the
condenser neck. LP3, LP4 and LP5 heaters are located in series outside of the
condenser. LP2 and LP4 are equipped with drain recovery pumps, which route
drains to the next heater inlet.
HP heaters function is to increase feedwater temperature before entry to the boiler
by using steam from IP and HP steam turbines. HP heaters system includes three
high pressure heater stages plus a topping heater. The single heaters are arranged
in series at feedwater pumps discharge. The topping heater acts as HP10 heating
stage and uses the high level of superheat in the IP turbine extraction to increase
the final feed temperature. An automatic by-pass is able to bypass HP7 and HP8
heaters and another one is able to bypass HP9 heater to route feedwater to the
boiler.
The heaters are thermally designed according to the values indicated in the TMCR
heat balance with a tube fouling factor according to HEI rules. The mechanical
design is made according to ASME Code and HEI Code.
The design flow rate of the drain recovery pumps is based on TMCR flow plus 15%
margin.
The low pressure feedwater heating system will include:
− five low pressure heaters,
− two drain recovery pumps,
− the steam extraction, ventilation, normal and emergency drain piping and the
condensate water piping from the condensate pump discharge up to the
feedwater tank inlet.
The feedwater side is composed of:
− the water box with a separating plate and inlet / outlet nozzles,
− the tube sheet welded on the water box,
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The steam side is composed of:
− the external part of the tubes, with condensing and drain cooling zones as
applicable,
− the shell, which is welded on the tube sheet, supports the steam and drain inlet
nozzles, the drain outlets, the venting nozzles with their headers and the various
accessories.
The high pressure feedwater heating system will include:
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four high pressure heaters,
the high pressure steam extractions,
the HP feedwater piping,
the normal and emergency drains,
the venting of the heaters.
Each heater is of the horizontal type with U- tubes.
The feedwater side is composed of:
− a water distribution manifold,
− the U-tubes welded on the manifold,
The steam side is composed of:
− the external part of the tubes, with condensing, de-superheating and drain
cooling zones as applicable,
− the shell, which is welded on the tube-sheet and which supports the steam and
drain inlet nozzles, the drain outlets, the venting plugs and headers and the
various accessories.
Internal plates or baffles are supporting the tubes in the condensing zones. The desuperheating and drain cooling zones are formed by boxes with internal baffles.
HP heaters, except HP10, include a drain cooling section of the full flow type.
5.2.3.4.3.2 Storage and deaerating system
The purpose of the feed water storage and deaerating system is:
− to ensure a water reserve in the feed water tank, as well as the heating and the
deaerating of this water,
− to serve as a feed water flow break tank between the condenser extraction
pumps and the feed water pumps,
− to provide the required suction head to the feed water pumps.
The water reserve is designed to protect the plant from tripping of condensate
extraction pump during a short period. It allows the operator to restart these pumps
without tripping the feed water pumps.
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The feed water storage and deaerating system consists of one deaerator and one
feed water tank. The feed water tank receives the condensate coming from the
deaerator and delivers the deaerated water to the HP pumps suction using two
separate pipes.
The feedwater tank useful capacity is the volume comprised between the normal
working level and the low low level (FWP trip level). It is represents five minutes
operation at full load.
The deaerator is designed to maintain the feed water oxygen content lower than
5 ppb for steam turbine thermal load greater than 50 %.
The deaerator is located above the storage tank and comprises heating and
deaerating devices.
The devices are in 3 parts:
− an upper stage in which the water is sprayed through a suitable number of
nozzles, heated, and partially deaerated,
− an intermediate stage with perforated trays, which completes the heating of the
water,
− a lower stage which completes the deaeration by bubbling steam through the
previously-heated water.
The storage tank comprises:
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one cylindrical shell and two elliptical ends,
piping for water distribution,
feed water outlets equipped with anti vortex devices,
supports cradles on a metal frame,
one overflow and one drain pipe,
various nozzles and manholes.
The deaerator has the following characteristics:
− the deaerating and storage functions are completely separated,
− the heating steam supplied to the deaerator is in equilibrium with the vapour
phase over the water surface of the storage tank; this avoids any risks of regassing,
− no bled steam or equivalent is injected into the stored water. Consequently the
risk of water return to the turbine is reduced.
5.2.3.4.3.3 HP feedwater pumping system
The main purpose of the feed water pumping system is to supply feed water from
the feed water tank to the boiler. It also supplies the HP by-pass de-superheating
device with feed water and the cold reheat steam attemperator via the pump
intermediate take-off.
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At low loads, the feedwater control system maintains the minimum flow required to
cool the water wall tubes. In once through operation mode the feed pump follows
boiler demand.
2 x 50 % feed water pumps are installed for each unit, two are in operation and one
pump is able to cater at least for 70 % of the load when the other pump is
unavailable.
Each feed water pump is designed to ensure 70 % of the boiler maximum
continuous rating at nominal pressure.
Each feed pump set comprises:
− a main multistage pump with suction filter, minimum flow protection and
intermediate take-off, driven through the gearbox,
− a speed increasing gear box between the variable speed electric drive and main
pump,
− a booster pump with suction filter,
− a variable speed electric drive.
The pump sets are provided with associated piping, including the necessary vent
and drain, and with lubrication and cooling systems. Each pump is protected at low
flow by means of an automatic re-circulation to the feedwater tank.
An intermediate take-off is provided on the main pump to ensure attemperation of
the cold reheat steam.
Feed water pump speed control is achieved by the variable speed electric drive
governed by the variable frequency system.
Booster pump
The booster pump is horizontal with single stage, double entry impeller, supplied
with its plain type and oil lubricated bearings and mechanical shaft seals. The
suction and discharge are vertical. The booster is direct driven by one of the two
motor ends shafts.
The booster is installed on a base plate with auxiliary pipes, suction filter and
instrumentation arrangement.
Feedwater pump
The pressure stage pump is of the horizontal centrifugal multi-stage barrel casing
design incorporating a replaceable ‘’pull out’’ inner cartridge/hydraulic element. The
barrel casing and the delivery cover are in forged carbon steel.
The moving parts consist of a shaft, on which the wheels are individually held in
rotation by means of keys. Each shaft end is supported by a bearing bracket
flanged onto the suction and discharge ends. Bearings are of the plain type and oil
lubricated.
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The cartridge design comprises the complete rotating parts, the delivery cover, the
diffusers, the stage casing, the bearings and all wearing parts. The cartridge design
permits a quick exchange of the inner element, reducing considerably the
maintenance downtime. Shaft seals are of the mechanical type with cooling.
5.2.3.4.4 Polishing Plant
The condensate polishing plant is intended to provide the boiler with a continuous
source of purified feedwater and to provide emergency protection in the event of a
condenser leak. The constant feedwater quality obtained downstream the polishing
plant allows the application of the combined water treatment to the feedwater for the
whole water-steam cycle.
Condensate polishing units
The condensate polishing plant consists of 2 x 50 % prefilters associated with 3 x
50 % mixed bed polisher vessels, each supplied with a charge of strongly acidic
cation and strongly basic anion exchange resins supported on a bottom nozzle
plate collection system. The condensate polishing units are rubber lined pressure
vessel type, each complete with all associated pipework, valves, controls and
necessary instrumentation.
External regeneration system
The regeneration is made externally from the mixed bed polisher vessels. A spare
resin charge will be held in the cation regeneration/resin hold vessel. When a mixed
bed resin charge is exhausted, this resin is transferred to the resin separation/anion
regeneration vessel using demineralised water supplied by the regeneration water
pumps.
The plant is fully controlled by a PLC. Mixed bed polisher vessels are placed into
service automatically or by manual initiation from the control screen.
5.2.3.4.5 Auxiliary Steam Systems
The auxiliary steam production and distribution systems supply steam to the
different users of the unit. Auxiliary steam is distributed to the users from a sliding
pressure header fed from a branch pipe off the cold reheat steam (CRS).
The steam header consists of a pipe section installed in the machine room. It is
equipped with an automatic drain tap to discharge the condensate to the blowdown
pipe.The steam supply lines are equipped with motorised isolating valves and
manual valves. The various outgoing branch pipes feed the following auxiliaries:
− the feedwater tank pre-heating at unit start-up. Under base load the feedwater
tank is fed by the cold reheat steam to maintain the feedwater temperature at
about 190°C, when the unit is first started, the feedwater tank is not preheated,
so the boiler will start with cold feedwater.
− the steam turbine gland seals,
− the boiler air preheaters. When the unit is first started, the boiler air preheater is
not in service,
− the mills and PC pipes for inerting and purging,
70
− conditioning of inerting system.
Some branch pipes are equipped with pressure reducing valves at the auxiliaries
inlet.
5.2.3.4.6 Chemical Dosing & Sampling Systems
Chemical Dosing System
Skids for ammonia, hydrazine and oxygen dosing shall be supplied in order to
control the chemistry of the water/steam cycle. The dosing plant shall be located on
the ground floor of the turbine hall.
Dosing of chemicals to the water/steam cycle shall be automatic depending on
parameters measured by the online chemical sampling system.
Chemical Sampling System
The chemical sampling system shall receive, condition and analyse water and
steam samples from various locations in the water/steam cycle. The sampling plant
shall be located on the ground floor of the turbine hall.
Sample analyses shall be fed to the DCS to allow the dosing system to operate
automatically.
5.2.3.5 System Description (Reference Case C1-R0)
5.2.3.5.1 Plant Operation
HP/LP bypass
The steam circuit is designed with bypasses which allow start-up of the unit under
any condition. The overall control of the valves is integrated in the DCS.
The capacity of bypasses in term of flow is:
− for HP Bypass, 100 % of ST steam flow at nominal pressure (Not in Unit 700
Turbine Island scope),
− for LP Bypass, 50 % of ST flow at nominal pressure.
The HP/LP bypass systems are designed:
− to permit the matching of steam and turbine metal temperatures during boiler
start-up, thus reducing rotor and cylinder thermal stresses,
− to permit the operation of the boiler with the turbo-generator tripped. Thus, the
boiler can be maintained at its minimum load,
− to act as a main steam pressure control device (for HP bypass valve) in case of
over-pressure or excessive pressure increase (capacity compensated by
superheater outlet safety valve).
5.2.3.5.2 Mechanical Auxiliary System
71
HP feed water heater No. 9 level control loop:
The drain condensate is cascaded down to the HP feed water heater No. 8 via the
normal level control valve. If the level rises above the normal level (normal control
valve signal 100 %), the emergency drain control valve comes into operation and
the drain condensate is drained to the flash tank at the main condenser. The normal
level control valve drains from the outlet of the integrated drains cooler. The
emergency level control valve drains condensate out of the condensing part of the
feed water heater ie this drain bypasses the drains cooler.
If the emergency drain control valve of the next lower heater No. 8 goes into
operation (leaving the closed position), then the normal drains control valves of feed
water heater No. 9 automatically closes and the No. 9 emergency drain control
valve goes into operation.
HP feed water heater No. 8 level control loop:
The drain condensate is cascaded down to the HP feed water heater No. 6 via the
normal level control valve. If the level rises above the normal level (normal control
valve signal 100 %), the emergency drain control valve comes into operation and
the drain condensate is drained to the flash tank at the main condenser. The normal
level control valve drains from the outlet of the integrated drains cooler. The
emergency level control valve drains condensate out of the condensing part of the
feed water heater ie this drain bypasses the drains cooler.
If the emergency drain control valve of the next lower heater No. 7 goes into
operation (leaving the closed position), then the normal drains control valves of feed
water heater No. 8 automatically closes and the No. 8 emergency drain control
valve goes into operation.
Feed water heater No. 7 level control loop:
The drain condensate is cascaded to the feed water tank via the normal level
control valve. If the level rises above the normal level (normal control valve signal
100 %), the emergency drain level control valve comes into operation and the drain
condensate is drained to the flash tank on the main condenser. The normal level
control valve drains from the outlet of the integrated drains cooler. The emergency
drain valve bypasses the drains cooler.
HP feed water heater 7 & 8 bypass:
The HP heater 7 & 8 bypass consist of power operated 3 way bypass valves, fast
closing (closing time adjustable from approx. 5 to 20 seconds on site) operated by
feed water pressure.
Each of the above valves incorporates a needle valve for setting the speed of
operation in order to achieve fast isolation of the water tube side of the HP heater 7
& 8 should a high high water level be detected in the shell (steam) side of any one
of the heaters.
HP feed water heater 9 bypass:
72
The HP heater 9 bypass consist of power operated 3 way bypass valves, fast
closing (closing time adjustable from approx. 5 to 20 seconds on site) operated by
feed water pressure.
Feed water tank /condenser level control:
When the level in the feed water tank drops, then condensate is pumped by one of
the two 100 % make-up water pumps from the demineralized water tank into the
condenser neck where it is introduced by spraying above the level of the tube banks
in order to achieve good degasification. If the level is below the make-up valve
level, there is opening of the emergency make-up valve. If the feed water tank level
rises above the overflow level, then the automatic valve on the overflow line opens
to discharge the water to boiler separator flash tank.
The level in the condenser is held constant by extraction water control valve. In
case of water surplus in the steam and water cycle, the level will increase in the
feed water tank, and the surplus will be discharged to the boiler flash tank by the
automatic valve on the feed water tank over flow line.
Feed water tank pressure control:
During normal operation, the feed water tank is held at a pressure of approximately
14 bara by feeding steam from the IP turbine. When the tank pressure falls below
approximately 2.7 bara, the control valve opens and introduces cold reheat steam
into the tank to hold the pressure. During unit startup, when auxiliary steam is
available from the auxiliary steam header, the feed water in the feed water tank can
be preheated to about 105-130 °C before boiler start. However, the boiler can start
with cold feed water supply if no auxiliary steam is available.
LP feed water heaters No. 5 & No. 3:
The drain condensate is cascaded to the next lowest LP feed water heaters Nos. 4
& 2 via the normal level control valve. If the level rises above the normal level
(normal control valve signal 100 %), then the emergency drain control valve comes
into operation and the drain condensate is led directly to the main condenser.
LP feed water heaters No. 4 & No. 2:
The heat of LP4 & LP2 heater drain condensate is recovered by drain recovery
pumps, which pump the drain condensate to its outlet.
LP feed water heater No. 1:
The drain from LP1 heater flows to the condenser shell via a loop pipe.
Condensate pump minimum flow control:
The flow rate through the running condensate extraction pump (CEP) is maintained
above the permissible minimum by condensate recirculation back to the condenser.
The condensate flow is measured after the CEP's in the common line. In case this
flow should become too low, the minimum flow control valve opens and thus keeps
the flow through the running CEP above the minimum.
73
Auxiliary steam header pressure control:
The auxiliary steam header is fed during normal operation from the cold reheat line.
The normal pressure is kept at the same level as the cold reheat steam line
pressure. Before boiler start, the auxiliary steam header is fed from an external
source. As soon as the main boiler is started and produces steam, the steam from
cold reheat line (coming from HP bypass discharge) will feed the auxiliary steam
header.
5.2.4
Modifications Relative to C1-R0 Plant.
5.2.4.1 Reference Plant
5.2.4.1.1 Changes For Case C2-R0
In this case the condenser vacuum is higher, ie 26 mbara as opposed to 40mbara
for case C1-R0. This is due to the lower cooling water temperature at the site.
Otherwise the design is very similar to case C1-R0.
5.2.4.1.2 Changes For Case C3-R0
This case is very similar to case C1-R0.
5.2.4.2 Oxy Firing Plant
5.2.4.2.1 Changes For Case C1-A1
The capture plant gives heat to the water/steam cycle condensate, so less steam is
taken from the turbine and the flow through the condenser, condensate extraction
pumps and condensate polishing plant is higher. The capture plant heat exchangers
are located with the capture plant, ie not in the turbine hall, and are not covered by
this report.
There are only 3 LP heaters instead of 5 for case C1-R0. Only 1 of these heaters is
located in the condenser neck.
5.2.4.2.2 CHANGES FOR CASE C2-A1
In this case the condenser vacuum is higher, ie 26mbara as opposed to 40mbara
for case C1-R0. This is due to the lower cooling water temperature at the site.
The capture plant gives heat to the water/steam cycle condensate, so less steam is
taken from the turbine and the flow through the condenser, condensate extraction
pumps and condensate polishing plant is higher. The capture plant heat exchangers
are located with the capture plant, ie not in the turbine hall, and are not covered by
this report.
There are only 3 LP heaters instead of 5 for case C1-R0. Only 1 of these heaters is
located in the condenser neck.
5.2.4.2.3 Changes For Case C3-A1
74
The capture plant gives heat to the water/steam cycle condensate, so less steam is
taken from the turbine and the flow through the condenser, condensate extraction
pumps and condensate polishing plant is higher. The capture plant heat exchangers
are located with the capture plant, ie not in the turbine hall, and are not covered by
this report.
There are only 2 LP heaters instead of 5 for case C1-R0. Only 1 of these heaters is
located in the condenser neck.
5.2.4.2.4 Changes For Case C1-A2
This case is very similar to case C1-R0.
5.2.4.3 Amine Capture Plant
5.2.4.3.1 Changes For Case C1-B1
The capture plant gives heat to the water/steam cycle condensate, so less steam is
taken from the turbine. However, this is more than offset by the higher steam flow
taken by the amine reboiler. Consequently the flow through the condenser,
condensate extraction pumps and condensate polishing plant is lower than in case
C1-R0. The capture plant heat exchangers are located with the capture plant, ie not
in the turbine hall, and are not covered by this report.
There are only 2 LP heaters instead of 5 for case C1-R0. Neither of these heaters is
located in the condenser neck.
5.2.4.3.2 Changes For Case C2-B1
In this case the condenser vacuum is higher, ie 26mbara as opposed to 40mbara
for case C1-R0. This is due to the lower cooling water temperature at the site.
The capture plant gives heat to the water/steam cycle condensate, so less steam is
taken from the turbine. However, this is more than offset by the higher steam flow
taken by the amine reboiler. Consequently the flow through the condenser,
condensate extraction pumps and condensate polishing plant is lower than in case
C1-R0. The capture plant heat exchangers are located with the capture plant, ie not
in the turbine hall, and are not covered by this report.
There are only 2 LP heaters instead of 5 for case C1-R0. Neither of these heaters is
located in the condenser neck.
5.2.4.3.3 Changes For Case C3-B1
The capture plant gives heat to the water/steam cycle condensate, so less steam is
taken from the turbine. However, this is more than offset by the higher steam flow
taken by the amine reboiler. Consequently the flow through the condenser,
condensate extraction pumps and condensate polishing plant is lower than in case
C1-R0. The capture plant heat exchangers are located with the capture plant, ie not
in the turbine hall, and are not covered by this report.
75
There are only 2 LP heaters instead of 5 for case C1-R0. Neither of these heaters is
located in the condenser neck.
5.2.4.3.4 Changes For Case C1-B2
This case is very similar to case C1-R0.
5.3
BOILER ISLAND (UNIT 200)
For this BERR-366 project, all the boiler designs are based on Doosan Babcock
two-pass, once through supercritical PosiflowTM boiler technology, which features
low mass flux vertical internally ribbed tube furnace. The boiler designs are based
on the ASME code standard.
The ASC boiler comprises of one OTSC PosiflowTM steam generator; a two-pass
boiler with opposed wall firing and a series back end arrangement with spray
attemperation for superheater and reheater temperature control. The boiler island is
comprised of the following major components with their related ancillaries and
control systems as appropriate:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
Furnace
Superheater
Reheater
Economizer
Separator, recirculation pump and the start-up system
Attemperators
Soot blowing system
Primary air fans (air firing cases) or
Primary Flue Gas Recycle fans (Oxyfuel cases)
Forced draft fans (air firing cases) or
Secondary Flue Gas Recycle fans (Oxyfuel cases)
Induced draft fan
Air preheaters.
Pulverizers
Coal feeders
Coal burners
5.3.1 Air/PF-Fired Boiler Island Process Descriptions
5.3.1.1
Boiler Island Process Flow Diagram: C1-R0, C1-B1 & C1-B2
Figures 5.3.1-1 below presents the general process flow diagram of the C1-B1
Amine Scrubbing CO2 Capture Power Plant boiler island for C1:Subbituminous/Keephills (TransAlta Power). From overall power plant configuration
viewpoints, the power plant configuration of C1-B1 and C1-B2 is basically the C1R0 power plant with an additional Amine Scrubbing CO2 Recovery Plant (Unit 800)
and CO2 Compression Plant (Unit 900) added downstream the FGD plant. The
boiler islands of C1-B1, C1-B2 are same as per C1-R0 [2], which has been
presented in project D4.1 report [2].
76
The boiler is air/PF-fired, operated under balanced draught conditions. The forced
draught (FD) fans supply the bulk of the air, which is split into two air streams,
namely the primary air (PA) stream and secondary air (SA) stream. The PA air and
SA air are preheated in the regenerative airheaters before being conveyed to the
furnace for combustion. The primary air boosted by PA fans is delivered to the
milling plant to dry the pulverised fuel (PF) and convey the PF from the mills to the
furnace for combustion.
Exhaust gases from the furnace pass through the various boiler heat exchanger
zones where the heat in flue gas is transferred to the boiler water or to the steam for
superheating or reheating. Exhaust gases from the economiser pass through a SCR
before entering the regenerative airheater where the final extraction of heat from the
gases takes place to preheat the air streams originating from the FD and PA fans.
COAL C1 - SUB-BITUMINOUS
Emissions
C1B1
LOW SULPHUR
AIR FIRING WITH AMINE
SCRUBBER
INLAND PLANT
TEMPERING GAS CONTROL
NOx
Limit
50.00
50.00
g/MWh (net)
SOx
55.00
55.00
g/MWh (net)
Furnace & Boiler
Heat Released & Available
Enthalpy
Particulates
Mercury
SO3
28.00
3.50
5.00
0.28
3.50
3.22
g/MWh (net)
mg/MWh (net)
Adiabatic Flame Temperature
Heat to Steam
Boiler Efficiency
Actual
[email protected] 3% O2
1232.75 MWt
File Ref: 78557_B251_CA_31000_C1B1_0001_PFDAIR_REV25.XLS
Efficiency Method
CRH
HRH
FEEDW
MS
GOUT
2529 kJ/kg
2002
1041.0
88.838
94.352
410 kg/s
°C
CO2 = 2.7%
MWt
H2O = 3.7%
Inerts = 93.6%
%GCV
%NCV
Loss
Cooling
Towers
(inland)
35 °C
99393.6 gCO2/MWh (400MWe)
GOUT
CO2 = 96.9%
Removal Efficiency
CO2 %
Ash %
90.0
90.0
CO2 RECOVERY
AMINE
SCRUBBER +
DCC
27.51 kg/s
Furnace SO2 =245 ppm
Furnace SO3 =3 ppm
Removal Efficiencies
NOx %
Ash %
Hg %
Regenerative
AIR
HEATER
AI1
FURNACE
372 °C
FG1
FG2
498 kg/s
DeNOx
SCR
6.0419 pgHg/kgFG
95.67
99.96
87.09
540 kg/s
51 °C
100% RH
FG4
523 kg/s
DeHg
120 °C
FGD
FG5
524 kg/s
FG6
524 kg/s
118 °C
118 °C
FG7
524 kg/s
AM1
91%MR
Air Stream
GYP1
ID FAN
AI2
SO2 =2 vppm @ 6% O2
H2O
CO2 from CaCO3
ESP
FG3
499 kg/s
FG8
0.6649 pgHg/kgFG
0 kg/s
Removal Efficiencies
SO2 %
FA1 AI3
99.1
SO3 %
50.0
HCl %
100.0
Ash %
90.0
SFGR3
338 kg/s
20 °C
SFGR4
324 kg/s
331 °C
BA1
PFGR3
116 kg/s
SFGR1
SFGR5
459 kg/s
324 kg/s
331 °C
20.85% v/v O2
SFGR FAN
PFGR4
105 kg/s
MILL
15 °C
AIR2
327 °C
PFGR2
20 °C
PFGR7
173 kg/s
PFGR6
110 kg/s
PFGR5
110 kg/s
65 °C
18.18% v/v O2
315 °C
315 °C
PTM1
4.4 kg/s
121 kg/s
20% RH
PFGR FAN
1.75 kg Air/ kg Fuel fired
37.5% RH
F1
Figure 5.3.1-1 Boiler Island PFD of Amine Scrubbing CO2 Capture Power Plant
(for Cases C1-R0, C1-B1 & C1-B2)
The electrostatic precipitator (ESP) located downstream of the airheater removes
entrained ash from the flue gases, followed by downstream FGD plant which
removes SOx from the flue gases before the exhaust gases entering the Amine
Scrubber where ~90% of CO2 is extracted from the main flue gas and fed to the
downstream CO2 compression plant for compression and storage. The scrubbed
flue gas is discharged to the atmosphere via the cooling tower (for C1, and C3
cases) or a stack (for C2 cases).
It should be noted that the DeHg plant indicated in the process diagram is not
standalone equipment rather than showing the employment of a DeHg process in
the flue gas stream. For all the air/PF-fired cases in this BERR366 project, DeHg is
based on MHI’s technology process that HCl is injected upstream of the SCR for
mercury oxidation to enhance removal ratio at the FGD absorber. The detail about
the DeHg process is presented later in Section 5.8.2.
77
5.3.1.2 Boiler Island Process Flow Diagram (PFD): C2-R0 & C2-B1
From overall power plant configuration viewpoint, C2-B1 power plant is basically the
C2-R0 reference power plant with an additional Amine Scrubbing CO2 Recovery
Plant (Unit 800) and CO2 Compression Plant (Unit 900) added downstream of the
FGD plant. Figures 5.3.1-2 presents the general process flow diagram of the C2-B1
Amine Scrubbing CO2 Capture Power Plant boiler island for C2:Bituminous of Point
Tupper (Nova Scotia Power) which also applies to C2-R0.
COAL C2 - BITUMINOUS
Emissions
C2B1
HIGH SULPHUR
AIR FIRING WITH AMINE
SCRUBBER
COASTAL PLANT
TEMPERING GAS CONTROL
NOx
Limit
50.00
50.00
g/MWh (net)
SOx
55.00
55.00
g/MWh (net)
Furnace & Boiler
Heat Released & Available
Enthalpy
Particulates
Mercury
SO3
28.00
3.00
5.00
0.28
3.00
3.46
g/MWh (net)
mg/MWh (net)
Adiabatic Flame Temperature
Heat to Steam
Boiler Efficiency
Actual
[email protected] 3% O2
1219.60 MWt
2698 kJ/kg
2152
1042.6
90.787
94.675
Ref: 78557_B251_CA_31000_C2B1_0001_PFDAIR_REV24.XLS
Efficiency Method
CRH
°C
MWt
%GCV
%NCV
Loss
GOUT
CO2 = 96.9%
HRH
FG9
FEEDW
413 kg/s
45 °C
MS
CO2 RECOVERY
Furnace SO2 =901 ppm
Furnace SO3 =12 ppm
AMINE
SCRUBBER
Removal Efficiencies
NOx %
Ash %
Hg %
Regenerative
AIR
HEATER
AI1
FURNACE
372 °C
FG1
501 kg/s
45 °C
100% RH
FG3
462 kg/s
FG4
485 kg/s
H2O
CO2 from CaCO3
45 °C
FG5
491 kg/s
DeHg
120 °C
SO2 =2 vppm @ 6% O2
FG8
FGD GGH
0.7143 pgHg/kgFG
ESP
FG2 DeNOx
SCR
462 kg/s
4.1384 pgHg/kgFG
96.14
99.79
82.57
118 °C
FGD
FG6
491 kg/s
78 °C
Stream
FG7
491 kg/s
90 °C
GYP1
ID FAN
AI2
94%MR
AM1
FA1 AI3
20 °C
SFGR4
360 kg/s
316 °C
Removal Efficiencies
SO2 %
85.00
HCl %
100.00
78 °C
131532 gCO2/MWh (400MWe)
PFGR3
STACK
Coastal
Site
60 kg/s
SFGR1
446 kg/s
SFGR5
360 kg/s
316 °C
20.85% v/v O2
SFGR FAN
PFGR4
52 kg/s
MILL
15 °C
AIR2
322 °C
PFGR2
20 °C
PFGR7
99 kg/s
PFGR6
63 kg/s
PFGR5
63 kg/s
90 °C
19.26% v/v O2
271 °C
70 kg/s
PTM1
10.9 kg/s
20% RH
271 °C
PFGR FAN
1.75 kg Air/ kg Fuel fired
8.5% RH
F1
Figure 5.3.1-2 Boiler Island PFD of Amine Scrubbing CO2 Capture Power Plant
(For Cases C2-R0 and C2-B1)
With majority of the overall flow process similar to that of C1-B1 described above, the
major differences are that the C2-B1 power plant is based on coastal site, sea water
cooling, with condenser pressure of 2.6kPa instead of 4 kPa, flue gas discharged via a
stack instead of cooling tower.
5.3.1.3 Boiler Island Process Flow Diagram (PFD): C3-R0 & C3-B1
Figures 5.3.1-3 presents the general process flow diagram of the C3-B1 Amine
Scrubbing CO2 Capture Power Plant boiler island for C3: Lignite/Shand (SaskPower),
which also applies to C3-R0 as far as the boiler island process is concerned.
C3 site conditions is similar to that of C1, namely on the basis of inland Greenfield,
cooling water for heat rejection and flue gas discharge, the overall process flow
process similar to that of C1-B1 described above. Note that the C3 Lignite boiler fuel
firing system is assumed to be based on the existing subcritical boiler of Sask Power.
78
99.76
SO3 %
413 kg/s
CO2 = 3.5%
H2O = 6.1%
Inerts = 90.4%
SFGR3
376 kg/s
BA1
1 kg/s
GOUT
COAL C3 - LIGNITE
Emissions
C3B1
HIGH SULPHUR
AIR FIRING WITH AMINE
SCRUBBER
INLAND PLANT
TEMPERING GAS CONTROL
NOx
Limit
50.00
50.00
g/MWh (net)
Furnace & Boiler
Heat Released & Available
SOx
55.00
55.00
g/MWh (net)
Enthalpy
Particulates
Mercury
SO3
28.00
5.50
5.00
0.28
5.50
3.46
g/MWh (net)
mg/MWh (net)
Adiabatic Flame Temperature
Heat to Steam
Boiler Efficiency
Actual
[email protected] 3% O2
1272.46 MWt
1744
1040.8
82.673
91.372
Ref: 78557_B251_CA_31000_C3B1_0001_PFDAIR_REV26.XLS
Efficiency Method
CRH
HRH
FEEDW
MS
Plant In-Service ==>
FD Fans
I/S
ID Fans
CT / Stack
I/S
I/S
2219 kJ/kg
°C
MWt
%GCV
%NCV
Direct
I/S = In-Service
OOS = Out-of-Service
Cooling
Towers
(inland)
GOUT
509 kg/s
CO2 = 3.6%
H2O = 9.1%
Inerts = 87.3%
165341 gCO2/MWh (400MWe)
CO2
RECOVERY
53 °C
100% RH
COUT
40 °C
CO2 = 96.9%
Removal Efficiencies
Furnace SO2 =639 ppm
Furnace SO3 =9 ppm
NOx %
Ash %
Hg %
96.53
99.97
90.89
7.09 kg/s
624 kg/s
53 °C
100% RH
Regenerative
AIR
HEATER
AI1
FURNACE
372 °C
FG1
FG2
587 kg/s
DeNOx
SCR
11.4395 pgHg/kgFG
0.5845 pgHg/kgFG
HEAT RECOVERY
FG4
616 kg/s
FG5
616 kg/s
DeHg
156.5 °C
154 °C
FG6
616 kg/s
48.97 MW
SO2 =1.9 vppm @ 6% O2
H2O
CO2 from CaCO3
FGD
ESP
FG3
587 kg/s
FG8
FG7
616 kg/s
80 °C
Air Stream
GYP1
1 kg/s
ID FAN
Removal Efficiencies
AI2
AM1
90%MR
FA1 AI3
SA3
360 kg/s
99.70
SO3 %
HCl %
85.00
100.00
20 °C
SA4
345 kg/s
293 °C
BA1
SO2 %
PA3
169 kg/s
SA1
SA5
530 kg/s
345 kg/s
293 °C
20.85% v/v O2
FD FAN
PA4
155 kg/s
MILL
15 °C
AIR2
294 °C
PA2
20 °C
PA7
240 kg/s
66 °C
18.44% v/v O2
PA6
156 kg/s
PA5
156 kg/s
292 °C
292 °C
PTM1
0.9 kg/s
170 kg/s
20% RH
C1R0 Airheater Tgas = 121 °C (diluted)
PA FAN
1.85 kg Air/ kg Fuel fired
33.2% RH
F1
Figure 5.3.1-3 PFD of Amine Scrubbing CO2 Capture Power Plant Boiler Island
(For Cases C3-R0 and C3-B1)
5.3.2 Oxyfuel Boiler Island Process Descriptions
5.3.2.1 C1-A1 Oxyfuel CO2 Capture Power Plant Boiler Island PFD
Figure 5.3.2-1 below presents the overall process flow diagram of the C1-A1
Oxyfuel boiler island, showing the mass and heat balance of air/flue gas streams.
The oxyfuel boiler is operated under balanced draught conditions similar to an
air/PF-fired boiler. Instead of using air streams, the oxygen supplied by the ASU
mixed with recycled flue gas form two separate flue gas recycle (FGR) streams,
namely the PFGR stream and SFGR stream which correpond to the primary air (PA)
and secondary air (SA) streams of an air/PF-fired boiler island.
The PFGR stream and SFGR stream are preheated in a tubular airheater before
being fed to the furnace for combustion. The SFGR is delivered by SFGR fans to the
burner windbox, while the PFGR stream is delivered by PFGR fans to the milling
plant to dry the pulverised fuel (PF) and convey the PF to the burners for
combustion. Note that a primary flue gas heat recovery Unit 550 is installed
upstream the milling plant for PFGR tempering upstream the mill with the heat
revovered for feedwater preheating for improving overall cycle efficiency of the
power plant.
Exhaust gases from the furnace pass through the various boiler heat transfer banks
where the heat in flue gas is transferred to the boiler water or to the steam for
superheating or reheating. Exhaust gases from the economiser pass through the
79
tubular airheaters where the final extraction of heat from the gases takes place to
preheat the PFGR and SFGR streams.
COAL C1 - SUB-BITUMINOUS
Emissions
C1A1
LOW SULPHUR
OXYFUEL BOILER
PLANT
COOL RECYCLE
HEAT RECOVERY CONTROL
Limit
50.00
55.00
Actual
> INERTS PLANT
NOx
SOx
195.5
2393
g/MWh (net)
g/MWh (net)
Particulates
Mercury
SO3
28.00
3.50
5.00
0.88
27.10
61.34
g/MWh (net)
mg/MWh (net)
C78557: DTI 366 CCPC ASC C&CR
78557_B251_CA_31000_C1A1_0010_PFDOXY_DTI366_FGROpt2_Case3_70FGR_rev15.XLS
CRH
HRH
FEEDW
MS
Furnace & Boiler
Heat Released & Available
Enthalpy
Adiabatic Flame Temperature
Heat to Steam
Boiler Efficiency
[email protected] 3% O2
Recycle Conditions :
Plant In-Service ==>
FD Fans
ASU
1213.09 MWt
2637 kJ/kg
1965
1023.7
85.878
91.211
Efficiency Method
°C
ID Fans
CT \ Stack
CO2 Compression
Inerts Removal
MWt
%GCV
%NCV
Loss
I/S = In-Service
OOS = Out-of-Service
CO2 RECOVERY
69.8% FGR
65.1% total
Based on (Σ FGR + Product) %
GOUT
134 kg/s
#NAME?
CO2 = 82.7%
H2O = 2.9%
Furnace SO2 =991 ppm
Inerts = 14.5%
Furnace SO3 =42 ppm
Furnace NOx =119 ppm
I/S
I/S
I/S
OOS
I/S
I/S
Product SO2 =1179 ppm
Removal Efficiencies
SO2 %
FGR1
120 kg/s
31 °C
0.00
SO3 %
0.00
HCl %
100.00
ID FAN
RHG
5 kg/s
FG8
253 kg/s
31 °C
Tubular
GAS/ GAS
HEATER
AI1
372 °C
FURNACE
FG1
FG2
466 kg/s
???
DeNOx
FG3
466 kg/s
HEAT RECOVERY
HEAT RECOVERY
A
B
ESP
FG4
FG5
FG6
466 kg/s
466 kg/s
278 kg/s
199 °C
#NAME?
###
125 °C
#NAME?
###
AI2
86%MR
AM1
DCC
0 kg/s O2 Stream
FG7
278 kg/s
COND1 24 kg/s
74 °C
Tav =100°C
FA1 AI3
#NAME? MW cooling
PFGR1
124 kg/s
#NAME?
#VALUE!
Cooling Towers
(Inland Plant)
0 kg/s
SFGR4
305 °C
BA1
256 kg/s
SFGR3
RH FGR FAN
183.5 kg/s
105 °C
(STARTUP ONLY)
305 °C
SFGR5
256 kg/s
SFGR2
256 kg/s
305 °C
32% v/v O2
FA2
HEAT
RECOVERY
MILL
SFGR FAN
PFGR4
146 kg/s
AIR2
SOXY
72 kg/s
PFGR3
146 kg/s
302 °C
SFGR1
0 kg/s
100 °C
23% RH
AIR1
NIT1
PFGR2
PFGR7
209 kg/s
PFGR6
146 kg/s
65 °C
18.18% v/v O2
259 °C
20.85% v/v O2
6.53 MWth
PFGR5
146 kg/s
Tav =280°C
302 °C
35 °C
PTM1
0 kg/s
146 kg/s
75% RH
PFGR FAN
POXY
22 kg/s
ASU
49.5 % RH
OXY
Figure 5.3.2-1: C1-A1: Process Flow Diagram of Oxyfuel CO2 Capture Power Plant
The electrostatic precipitator (ESP) located downstream of the airheater removes
entrained ash from the flue gases. The de-dusted flue gas is cooled by a heat
recovery Unit 550A, before the SFGR stream take-off. The remaining flue gas is
further cooled by the second main flue gas heat recovery Unit 550B before entering
the DCC where the moisture from the flue gas is removed as condensate.
The saturated flue gas from the DCC is discharged via an ID fan. The PFGR is
taken off at the ID fan exit, the balance of flue gas is fed to the downstream Unit
1200 & 1300 for CO2 purification processing during plant normal operation, or is
discharged through by-pass ductwork to the cooling tower during start-up/showdown operations.
5.3.2.2 C1-A2 Oxyfuel CO2 Capture Retrofit Power Plant PFD
Figures 5.3.2-2 below presents the general process flow diagram of the C1-A2 boiler
island. C1-A2 is defined as a retrofit of the reference power plant C1-R0[2], with
majority of the overall process flow diagram similar to that of C1-A1, the major
differences are summarised below:
• Retains SCR, DeHg, Rotary Airheater and FGD plant from C1-R0 plant,
• Both PFGR and SFGR streams are taken off at ID fan outlet after being cleaned
by the existing FGD plant, no additional DCC is installed within the boiler island.
• No primary flue gas heat recovery Unit 550.
• Furnace/Boiler envelope and pressure parts remain the same as per C1-R0.
80
• Oxygen is preheated to approximately 150°C using LP steam for improved cycle
efficiency.
• Oxygen is injected downstream the rotary airheater in order to prevent oxygen
leakage inside the rotary airheater.
COAL C1 - SUB-BITUMINOUS
Emissions
C1A2
LOW SULPHUR
RETROFIT OXYFUEL
BOILER PLANT
COLD RECYCLE
TEMPERING GAS CONTROL
Limit
50.00
55.00
Actual
> INERTS PLANT
NOx
SOx
12.34
30.42
g/MWh (net)
g/MWh (net)
Particulates
Mercury
SO3
28.00
3.50
5.00
1.22
1.70
9.67
g/MWh (net)
mg/MWh (net)
C78557: DTI 366 CCPC ASC C&CR
78557_B251_CA_31000_C1A2_0010_PFDOXY_DTI366_FGROpt2_Case3_63FGR_rev15.XLS
Furnace & Boiler
Heat Released & Available
Enthalpy
Adiabatic Flame Temperature
Heat to Steam
Boiler Efficiency
[email protected] 3% O2
Recycle Conditions :
HRH
FEEDW
MS
1983
1028.3
85.366
90.667
Efficiency Method
°C
ID Fans
CT \ Stack
CO2 Compression
Inerts Removal
MWt
%GCV
%NCV
Loss
I/S
I/S
I/S
OOS
I/S
I/S
I/S = In-Service
OOS = Out-of-Service
CO2 RECOVERY
63.4% FGR
CRH
Plant In-Service ==>
FD Fans
ASU
1211.40 MWt
2830 kJ/kg
64.3% total
Based on (Σ FGR + Product) %
GOUT
160 kg/s
72 °C
CO2 = 69%
O2 = 3.9%
Product SO2 =7 ppm
Removal Efficiencies
SO2 %
98.51
Furnace SO2 =323 ppm
H2O = 18.5%
FGR1
SO3 %
50.00
Furnace SO3 =8 ppm
Furnace NOx =117 ppm
Inerts = 12.4%
295 kg/s
HCl %
100.00
72 °C
ID FAN
RHG
5 kg/s
AI1
FURNACE
299 kg/s
GAS/ GAS
HEATER
74 °C
92% RH
FG1
FG2
DeNOx
21.8 kg/s
FG3
437 kg/s
HEAT RECOVERY
ESP
372 °C
437 kg/s
FG8
455 kg/s
Regenerative
72 °C
1.57 kg/s H2O
0.18 kg/s CO2 from CaCO3
FGD
FG4
FG5
459 kg/s
458 kg/s
206 °C
205 °C
FG6
0.07 kg/s O2 Stream
FG7
453 kg/s
453 kg/s
80 °C
63 MWth
COND1 -1 kg/s
80 °C
Tav =142°C
AI2
64%MR
AM1
-1.02 MW cooling
FA1 AI3
0 kg/s
SFGR4
Cooling Towers
(Inland Plant)
SFGR3
79 °C
174 kg/s
BA1
(STARTUP ONLY)
363 °C
SFGR5
246 kg/s
SFGR2
187 kg/s
311 °C
31.41% v/v O2
SOXY
72 kg/s
PFGR5
103 kg/s
MILL
360 °C
310 °C
SFGR1
187 kg/s
74 °C
PFGR4
84 kg/s
FA2
SFGR FAN
AIR2
14% RH
PFGR3
93 kg/s
74 °C
PFGR1
112 kg/s
AIR1
NIT1
PFGR2
PFGR7
188 kg/s
PFGR6
126 kg/s
80 °C
18.18% v/v O2
286 °C
20.85% v/v O2
POXY
23 kg/s
74 °C
PTM1
19 kg/s
112 kg/s
PFGR FAN
1% RH
ASU
79.2 % RH
150 °C
Steam
F1
62.74 kg/s
165 °C Tsat
3.89 kg/s
Oxygen
Preheater
o
155 C
Condensate
OXY
95 kg/s
15 °C
Figure 5.3.2-2:C1-A2: Process Flow Diagram of Oxyfuel CO2 Capture Power Plant
5.3.2.3 C2-A1 Oxyfuel CO2 Capture Power Plant Boiler Island PFD
Figure 5.3.2-3 below presents the general process flow diagram of the C2-A1
Oxyfuel CO2 Capture Power Plant boiler island. With majority of the C2-A1 process
flow diagram being similar to that of C1-A1 described above, the major differences
are as follows:
•
•
Both the C2-A1 PFGR and SFGR streams are required to be cleaned by a FGD
plant instead of a DCC plant, hence both PFGR and SFGR streams are taken off
at ID fan outlet.
The C2-A1 power plant is a coastal site, utilising seawater cooling with a
condenser pressure of 2.6 kPa instead of 4 kPa and with flue gas discharged via
a stack instead of cooling tower.
5.3.2.4 C3-A1 Oxyfuel CO2 Capture Power Plant PFD
Figures 5.3.2-4 below presents the general process flow diagram of the C3-A1 boiler
island for C3:Lignite (Shand, Sask Power). The C3-A1 is of inland greenfield site
condition, with majority of the overall flow process similar to that of C1-A1, the major
difference between C3-A1 and C1-A1 is that the PFGR stream take-off at ID fan
81
outlet is cleaned by a FGD plant instead of a DCC plant, and a DCC is installed
downstream the FGD for further flue gas drying and cooling to meet the
requirements of the PFGR stream and down stream CO2 compression plant.
COAL C2 - BITUMINOUS
Emissions
C2A1
HIGH SULPHUR
OXYFUEL BOILER
PLANT
COLD RECYCLE
HEAT RECOVERY CONTROL
Limit
50.00
55.00
Actual
> INERTS PLANT
NOx
SOx
230.2
150.3
g/MWh (net)
g/MWh (net)
Particulates
Mercury
SO3
28.00
3.00
5.00
0.92
28.70
22.05
g/MWh (net)
mg/MWh (net)
C78557: DTI 366 CCPC ASC C&CR
78557_B251_CA_31000_C2A1_0010_PFDOXY_DTI366_FGR-COLD_Case3_67FGR_rev16.XLS
CRH
HRH
FEEDW
MS
Furnace & Boiler
Heat Released & Available
Enthalpy
Adiabatic Flame Temperature
Heat to Steam
Boiler Efficiency
[email protected] 3% O2
Recycle Conditions :
Plant In-Service ==>
FD Fans
ASU
1187.60 MWt
2971 kJ/kg
2127
1023.6
88.122
91.896
Efficiency Method
°C
ID Fans
CT \ Stack
CO2 Compression
Inerts Removal
MWt
%GCV
%NCV
Loss
62.1% total
Based on (Σ FGR + Product) %
GOUT
136 kg/s
66 °C
CO2 = 71.6%
H2O = 14.9%
Furnace SO2 =1288 ppm
Product SO2 =50 ppm
Removal Ef
SO2 %
Inerts = 13.5%
Furnace SO3 =27 ppm
Furnace NOx =144 ppm
I/S
OOS
I/S
I/S
I/S = In-Service
OOS = Out-of-Service
CO2 RECOVERY
67% FGR
I/S
I/S
SO3 %
FG9
256 kg/s
HCl %
66 °C
ID FAN
FG8
392 kg/s
RHG
66 °C
21 kg/s
Tubular
GAS/ GAS
HEATER
AI1
372 °C
FURNACE
???
FG2
DeNOx
FG1
408 kg/s
FG3
408 kg/s
0.89 kg/s H2O
0.61 kg/s CO2 from C
HEAT
RECOVERY
ESP
FG4
FG5
FG6
408 kg/s
412 kg/s
392 kg/s
201 °C
199 °C
199 °C
FGD
0.23 kg/s O2 Stream
FG7
392 kg/s
53.725 MW 71 °C
COND1
Tav =135°C
AI2
90%MR
AM1
0 kg/s
-0.45 MW coolin
FGR1
276 kg/s
FA1 AI3
76 °C
67% RH
0 kg/s
SFGR4
269 °C
BA1
SFGR3
0 kg/s
RH FGR FAN
(STARTUP ONLY)
269 °C
SFGR5
294 kg/s
SFGR2
294 kg/s
269 °C
30.04% v/v O2
SFGR1
215 kg/s
61 °C
FA2
SFGR FAN
PFGR4
74 kg/s
HEAT
RECOVERY
MILL
STACK
Coastal
Plant
66 °C
294 kg/s
AIR2
86% RH
SOXY
79 kg/s
PFGR3
74 kg/s
305 °C
PFGR1
62 kg/s
AIR1
NIT1
PFGR2
PFGR7
110 kg/s
PFGR6
74 kg/s
90 °C
19.26% v/v O2
235 °C
20.85% v/v O2
PFGR5
74 kg/s
5.897 MWth
67 °C
PTM1
0 kg/s
74 kg/s
305 °C
Tav =270°C
77% RH
PFGR FAN
POXY
13 kg/s
ASU
42.9 % RH
OXY
92 kg/s
F1
Figure 5.3.2-3:C2-A1: Process Flow Diagram of Oxyfuel CO2 Capture Power Plant
COAL C3 - LIGNITE
Emissions
C3A1
HIGH SULPHUR
OXYFUEL BOILER
PLANT
COOL RECYCLE
HEAT RECOVERY CONTROL
Limit
50.00
55.00
Actual
> INERTS PLANT
NOx
SOx
238.0
193.0
g/MWh (net)
g/MWh (net)
Particulates
Mercury
SO3
28.00
5.50
5.00
0.85
60.4
20.5
g/MWh (net)
mg/MWh (net)
C78557: DTI 366 CCPC ASC C&CR
78557_B251_CA_31000_C3A1_0010_PFDOXY_DTI366_FGROpt2_Case3_64FGR_rev19.XLS
CRH
HRH
FEEDW
MS
Furnace & Boiler
Heat Released & Available
Enthalpy
[email protected] 3% O2
Recycle Conditions :
Plant In-Service ==>
FD Fans
ASU
1267.19 MWt
2305 kJ/kg
Adiabatic Flame Temperature
Heat to Steam
Boiler Efficiency
1728
1024.6
81.976
90.307
Efficiency Method
°C
%GCV
%NCV
Loss
CO2 RECOVERY
70.6% FGR
208 MWth Cooling
GOUT
148 kg/s
30 °C
CO2 = 82.5%
H2O = 2.7%
Inerts = 14.7%
Furnace SO3 =27 ppm
Furnace NOx =126 ppm
I/S
OOS
I/S
I/S
I/S = In-Service
OOS = Out-of-Service
63.9% total
Based on (Σ FGR + Product) %
Furnace SO2 =1110 ppm
I/S
I/S
ID Fans
CT \ Stack
CO2 Compression
Inerts Removal
MWt
DCC
Product SO2 =69 ppm
Removal Efficiencies
FGR1
233 kg/s
30 °C
49.82 kg/s
RHG
SO2 %
94.95
SO3 %
50.00
HCl %
61.26
ID FAN
FG8
431 kg/s
64 °C
5 kg/s
Tubular
HEAT RECOVERY
GAS/ GAS
HEATER
AI1
372 °C
FURNACE
???
FG2
DeNOx
FG1
549 kg/s
FG3
549 kg/s
ESP
FG4
FG5
549 kg/s
549 kg/s
193 °C
191 °C
Unit 550B
FG6
84%MR
AM1
0.21 kg/s O2 Stream
425 kg/s
125 °C
COND1 -5 kg/s
12.299 MW 97 °C
Tav =158°C
AI2
FGD
FG7
425 kg/s
38.66 MWth
6.28 kg/s H2O
0.55 kg/s CO2 from CaCO3
HEAT RECOVERY
Unit 550A
Tav =111°C
-3.12 MW cooling
50.959 MWth TARGET
PFGR1
238 kg/s
FA1 AI3
50.959 MWth
34 °C
83% RH
0 kg/s
SFGR4
305 °C
BA1
184 kg/s
SFGR3
RH FGR FAN
117.8 kg/s
96 °C
SFGR5
184 kg/s
SFGR2
184 kg/s
305 °C
38.65% v/v O2
SFGR1
0 kg/s
91 °C
FA2
PRIMARY HEAT
RECOVERY Unit 550
MILL
SFGR FAN
PFGR4
280 kg/s
27% RH
AIR2
SOXY
66 kg/s
PFGR3
280 kg/s
299 °C
Cooling Towers
(Inland Plant)
(STARTUP ONLY)
305 °C
AIR1
NIT1
PFGR2
PFGR7
364 kg/s
PFGR6
280 kg/s
65 °C
18.71% v/v O2
216 °C
20.85% v/v O2
23.818 MWth
PFGR5
280 kg/s
Tav =258°C
299 °C
31 °C
PTM1
0 kg/s
280 kg/s
84% RH
PFGR FAN
POXY
41 kg/s
ASU
44.2 % RH
OXY
107 kg/s
F1
Figure 5.3.2-4:C3-A1:Process Flow Diagram of Oxyfuel CO2 Capture Power Plant
82
5.3.3 Furnace Design
Despite of different power plant options, all the ASC boilers have common features
of the Doosan Babcock’s ASC boiler summarised below:
•
•
•
•
•
Two pass, ASC once through Benson boiler, with PosiflowTM vertical tube
furnace
Series back end, balanced draught operation, two stage superheater spray
control, one stage reheater spray control
Opposed wall fired, 3 burner rows on the front and rear wall, 4 burners per row.
Milling plant located to furnace front, 5 (firing) + 1 (spare), total 6 mills installed
Bottom ash via submerged chain conveyer (SCC) and crusher
For air/PF fired cases (i.e R0, B1, B2 cases), the furnace shape and size is primarily
determined by the fuel ash characteristics, the fuel burnout and oxides of nitrogen
(NOx) in the flue gas required. The layout of the furnace is derived on the basis for
low NOx combustion, generous residence time for fuel burnout and to minimise the
accumulation of slagging/ash deposits.
For oxygen/PF-fired boiler, there is no in-furnace NOx control requirement due to the
elimination nitrogen of air from the combustion process. Therefore an Oxyfuel
furnace can be designed smaller with relatively higher volume thermal rating than
that of air/PF-fired furnace with in-furnace NOx control consideration.
The furnace design for all cases in this project features an opposed wall firing
burner arrangement so as to give improved combustion performance with greater
flame stability at low loads. It enables the number of burner rows needed on large
capacity boilers to be accommodated without excessive furnace height and avoids
large performance variations with varying mill combinations.
There are three burner rows on both front and rear wall, four burners per row. Each
row of burners is served by one mill so that a uniform lateral heat input can be
maintained irrespective of the combination of mills in service. A major advantage of
this burner arrangement over corner firing is the improved distribution of gas
temperature, velocity and peak metal temperatures throughout the superheater and
reheater. These improvements show their effect in better availability owing to lower
corrosion rates and reduced deposit problems.
The boiler design proposed incorporates major components which have been
proven in service, and offers as standard the following features for economic
operation and long term availability:- A pressure part envelope constructed from fully welded "membrane" tube
walls and a framing system designed to resist implosive and explosive loads.
- A well proven furnace design of adequate dimensions and moderate rating
arranged for opposed wall firing ensuring a generous residence time for fuel
burn-off.
- A fully welded gas tight enclosure with seal welded tube penetrations.
- Moderate gas velocities resulting in favourable balance between auxiliary
power consumption and effective utilisation of heating surface.
83
The platen and the final superheat and reheat heating surfaces are of proven
pendant design, which resist slag build-up. The second pass comprises typical
convective surface; primary superheat, primary reheat and economiser banks. The
second pass has the flue gas in downward flow in a series gas path arrangement.
Figure 5.3.3-1 below presents the schematic ASC PosiflowTM boiler side elevation
view which applies to all the boilers presented in this report.
Figure 5.3.3-1: Generic ASC PosiflowTM Boiler Side Elevation View
84
The main dimensions of the furnaces are summarised in Table 5.3-1.
C1:
Sub-bituminous
Furnace
Width
Depth
Height
C2:
Bituminous
C3:
Lignite
C1-R0/B1/B2
(m)
C1-A1
(m)
C1-A2
(m)
C2-R0/B1
(m)
C2-A1
(m)
C3-R0/B1
(m)
C3-A1
(m)
18.40
14.72
51.15
15.64
13.80
49.00
18.40
14.72
51.15
18.40
14.72
49.65
18.40
13.80
50.00
19.32
14.72
51.15
15.64
13.80
49.00
Table 5.3-1 Summary of Furnace Dimensions
Furnace, Enclosure Walls and Framing
The furnace of "membrane" panel construction is designed for opposed wall firing
with a total of twelve burners in three rows on the front wall and twelve burners in
three rows on the rear wall. A single row of after air ports is provided in each of the
front and rear walls above the burner pattern to permit two stage combustion and
effective in-furnace NOx control.
Adequate burner side wall clearances are obtained with the burner layout proposed
and the furnace depth has been chosen to give sufficient space for flame
development, thus eliminating impingement on the furnace wall tubes.
The furnace walls from the hopper inlet to the furnace arch nose level are a vertical
membrane wall construction. Transfer headers at the arch nose level provide
pressure equalisation for the steam/water mixture before it enters the membraned,
vertical, plain tube section in the top part of the furnace. From the upper rear wall
transfer header some tubes run vertically supporting the rear wall whilst others form
the arch. The tubes re-unite in the vestibule floor and continue upwards to form the
rear wall screen. From the top of the furnace, the steam enters the separator
vessels before transferring to the furnace and rear pass roof tubes and
subsequently to the rear pass walls. A U-shaped header at the bottom of the rear
pass membraned wall section acts as inlet header to the primary superheater
horizontal tube bank.
The furnace and enclosure walls are strengthened by means of tie bars welded to
the tubes and heavy section buckstays clipped to the tie bars which encircle the
furnace at varying heights, thereby providing freedom of movement for expansion.
The buckstays are supplemented by over turning posts to withstand explosion and
implosion forces.
Remote mild steel casings are provided to enclose the penthouse, and the furnace
hopper. These remote casings are covered with a suitable insulation and an outer
cladding.
Unlike a conventional spiral wound furnace, which requires a vertical support strap
arrangement to carry the vertical boiler loads of the lower furnace to the upper
furnace and the slings, the vertical tube furnace does not require a support strap
arrangement to carry the vertical loads of the lower furnace. The vertical tubes of
the lower furnace are able to carry the loads and the hot structure support
arrangement can follow conventional buckstay designs, as in natural circulation
subcritical boiler support.
85
POSIFLOWTM Furnace with Vertical Internally Ribbed Tubing
The Doosan Babcock’s ASC POSIFLOWTM boiler design utilising Siemens Benson
technology, designed with evaporator furnace surfaces, which utilises vertical tubing
with internal ribbing in place of the traditional spiral wound smooth bore tubing. The
internal ribbed tubing is illustrated in Figure 5.3.3-2 below. The internal ribbing
improves the heat transfer by forcing the water droplets against the wall of the tube
through increased turbulence and the induced swirl. The improvement in heat
transfer allows these vertical tubes to operate at low fluid mass fluxes similar to
those of a subcritical drum boiler. This establishes a positive flow characteristic
similar to that in a natural circulation boiler as illustrated in Figure 5.3.3-3 below.
This flow characteristic in a once-through boiler ensures that gross temperature
deviations do not occur at any location of the furnace even with large variations in
the heating of the furnace walls and that impermissible stresses do not occur.
Essentially as the tube surface receives more heat, the fluid moves through the tube
more rapidly thus providing increased cooling for the tube wall.
Figure 5.3.3-2: Internally Ribbed Tubing for PosiflowTM Furnace
Figure 5.3.3-3: Flow Characteristics of Once Through Boilers
This is unlike the high fluid mass fluxes necessary in traditional spiral wound
furnace designs which result in a negative flow response characteristic (ie upsets in
heat absorption lead to inverse changes in fluid flow as shown above). The natural
circulation characteristic in a forced-circulation evaporator has been verified by
numerous theoretical investigations and measurements performed on fired boilers
and heat recovery steam generators. The technology has recently been
demonstrated, albeit at once-through subcritical conditions, following a furnace
retrofit at Yaomeng Power Plant in China [3], the world’s first operating low mass flux
vertical tube boiler.
86
Compared to the conventional spiral wound furnace, the low fluid mass flux vertical
internally ribbed tube furnace benefits from lower capital and operating costs. The
main advantages identified are: Lower Capital Costs:- Self-supporting tubes hence simplifying part of the boiler support system.
- Elimination of transition headers at spiral/vertical interface.
- Simpler ash hopper tubing geometry.
Lower Operating Costs:- Lower overall boiler pressure drop, hence lower auxiliary power load resulting in
higher plant output and higher efficiency.
- ‘Positive flow characteristic’ automatically compensates for variations in furnace
absorptions compared to the negative flow characteristics of the spiral furnace
requiring pressure balancing and positive mixing methods.
- Simple and economic tube repair.
5.3.4 Boiler Design
All the boilers presented in this report feature the same schematic once through
supercritical (OTSC) water/steam circuitry (Figure 5.3.4-1) which includes the
following major components.
•
•
•
•
•
Economiser
Evaporator
Separator Vessels, Mixing Vessel and Circulation Pump
Superheater
Reheater
87
Figure 5.3.4-1, Typical OTSC Once Through Water/Steam Circuitry
High pressure feedwater from the feedwater system is transferred to the
economiser system via one main feed pipe. The economiser heating surface is
located downstream of the primary superheater and reheater banks at the exit of
the steam-cooled rear pass cage enclosure. The economiser heating surface
comprises horizontal banks of plain tubes in a serpentine arrangement, at the
bottom of the rear pass. Pipes transfer the economiser outlet water flows into a
single large bore downcomer pipe, where the economiser water flows are combined
and mixed before distribution to the furnace hopper inlet headers.
The evaporator takes the high pressure pre-heated water from the economiser and
via the heated straight furnace tube wall and arch sections of the furnace, delivers
fully evaporated steam to the separator vessels during normal once-through
operation.
The evaporated steam from the separator vessels pass through the roof and feed
into a mixing vessel which distribute the steam into the inlet headers of the rear
cage walls and the sling tubes. The steam heated by the cage walls and sling tubes
converge into the inlet header of the primary superheater located above the reheat
bank at rear pass, the superheated steam then passes through the secondary
superheater (ie platen) before entering the final superheater located at the
vestibule. The main steam is transported via the main steam pipes to the HP steam
turbine.
The HP steam turbine exhaust steam is transported to the primary reheater located
in between the primary superheater bank and the economiser bank in the boiler rear
cage. The steam from the primary reheater is further reheated by the final reheater
before being transported to the IP steam turbine.
The boiler convective heating surfaces comprise of pendant final superheater and
final reheater located in the vestibule and horizontal surface; primary superheater,
primary reheater, economiser located in rear pass enclosure.
88
Under normal operation at high load, water flow is literally once-through in that there
is no recirculation within the boiler cycle. Evaporation (phase change from water to
steam) takes place in the upper furnace (vertical tube) section. From there the
steam is superheated before being delivered to the steam turbine. Additionally, this
design is supercritical in that it operates above critical pressure (221 bar), above
which the density of steam and water are virtually the same. Benson flow occurs
when dynamic flow stability is achieved in the furnace. This is at approximately
35%MCR. Below this flow, the pressure drop through the system is very low and
dynamic flow stability cannot be achieved without circulation assistance. The
circulation pump takes water from the storage vessel and feeds it into the
economiser inlet. Once Benson flow is achieved, the circulation pump can be shut
down.
The main performance data of these ASC boilers are summarised in Table 5.3-2
below.
100%MCR Load
C1: Sub-bituminous
C2: Bituminous
C3: Lignite
Keephills
TransAlta Power
Point Tupper
Nova Scotia Power
Shand
Sask Power
C1-R0/B1 /B2
C1-A1
C1-A2
C2-R0/B1
C2-A1
C3-R0/B1
C3-A1
Heat Duties (MWt)
Heat to Main Steam
813
795
803
813
795
813
798
Heat to Reheater
228
228
225
228
228
228
227
Total Heat to Steam
1040
1024
1028
1040
1024
1040
1025
Heat in Fuel (Wf x LHV)
1105
1105
1105
1100
1100
1143
1143
62.74
62.74
62.74
35.91
35.91
84.14
84.14
94.50
88.96
91.21
85.88
90.67
85.37
94.87
90.95
91.90
88.12
91.59
83.09
90.31
81.98
Fuel Fired (kg/s)
[*]
Boiler Gross Efficiency
%LHV
%HHV
* Heat account to ASME @ 25°C
Table 5.3-2
Summary of Boiler Performance @ 100%MCR
5.3.5 Ancillaries of the Boiler Island
For Air/PF-fired boilers, the main ancillaries of the boiler island include the following
major components and associated systems summarised in Table 5.3.5-1 below.
For Oxyfuel boiler, the major ancillaries of the boiler island which need to be
especially designed with the consideration of oxyfuel process conditions are
summarised in Table 5.3.5-2 below.
C1:
Sub-bituminous
C2:
Bituminous
C3:
Lignite
C1-R0/B1/B2
C2-R0/B1
C3-R0/B1
Total Burners installed
24
24
24
Total Burners In operation @ full load
20
20
20
Total Mills Installed
6
6
6
Air Heaters (Tri-sector regenerative)
2
2
2
ESP
2
2
2
89
PA Fans
2
2
FD Fans
2
2
2
2
ID Fan
1
1
1
Table 5.3.5-1: Summary of Main Ancillaries for Air/PF-fired Boiler
C1:
Sub-bituminous
Burner design thermal rating (MWt)
C2:
Bituminous
C3:
Lignite
C1-A1
C1-A2
C2-A1
C3-A1
58.7
58.7
57.4
63.0
Total Burners installed
24
24
24
24
Total Burners In Operation @ full load
20
20
20
20
Total Mills Installed
6
6
6
6
Air Heaters (TAH)
2
2 (RAH)
2
2
ESP
2
2
2
2
PFGR Fan
2
2
2
2
SFGR Fan
2
2
2
2
ID Fan
1
1
1
1
Flue Gas Heat Recovery Units
3
2
2
3
FGD
0
1
0
1
DCC
1
0
1
1
Oxygen Injection Mixer
2
2
2
2
Table 5.3.5-2 Summary of Main Ancillaries for Oxyfuel Boiler
5.3.5.1 Fans
PFGR Fan (Primary Flue Gas Recycle Fan)
For an Oxyfuel Boiler, a PFGR fan operates in a similar manner to a PA fan in an
air/PF-fired boiler. Two PFGR fans are employed to recycle part of the flue gas
downstream the ID fan. The PFGR gases mix with oxygen supplied from the ASU to
form the PFGR stream. The quantity of the primary flue gas recycled depends on
the fuel/gas ratio required for the milling plant to ensure proper coal drying, grinding,
and delivering the pulverised fuel (PF) to the burners.
Note that the PFGR flue gas stream taken off at down stream a DCC (C1-A1 case)
or FGD (C1-A2, C2-A1, C3-A1 cases) is nearly moisture saturated (ie~100% relative
humidity), to avoid moisture condensation along the FGR ductwork, a hot flue gas
bypass from upstream ESP outlet is introduced to increase the PFGR gas
temperature by approximately 5 K in order to reduce the relative humidity. The
PFGR fans are designed for the operation conditions at 100%MCR load.
SFGR Fan (Secondary Flue Gas Recycle Fan)
Two SFGR fans are employed to recycle partial of the boiler exhaust flue gas to mix
with oxygen supplied from the ASU and form the SFGR stream, which work in the
similar manner as the Secondary Air (SA) stream in air/PF-fired boiler.
The quantity of the secondary flue gas recycled depends on overall FGR rate
required to ensure proper combustion in furnace. The SFGR fans are designed for
the operation conditions (at 100%MCR load) summarised in Table 5.3.5-3 below
90
ID Fan
One ID fan is employed for one boiler unit. The ID fan is designed for the operation
conditions at 100%MCR.
5.3.5.2
Tubular Airheaters
Tubular airheaters are less widely employed than rotary airheaters in air/PF-fired
boiler due to its relatively larger footprint and higher capital cost. For all the A1
oxyfuel CO2 capture power plant conceptual options investigated in this project,
Tubular air heaters instead of rotary airheaters are proposed to be employed in
order to minimise the oxygen leakage. Rotary type airheater typically suffers 5~8%
air in-leakage which will reduce boiler thermal efficiency and increase the duties of
downstream flue gas treatment equipment such as ESP, FGD plant, and CO2
purification and compression plants.
The overall cost effectiveness of TAH remains to be further studied which is out of
the scope of this project.
5.3.5.3
Flue Gas Heat Recovery Units
For maximum heat integration with the water/steam cycle, there are three flue gas
heat recovery units employed where appropriate.
Primary Flue Gas Recycle Heat Recovery Unit 550
As illustrated in Figure 5.3.2-1, Figure 5.3.2-3 & Figure 5.3.2-4 in the previous
Section 5.3.2, a primary flue gas heat recovery Unit 550 is employed in the PFGR
stream in between the airheater and milling plant, with the purposes of :
1) PFGR tempering to control the mill outlet temperature,
2) The heat recovered is used for feed water preheating for improved cycle
efficiency
One Unit 550 is employed. Note that Unit 550 is only employed for the optimised
Oxyfuel power plant A1 options. C1-A2 case defined as a retrofit from C1-R0
reference power plant [2] is assumed to retain conventional air by-pass mill with air
tempering with no Unit 550 retrofitted.
Main Flue Gas Heat Recovery Unit 550A
As illustrated in Figure 5.3.2-1, Figure 5.3.2-3, Figure 5.3.2-3 & Figure 5.3.2-4 in the
previous Section 5.3.2, a main flue gas heat recovery Unit 550A is employed
downstream the ESP, the heat recovered by Unit 550A is used for condensate
preheating. The purpose of employing the Unit 550A is to cool the main flue gases
prior to the secondary flue gas recycle (SFGR) take-off (for C1, C3 cases only). The
heat duty of the Unit 550A has direct impact on the ESP operating temperature as
well as the airheater heat duty. Lower heat duty of Unit 550A results in higher ESP
inlet gas temperature and less effective airheater design. In this project, the Unit
550A heat duty is determined to maintain ESP gas inlet temperature of
approximately 200 oC. One Unit 550A is employed. The main characteristics of the
Unit 550A are summarised in Table 5.3.5-4 below:
91
Main Flue Gas Heat Recovery Unit 550B
As illustrated in Figure 5.3.2-1, Figure 5.3.2-3, Figure 5.3.2-3 & Figure 5.3.2-4 in the
previous Section 5.3.2, a flue gas heat recovery Unit 550B is located down stream
the Unit 550A for further heat recovery from the main flue gases prior to its entering
the DCC where the remaining latent heat is ejected and moisture is removed by
condensate. The heat recovered by Unit 550B is used for steam turbine condensate
preheating. One Unit 550B is employed.
5.3.5.4 Oxygen Injection and Mixer
Unlike air/PF-fired boiler, an oxyfuel boiler uses oxygen diluted with recycled flue
gas instead of air for coal combustion. One of the major issues is to ensure proper
mixing of the Oxygen and the recycled flue gases with the compliance of safety
code particularly for pure Oxygen application. More details are presented in Section
5.7.3.
5.3.5.5
Combustion System
The combustion system comprises Doosan Babcock MKIII Low NOx PF burners
arranged through the front and rear walls of the furnace and one level of overfire air
ports above the burners on front and rear walls to enable the targeted in-furnace
NOx limit to be met as appropriate.
5.3.5.6
Coal Fuel System
The milling plant comprises vertical spindle, ring and roller, slow speed, pressurised
mills together with associated bunkers, coal feeders, outlet chutes, pulverised fuel
pipework and seal air fans. The mills are supplied complete with mill motor, gearbox
and gearbox lubricating oil system. The margin on milling capacity is such that
BMCR can be achieved firing worst coal with one spare mill. Each mill supplies one
row of burners with each burner supplied by its own pipe from the mill outlet.
5.3.5.7
Light Oil Firing System
The light oil firing system comprises oil burners and atomisers complete with all
necessary pumping, supply and return pipework, supports, attachments, valves and
fittings.
5.3.5.8 Bottom Ash System
The bottom ash from the furnace is transported by a submerged chain conveyor to
the bottom ash storage area or to a pipe conveyor inside the power plant.
5.3.5.9 Draught Equipment
The draught plant is based on dual stream air and flue gas configuration. Airheaters
and precipitators are provided in two parallel flue gas streams.
92
5.4
AMINE SCRUBBER CO2 CAPTURE PLANT (UNIT 800)
This section describes the MHI’s process technology of Amine scrubbing CO2
recovery plant which applies to the post-combustion Amine CO2 capture options,
namely B1 and B2 cases.
5.4.1 General Process Descriptions
The post-combustion CO2 capture process is based on Mitsubishi Heavy Industries
(MHI)’s Amine scrubbing technology as illustrated in Figure 5.4-1 below. Flue gas
streams from coal-fired boilers commonly contain more SOx, NOx, dust particulates
and halogens compared with natural gas-fired boiler flue gas streams. For this
reason an FGD unit is designed to pre-treat the flue gas prior to entering the CO2
capture plant to ensure proficiency, reliability and economical operation. To ensure
efficient and highly reliable operation of the CO2 capture plant for coal-fired boilers,
flue gas pre-treatment is critically important. SO2 removal efficiencies up to 99.9%
have been successfully demonstrated in MHI’s FGD over a wide range of SO2 inlet
concentrations. MHI has comprehensive, large-scale commercial FGD experience,
which when combined with a CO2 capture plant, will provide advanced high level
performance compared with conventional processes.
Figure 5.4-1: Block Diagram of MHI’s Amine Scrubbing CO2 Recovery Process
MHI’s flue gas CO2 recovery plant utilizes the KS-1 solvent as the CO2 absorbent,
which is a sterically hindered amine developed through the cooperation of KANSAI
and MHI. The process is based on commercially proven highly advanced
technologies, capable of recovering CO2 from flue gases under various conditions.
Application of this process will lead to mean life extension through low energy
consumption, extended solvent life with near infinitive degradation in comparison to
other amine-based type processes. The KM-CDR process will provide higher level
of advanced performance than its predecessor, making CO2 recovery more feasible
due to the reduction of steam consumption by 30% over conventional MEA process
93
by utilizing the heat of the CO2 lean KS-1 solvent for solvent regeneration
effectively.
Integration of CO2 Recovery Plant
The CO2 recovery plant capacity is designed so that the required volume of flue gas
is always secured in order to ensure constant designed maximum operational
performance. By ensuring that the CO2 recovery plant is performing at its designed
maximum, the plant will perform at its highest performance level. However, the CO2
recovery plant is able to follow the boiler load if the CO2 consumer accepts. The
CO2 product will transfer to the processing facilities at purity levels exceeding 99%
by volume (99.9% by volume expected).
For retrofitting such as C1-B2 case, modification of existing facility is minimal,
consisting of construction of a flue gas duct that connects the CO2 recovery plant
and existing stack, including other minor modifications to utility systems. The flue
gas is extracted from the stack by a Flue Gas Blower. In case of Flue Gas Blower
shutdown, the flue gas will automatically be emitted to the atmosphere through the
stack; thus, operational outage of the CO2 recovery plant will not affect the existing
facility. The treated flue gas from the top of the CO2 Absorber will be returned to the
stack.
CO2 Recovery Plant
The CO2 recovery plant consists of three main sections:(1) Flue gas pre-treatment section (partial pre-treatment),
(2) CO2 recovery section, and
(3) Solvent regeneration section.
The following block flow diagram Figure 5.4-2 illustrates the CO2 recovery plant
configuration. And the process flow diagram is presented in Figure 5.4-3.
FLUE
GAS
Stack
TREATED
FLUE
Flue Gas Source
(Existing Facility)
(1)
Flue Gas
Pretreatment
(Cooling)
CO2 LEAN
(3)
Solvent
CO2 PRODUCT
Regeneration
(2)
CO2
Recovery
CO2 RICH
( 4* )
To
Compression
& Dehydration
*(4) Solvent reclamation operation is conducted on an intermittent basis.
Figure 5.4-2 Block Flow Diagram of a Typical MHI's CO2 Recovery Plant
(1) Flue Gas Pre-treatment
Flue gas from the stack is at high temperature and contains various impurities that
degrade the KS-1 solvent. The high temperature of the flue gas must be reduced to
approximately 35 to 45°C, depending upon the consideration of utility requirements,
due to CO2 absorptions exothermic reaction. Low temperature will positively affect
94
the reaction equilibrium, while high temperature will shift the equilibrium so as to
lessen the amount of CO2 bonding per unit of KS-1 solvent. Primary impurities of
concern are NOx, suspended particulate matter (SPM) or dust, and SOx. The
respective impurity concentrations and the flue gas temperature depend upon the
source of the flue gas. High CO2 emission coal-fired boiler flue gas contains the
most amounts of impurities. MEA-based solvents are affected similarly, though KS1 is significantly more resilient. The aforementioned compounds readily react with
the solvent to form heat-stable salts (HSS) and other reaction by-products that
reduce the concentration of available KS-1 solvent concentration for CO2 recovery.
95
Flue Gas
Outlet
CO2
Purity : 99.9 %
C.W.
CO2 Recovery Section
CO2 Absorber
CO2 Stripper
Lean Solution Cooler
C.W.
Flue Gas
Cooler
C.W.
Lean/Rich
Solution
Exchanger
Stripper
Flue Gas
Reboiler
C.W.
Lean Solution Pump
Rich Solution Pump
Figure 5.4-3 Process Flow Diagram of a Typical MHI's CO2 Recovery Plant
96
Steam
Therefore, the flue gas characteristics should be controlled so that the degradation
rate is minimized, thus optimizing the operational cost of solvent loss while
lessening the frequency of required reclamation operations. The temperature
should be reduced to the lowest economically feasible level after consideration of
the prevailing conditions.
Flue Gas Water Cooler (FGWC):
The flue gas temperature is too high to feed the CO2 Absorber directly. Therefore,
the hot flue gas is cooled by the Flue Gas Water Cooler (FGWC) prior to the CO2
Absorber. Lower flue gas temperature is preferred due to the exothermic reaction of
CO2 absorption, and also KS-1 solvent loss due to gas phase equilibrium rises as
the temperature increases at the Absorber's treated flue gas outlet. The optimum
temperature range for CO2 recovery is between 35 oC to 45 oC, in consideration of
KS-1 solvent consumption, as well as other factors as utility requirements
concerning cooling water temperature and availability.
The FGWC, is thus installed to accomplish the cooling process through direct
contact of flue gas with cooled water. The FGWC is a tower packed with structured
packing to minimize pressure reduction and minimize load on the Flue Gas Blower.
Flue gas is introduced into the bottom section of the tower, and it rises upwards
through the structured packing. The cooled water will be evenly distributed from the
top of the packing material, where the flue gas and the cooled water come into
direct contact for cooling to occur.
(2) CO2 Recovery Unit
CO2 recovery and flue gas wash is conducted in the CO2 Absorber. The CO2
Absorber has two main sections, the CO2 absorption section (bottom section), and
the treated flue gas washing section (top section). The conditioned flue gas from the
Flue Gas Water Cooler is introduced into the bottom section of the CO2 Absorber.
The flue gas moves upward through the packing material while the CO2 lean KS-1
solvent (lean solvent) is distributed evenly from the top of the absorption section
onto the packing material. The flue gas comes into direct contact with the KS-1
solvent at the surface of the packing material, where CO2 in the flue gas is
absorbed into the solvent. The flue gas then moves upward into the treated flue gas
washing section, located on the top section of the CO2 Absorber. This section is
similar to the Flue Gas Water Cooler, where the flue gas comes into direct contact
with water to have its amine content washed out, and to be cooled down to maintain
water balance within the system. The treated flue gas then exits from the top
section of the CO2 Absorber to the Stack. Meanwhile, the CO2 rich KS-1 solvent
(rich solvent) is collected from the bottom of the Absorber. The rich solvent is then
directed to the CO2 Stripper for regeneration.
(3) Solvent Regeneration
The Rich Solution Pump transfers rich solvent from the bottom of the CO2 Absorber
to the Lean/Rich Solution Exchanger so that the rich solvent can be heated up by
the lean solvent from the bottom of the CO2 Stripper. The heated rich solvent is
97
then introduced into the upper section of the CO2 Stripper, where it will come into
contact with stripping steam. The rich solvent is then steam-stripped of its CO2
content through the packing material of the CO2 Stripper, and is converted back into
lean solvent. Steam is produced by the Stripper Reboiler, which uses LP steam to
boil the lean solvent. The lean solvent at the bottom is then directed to the Lean
Solution Pump through a Lean/Rich Solution Exchanger. The Lean Solution Pump
forces this lean solvent to the Lean Solution Cooler, where it is cooled to the
optimum reaction temperature of approximately 40 oC or below before being
reintroduced to the top of the absorption section of the CO2 Absorber.
(4) Solvent reclaiming (intermittent operation)
A reclaimer unit is to be provided in order to eliminate heat-stable salts (HSS).
When the HSS content of the solvent has reached preset limits, the reclaimer must
be operated to boil down the solvent and concentrate the HSS so that it forms a
residue that can be discharged. The expected reclaimer operation frequency will be
extremely low compared with other types of amine-based solvents such as MEA.
This is due to the low degradation properties of the KS-1 solvent.
5.4.2 Design Performance and Features
The utilities required for DeHg and FGD & Handling Plant, Amine Scrubber (CO2
Recovery) and CO2 Compression Plant are summarised in Table 5.4-1. The main
features of the amine scrubbing plant are summarized in Table 5.4-2.
Case
C3-B1
C2-B1
Lignite
Bituminous
Yes
Yes
Yes
No
Yes
Yes
Yes
No
Yes
Yes
Yes
Tonne/h
0
406.8
360
421.2
Tonne/h
0
363.6
323.3
377.3
Tonne/h
0
0
0
0
Tonne/h
0
43
44
37
Fuel Coal
DeHg and
FGD & Handling Plant
Amine Scrubber
(CO2 Recovery)
System
CO2 Compression Plant
LP Steam
MP Steam
Usual
Operation
During
Reclaiming
Usual
Operation
During
Reclaiming
Electricity
C1-R0
Subbituminous
C1-B1
Subbituminous
Yes
kwh/h
46,500
56,694
62,820
50,660
Cooling Water
MW
0
387
444
309
Caustic Soda
kg/h as 100%
0
43
44
37
Tonne/h
1.7
1.8
5.3
5.9
Tonne(Wet)/h
3.1
3.1
9.5
10.5
Limestone
Gypsum(By-product)
Note) HCl for DeHg and Absorbent supply to Amine Scrubber are required for utilities. As for wastes,
FGD waste water, Amine Scrubber waste water and Reclaimer Waste are discharged. These
are not listed in the above table.
Table 5.4-1: Summary of Utilities of Amine Scrubbing CO2 Capture Equipment
98
C1:
Sub-bituminous
C2:
Bituminous
C3:
Lignite
Units
C1-B1/B2
C2-B1
C3-B1
High voltage
MWe
8.42
7.51
9.71
Low voltage
MWe
0.6
0.84
0.03
m
50
50
50
11400
11000
12000
Estimated Characteristics
Electric power consumption
Plant Size and Weight
Plant size, height requirements
Plant size, footprint requirements (W x L)
m
2
Cooling requirement
>>cooling water<<
Total
MWt
319.2
248.4
368
NaOH Consumption (as 100% purity)
kg/h
17.67
12.68
15.34
CO2 Removal Capacity
kg/s
99.4
87.7
110.2
%
90
90
90
Recovery base
MP Steam: intermittent for reclaiming purposes
Temperature
°C
160
160
160
Pressure
bara
6.0
6.0
6.0
Mass flowrate (Reclaiming operation Yes/No)
kg/s
12/0
10.2/0
12.2/0
°C
150
150
150
LP Steam for Reboiler:
Temperature
Pressure
bara
4.0
4.0
4.0
Mass flowrate( (Reclaiming operation Yes/No)
kg/s
101/113
90/100
105/117
°C
103.0
102.8
103
Steam Condensate Return
Temperature
Pressure
bara
4.0
4.0
4.0
Mass flowrate
kg/s
113
100
117
Table 5.4-2 Estimated Characteristics of Unit 800 Amine Scrubber
5.4.3 Conceptual Layout of the CO2 Recovery Plant
The schematic layout overview of the integration of Amine Scrubbing CO2 Recovery
Plant is presented in Figure 5.4-4. Two identical unit of CO2 Recovery Plant are
employed to one boiler unit.
99
Figure 5.4-4
Schematic Layout of Amine Scrubbing CO2 Recovery Plant
100
5.5
CO2 COMPRESSION PLANT (UNIT 900)
The CO2 Recovery Compressor Plant (Unit 900) described here is coupled with the
post-combustion Amine CO2 Recovery Plant (Unit 800). For the Amine Scrubbing
CO2 Recovery Capture Options, i.e B1, B2 cases in this project.
This should be distinguished from the CO2 Compression and Purification Plant (Unit
1200) for the Oxyfuel options (ie A1, A2 cases) in this project.
This section covers the specification of CO2 Recovery Compressor unit (Unit 900) to
be installed following to Post Combustion CO2 Capture Unit, ie, MHI’s propriety KMCDR Process. The aim of CO2 Recovery Compressor Unit is to recover the purified
CO2 from top of Regeneration Tower of CO2 Capture Unit and then build up the
pressure to 13.8Mpa so that CO2 could transport through CO2 Transfer Pipeline.
Two (2) compression trains of 50% capacity each will be installed. If CO2
compression & Dehydration unit is composed by one train, the capacity of CO2
compressor is beyond the experience of CO2 compressor vendor. The recovered
CO2 shall be compressed to 140barg by the compressor. The compressed CO2 gas
shall be cooled to 35°C by each stage discharge cooler, and then condensed water
shall be eliminated in the each stage scrubber.
Dehydration unit shall be installed after second stage CO2 compressor for removing
water in the CO2 gas. The CO2 gas which is compressed to 140barg shall be cooled
to 35°C, and then fed to the CO2 pipeline. The compressors are drive by the electric
motor.
5.5.1 General Process and Control Description
The process flow diagram for CO2 Compression and Dehydration is shown in Figure
5.5-1 below.
101
Figure 5.5-1 Flow Diagram of CO2 Compression and Dehydration Process
102
5.5.1.1
CO2 Compressor
Process Description
CO2 Recovery Compressor unit consist of LP and HP compressor section. LP
compressor has two stage centrifugal type compressors with common casing. Two
stage centrifugal types are employed for HP Compressor. Each LP and HP
compressor has common motor between them.
CO2 gas from regeneration tower of Unit-1100 is introduced to LP centrifugal type
compressor then the pressure is build up from almost atmospheric level to
2~2.4MPa with two stage. The compressed CO2 is once fed to TEG Dehydration
Unit for the removal of moisture and then fed to HP compressor.
HP compressor will build the CO2 pressure from 2~2.4MPa up to 13.8MPa then
send to downstream CO2 pipeline.
Design Basis and Utility Compositions
The feed gas condition at each LP and HP compressor are same as of product
conditions of CO2 capture.
Control, Start-up and Shut-Down Philosophy
The operating pressure of CO2 transfer pipeline and the intermediate pressure
between LP and HP compressor are maintained by spill back control.
Full recycle operation by each HP and LP compressor, before starting of gas
transfer and after shut down, would be considered to make start-up easier. After
field preparation works and machineries have started, all operation and controls will
be done by remote from DCS.
When emergency shutdown occurs, automatic emergency de-pressuring by safe
guarding system would be realized.
5.5.1.2 TEG Dehydrator
This section covers the specification of tri-ethylene glycol (TEG) dehydration unit to
be installed following to 2nd stage of CO2 Transfer Compressor. The aim of TEG
Dehydration Unit is for the removal of moisture from captured CO2 gas to prohibit
corrosion or hydrate formation at downstream facilities. The employed process is
TEG (Tri-ethylene Glycol) absorption method which is one of the proven methods
for oil and gas processing.
TEG absorption method is superior than Molecular Sieve in the point of economy
and operability.
One TEG dehydrator for one compressor train, total 2 trains of 50% x 2 capacity
each would be installed.
Process Description
TEG dehydration unit consist of two process sections, these are TEG absorption
section and regeneration section. The absorption section consist of feed TEG
cooler and contactor tower which has structured packing in its inside, and where
103
regenerated CO2 from the Capture plant is introduced and water is absorbed. The
regeneration section has section still column type regenerator, dealt with repurifying of the rich TEG in which a lot of water is absorbed and then regenerate the
lean TEG for re-feeding to the contactor.
The feed CO2 is taken from outlet of 2nd Stage Discharge Scrubber of CO2
Compressor, and then introduced to TEG Contactor. To ensure further high
performance on TEG absorption, higher pressure at contactor is preferable.
The regenerated lean TEG is once cooled by cooling water and is fed from upper
section of TEG contactor, while the feed CO2 gas is fed from lower section of tower.
Water contained in feed CO2 is contact with TEG and absorbed into TEG liquid.
Water contents in treated CO2 gas is down to the equal level of vapour-liquid
equilibrium at top of contactor then treated CO2 is compressed in further stage of
the transfer compressor, while rich TEG in which water is absorbed up to saturated
level at bottom of contactor, is returned to the TEG regeneration section to obtain
regenerated lean TEG.
Rich TEG drawn from contactor is once fed to TEG Flash Vessel then few H2O and
co-absorbed CO2 is flashed out.
Rich TEG solution drawn-off from the contactor bottom has enough pressure, and
then is once de-pressured at flash drum to flash-out the co-absorbed CO2.
Approximate 1% of captured CO2 is co-absorbed by TEG; most of those coabsorbed CO2 is flashed here and returned to 1st suction of the CO2 compressor.
While rich TEG from flash drum is fed to still column (TEG Regenerator) and
regenerated up to 99% of purity. After that heat recovery is made at Lean/Rich
Glycol Exchanger, and then it is fed to top of still column.
Water absorbed in TEG is stilled in this column and drawn off into still re-boiler by
gravity and then rich TEG is wormed up to 204°C by natural gas fuel heater.
Residual water in rich TEG is boiled up and stripped here to obtain further refined
TEG. Atomizing N2 would be used for mixing of this still re-boiler and as a stripping
gas in still column if necessary.
Re-generated lean TEG is pumped up to the pressure of contactor level by gear
type lean TEG pump and re-fed to contactor.
The dehydrated CO2 is transported to Injection Well Head through transfer
compressor 3rd, 4th stage and through CO2 pipeline.
Brief explanation about system is as follows.
1) TEG Contactor
The contact column will consist of, in the following respective sections: demister
(upper area), structured packing (central area), liquid distributor with liquid purge
tubes (below packing) and pre-purifier (bottom). The gas coming from the gas mist
separator will enter into the contactor column through the distribution tray. Two
demisting sections will be taken into consideration at the same time to minimize the
entrainment and to satisfy the gas specifications.
104
2) TEG Regenerator
The regeneration is made with drying up of gas as well as an equipped heater (TEG
heater).
3) TEG Flash Vessel
The vessel will be sized in order to ensure a TEG retention time of 30 minutes in the
inlet compartment. It will be designed on the basis of a full vacuum condition. No
atomizing gas reserve will be required.
4) Lean/Rich Glycol Exchanger
The system concerned will be designed so that the difference between the inlet
temperature and the outlet temperature does not exceed 5°C, this is to reduce the
loss of TEG in the contactor to the absolute minimum. The process control system
for this cooling system will allow to not cool excessively the flow of lean TEG.
5) Lean TEG Filter
Two 100% capacity filters will be provided in downstream of circulation pumps. This
filter will have an adequate mesh to avoid any clogging at the distributor in the
contactor, located in downstream of this filter.
6) Rich TEG Filters
Two 100% capacity particle filters will be provided in the regeneration unit of TEG to
remove solid matters in arrival TEG flow.
7) Carbon filter
In order to reduce the generation of foam, an activated carbon filtration unit will be
installed in TEG regeneration system in order to remove organic materials from the
liquid as well as polymers possibly generated in contact with the feed gas and TEG
flows.
8) TEG Circulation Pumps
Two 100% capacity glycol circulation pumps, positive displacement and electric
motor driven, of which the one is in stand-by, will be provided to circulate TEG from
TEG flash vessel to TEG contactor via lean TEG filter and lean TEG cooler.
5.5.2 Control, Start-up and Shut-Down Philosophy
The system is controlled by the following major process parameters that are
maintained at desired set points by instruments:
1) Liquid temperature in the TEG Regenerator
2) TEG Flash Drum level
3) TEG Contactor level
4) Lean glycol temperature to the contactor
105
Above process parameters are controlled by DCS. TEG regeneration unit will be
provided with complete instrumentation within the vendor’s battery of skid module,
necessary for good performance and operation of the unit.
Remote control function will be done by DCS (furnished as common facilities).
Re-boiler Burner Management System (BMS) would be installed inside skid.
Instrument wiring would be terminated at skid-mounted junction box.
5.5.3 Design Performance and Features
The CO2 compression plant main features and performance are summarised below:
C1:
Sub-bituminous
C2:
Bituminous
C3:
Lignite
Units
C1-B1&B2
C2-B1
C3-B1
High voltage
MWe
41.7
36.7
46.2
Low voltage
MWe
0.0
0
0
Total
MWt
68.1
60.1
75.6
Cooling water consumption (dT=11 k)
kg/s
1483
1308
1645
10
10
10
10000
10000
10000
Estimated characteristics
Electric power consumption
<Cooling water>
Waste stream
Off gas (moisture)
Plant Size and Weight
Plant size, height requirements
m
2
Plant size, footprint requirements
m
Table 5.5-1: CO2 Compression Plant Performance
5.6
AIR SEPARATION UNIT (UNIT 1100)
This section 5.6 presents the Air Separation Unit designs proposed by Air Products
[4]
for the Oxyfuel CO2 capture power plant options in this BERR-366 Project.
5.6.1 ASU Process Description
The amount of oxygen required for oxyfuel firing of the ASC PF boiler for Case C1A1 is approximately 7700 tonne/day. The proposal for the production of oxygen in
this case is to use two cryogenic ASUs of 3850 tonnes/day. This is within the range
of plants currently being offered for sale. The single train axial flow air compressors
required for this duty are available commercially.
The cycle chosen is one in which gaseous oxygen (GOX) is produced by boiling
liquid oxygen (LOX) which is ideally suited to this application as the delivery
pressure required is low. There is no requirement for either pumping the liquid O2 or
compressing the gaseous product.
A low purity cycle was chosen, which produces 95% oxygen purity. Studies have
been carried out to show that for oxy-combustion plants this is the optimum purity.
Even new balanced-draught boiler plants are expected to have air in-leakage, and
therefore there will always be some inerts that must be removed in the CO2
purification plant. Also, the increase in power required for the ASU to produce
99.5% purity oxygen is greater than the increase in CO2 compression power
106
required to remove the inerts introduced due to the lower purity oxygen. Table 5.6-1
summarises the ASU utility requirements.
Power Requirements (MWe)
Cooling Water (MWt)
Condensate Preheating (MWt)
LP Steam (MWt)
Contained oxygen (tonne/h)
C1: Sub-bituminous
C1-A1
C1-A2
74.06
74.75
13.98
13.99
47.38
47.92
0
11.76
319.31
322.58
C2: Bituminous
C2-A1
64.58
13.94
46.38
0
312.51
C3: Lignite
C3-A1
80.70
14.22
54.70
0
364.130
Table 5.6-1: ASU Utility Requirements
Cycle Description
To minimise the ASU power consumption because of its importance in this
application, an innovative cycle has been chosen that uses two high pressure
columns. A process flow diagram is shown in Figure 5.6-1.
The standard double column cycle has a low pressure column (C105) with its
reboiler (E103) integrated with the condenser of a high pressure column (C104).
The column pressures are set to give a temperature driving force in the
reboiler/condenser E103. In this cycle an extra column is added operating at an
intermediate pressure (C103). The condenser (E104) for this column also integrates
with a reboiler in the low pressure column but at a lower temperature, boiling a
liquid stream higher up within the low pressure column.
This arrangement minimises the amount of feed air that must be compressed to the
higher pressure of C104, leading to the low power requirement of this process
cycle.
Figure 5.6-1: Air Separation Unit Process Flow Diagram
Due to the size of the plant and the two pressure levels of compression, another
feature of this cycle is that there are dryers in two locations; after compression for
feed to the intermediate pressure column and after compression to the high
107
pressure column pressure, thus requiring smaller vessels than if only one system
were used for the total flow of air.
The plant consists of:
•
•
•
A compression system
An adsorption front end air purification system
A cold box containing the separation and the heat exchanger equipment
This process offers the benefits of high reliability, low maintenance cost and is
simple to install and operate.
Air Compression and Cooling
Air is taken in through an inlet filter to remove dust and particulate matter prior to
entering the main air compressor (MAC) where it is compressed to 3.5 bara using
an adiabatic compression arrangement. An axial compressor is used to compress
the feed air without intercooling so as to provide a higher temperature air stream to
use as a source of heat for preheating condensate for the ASC PF power plant.
The air discharge is further cooled in the Direct Contact Aftercooler (DCAC) with
chilled water from the Chiller Tower which uses evaporation of water into the dry
waste nitrogen stream leaving the ASU cold box to further cool part of the plant
cooling water. The air is cooled to a temperature of around 12°C. The main air
compressor will be an in-line axial compressor driven by an electric motor. Around
half of this compressed air stream is then further compressed in a single radial
wheel to 5.0 bara, cooled to ambient and compressed in the compressor wheel of
the coupled compressor/expander K103/K104 to 5.4 bara. The air is then cooled to
12°C in a second direct contact column.
Air Cleanup
Before the air is cooled to cryogenic temperatures, water vapour and carbon dioxide
and other trace impurities such as hydrocarbons and nitrous oxide are removed in a
pair of dual bed adsorbers. One pair is used to purify the 3.5bara air stream and the
other purifies the 5.4bara stream.
Removal of carbon dioxide and water avoids blockage of cryogenic equipment. The
removal of impurities results in a clean, dry air stream free from contaminants which
might cause blockages or safety problems in ASU operation. The adsorber
operates on a staggered cycle, ie one vessel is adsorbing the contained impurities
while the other is being reactivated by low pressure gaseous waste nitrogen using a
temperature swing adsorber cycle. The nitrogen is heated to around 160°C against
condensing steam in a reactivation gas heater followed by a period in which the bed
is cooled down with ambient temperature nitrogen which bypasses the heater. The
adsorbents used are generally selected for optimum operation at the particular site.
They consist of layers of alumina or silica gel plus layers of zeolite. The adsorber
vessels are vertical cylindrical units having annular adsorbent beds.
108
5.6.2 Principle of Cryogenic Air Separation
The industry standard method of cryogenic air separation consists of a double
column distillation cycle comprising a high pressure (HP) column (C104) and a low
pressure (LP) column (C105) as shown in Figure 5.6-1.
The high pressure, higher temperature cryogenic distillation column C104 produces
an overhead nitrogen product that is condensed against the low pressure, lower
temperature liquid oxygen in the LP column sump. The plate-fin condenser-reboiler
(E103) sits in the LP column sump and thermally links the HP and LP columns. The
HP column nitrogen provides the boil up for the LP distillation column and the LP
column oxygen provides the condensing duty for the HP column. Some of the
condensed nitrogen returns to the high pressure column as reflux. The balance of
the pure nitrogen reflux is cooled in the subcooler (E102) and flashed into the top of
the low pressure column as reflux. The columns have aluminium structured packing
optimised for cryogenic separation. In this cycle an extra column is added operating
at an intermediate pressure (C103). The condenser E104 for this column also
integrates with a reboiler in the low pressure column but at a lower temperature,
boiling a liquid stream higher up within the low pressure column.
Cooling and Refrigeration
Following the two front end adsorber systems (C101 and C102), both the
intermediate and high pressure air streams are split in two. These four streams (4,
6, 14 and 18 as shown in Figure 5.6-1) are fed directly to the main heat exchanger
(E101). This consists of a number of parallel aluminium plate-fin heat exchanger
blocks manifolded together.
The intermediate pressure stream 4 is cooled close to its dew point (-178°C) and
fed to the bottom of the intermediate pressure column (C103). The second
intermediate pressure stream 6 is removed from the main heat exchanger at -171°C
then expanded in a centrifugal single wheel expansion turbine K104 running on the
same shaft as a single wheel centrifugal compressor K103 which adsorbs the
expander power. The expanded air is fed to the middle of the low pressure column
(C105) at a pressure of about 1.4 bara and –188°C to provide refrigeration for the
operation of the ASU. The high pressure stream 18 is cooled close to its dew point
(-173°C) and fed to the bottom of the high pressure column (C104). The second
high pressure air stream is cooled and condensed in the main heat exchanger
against boiling oxygen. The resulting liquid air from the main exchanger is fed to the
middle of both the high pressure and intermediate pressure columns.
Distillation System
In the high (C104) and intermediate pressure (C103) columns, the gaseous air feed
is separated in the distillation packing into an overhead nitrogen vapour and an
oxygen-enriched bottom liquid. The nitrogen vapour from the high pressure column
is condensed against boiling oxygen in the low pressure column sump and split into
two parts. The first part is returned to the high pressure column as reflux, whilst the
second part is subcooled, reduced in pressure and fed to the low pressure column
(C105) as reflux. The nitrogen from the intermediate pressure column (C103) is
condensed against a boiling liquid stream in the low pressure column. Part of this
109
nitrogen is used as column reflux in the intermediate pressure column and part is
subcooled and added to the reflux to the low pressure column.
Crude liquid oxygen is withdrawn from the sumps of the high and intermediate
pressure columns, cooled in the subcooler (E102) against warming waste nitrogen
and is flashed to the low pressure column as intermediate feeds. A portion of liquid
air is also withdrawn from the middle of the high pressure column. This liquid is
subcooled in the subcooler and fed to the middle of the low pressure column.
Low Pressure Column
The feeds to the low pressure column are separated into a waste nitrogen overhead
vapour and a liquid oxygen bottom product, which reaches the required purity of
95% by volume. At present the nitrogen is vented to atmosphere, however, there is
potential to utilise this warm dry nitrogen stream within the coal drying process.
The waste nitrogen is withdrawn from the top of the low pressure column and
warmed in the subcooler and the main heat exchanger. A portion of the nitrogen
stream from the main exchanger is used for adsorber reactivation. The remaining
dry nitrogen is vented through a Chilled Water Tower to produce chilled water by
evaporative cooling. The chilled water is used to provide additional feed air cooling
in the top section of the DCACs.
Pure liquid oxygen is withdrawn from the reboiler sump of the low pressure column
and is returned to the main heat exchanger where it is vaporised and warmed up to
ambient conditions against boosted air feed to the columns. The gaseous O2 is then
regulated and supplied to the power plant. The pressure in the low pressure column
is typically 1.35 bara. The hydrostatic head between the sump of the LP Column
and the LOX boil heat exchanger results in the O2 product being available at
approximately 0.6 barg.
Oxygen Backup
The PF boilers will be designed in such a way as to allow air-firing as a fall-back
position should there be an interruption in supply from the ASUs. Therefore,
adequate backup for the ASUs should be provided in order to allow a controlled
change-over to air-firing. The ASU back-up system is presented in Figure 5.6-2
below:
110
Figure 5.6-2: ASU Back-up System
Backup will be in the form of liquid oxygen (LOX) enough of which will be stored on
site to allow controlled changeover to air-firing. The LOX will be held at a pressure
of 2.5 bara in a 500 tonne capacity vacuum insulated storage tank which can be
filled by gravity from the ASU. The tank size is a conservative estimate to allow for
flexibility in plant operation which is further discussed in section 5.6.7. If backup
oxygen is required from storage, detected by a pressure controller on the GOX
header, the control valves will open to allow LOX to enter the vaporiser. Because of
the short time lag in the system to initiate the GOX backup flow through the
vaporiser, a temporary means of providing GOX is required. The GOX pressure is
maintained in the system using a GOX buffer vessel kept at 30 bara pressure,
which discharges into the GOX header under pressure control.
Air Separation Equipment
Multiple structural steel cold boxes and one column can are supplied as part of the
equipment. The column can is a cylindrical enclosure of pre-formed/pre-rolled
flanged sections which bolt together at site to complete the structure. Steel jacket
panels can be welded or bolted for equipment access to the framework. The cold
boxes and column vessel are inclusive of process equipment. The process
equipment is supplied and constructed of material suitable for use at low
temperature.
The column can encloses the high, intermediate and low pressure columns. The
reboiler and condensers are contained in the low pressure column. All heat
exchangers in the cold air separation equipment are multi-passage, extended
surface aluminium / aluminium alloy, plate-fin heat exchangers.
The main heat exchanger and subcooler are prefabricated. The main heat
exchanger (MHE) box houses the main heat exchanger and the expander units.
The subcooler box contains a multi-passage, extended surface plate fin heat
exchanger.
The primary insulation material is expanded perlite. Certain areas are packed with
rockwool to allow access for maintenance of valves without perlite removal.
111
A dry nitrogen purge system is included on all cold boxes and cans to prevent moist
atmospheric air from leaking into the cold box/can during normal operation.
5.7.3 Oxygen Injection System
In cases C1-A1, C2-A1 and C3-A1 the oxygen is injected cold into a cold flue gas
stream. However in the C1-A2 case the oxygen will be preheated and injected into
a hot flue gas stream. This case requires some additional considerations.
The oxygen will be 95% purity, 1.6bara and up to 150°C when it is injected into the
primary and secondary flue gas recycles.
The primary and secondary flue gas recycles will be relatively hot at 310°C and
363°C respectively at the O2 injection point and will contain ash particulates at a
loading of about 1.6 wt% of the flue gas flow. The ash will contain about 1% carbon,
the remainder will be inert mineral matter. Ash will be a fine particle size. The duct
material is carbon steel but this is not expected to be a safety issue at such low
pressures. It is proposed to line the carbon steel ducting with stainless steel at the
oxygen injection point. Although it is known that carbon steel is not flammable at
near atmospheric pressure at purities below about 95% it is recommended that the
stainless steel be extended to a location where the maximum O2 purity is 60%. This
is to allow a safety margin for fluctuation in the O2 concentration. Computational
Fluid Dynamics (CFD) modelling is recommended to better define the oxygen
dispersion within the ducting. This modelling should be used to determine the length
of ducting downstream of the injection point that would require stainless steel lining,
ie the point at which mixing has occurred. Particle ignition of the stainless steel, or
the carbon steel in the lower purity enriched air, is not considered possible in this
case.
The design of oxygen injection point should be developed to optimise mixing of O2
and Flue Gas. An oxygen lance/perforated nozzle design could be considered (with
multiple small holes across the injection chamber, rather than a few larger injections
ports), as used on ASUs. CFD could again be used to analyse any further design
work although this is not within the scope of this study.
It was recommended that the oxygen be injected downstream of the flue gas fans
due to the risk of particulate impingement on the fan blades. Also, the oxygen
injection line should be kept particle free by purging or other means if carbon steel.
Since stainless steel is not flammable in low pressure oxygen, stainless steel
metallurgy can tolerate ash particles and would not have to be maintained particle
free because of oxygen compatibility concerns.
A HAZOP methodology for the Start-up/Shutdown/Trip scenarios should be
implemented to ensure a safe system is developed.
5.6.4 Oxygen Distribution to the Boiler
The oxygen generated in the ASUs must be distributed to the boiler. In order to be
able to use carbon steel piping, the pipeline network must be designed to a velocity
limit to avoid the risk of fire caused by impingement of foreign objects within the
piping against the pipe walls. In addition to the velocity restriction, there is also a
restriction on the configuration of the piping so as to avoid situations in which
112
impingement would be worse. Therefore, only long radius bends are used and Tjunctions can only be used when flow goes from the main into the branch.
Oxygen Preheating (Case C1-A2 only)
As previously discussed, in the C1-A2 case the O2 is preheated before injection into
the hot flue gas stream. Preheating the oxygen to the boiler improves the overall
efficiency of the process. Without oxygen preheating, the oxygen is effectively
heated to the combustion temperature using the high temperature from combustion
as the heat source. Using a lower grade heat source to preheat the oxygen
improves efficiency by freeing the higher temperature to raise more steam.
Oxygen can be preheated using any available source of heat integration. Previous
work has compared the efficiency improvement achieved using the net flue gas
against that achieved using IP steam and found that the latter gives higher
efficiency. Using multiple pressure levels of steam, ie having multiple oxygen
preheaters in series, would further improve the overall efficiency at the expense of
extra heaters.
Air Products’ oxygen standards allow the use of carbon steel up to a temperature of
149°C with oxygen purity required for oxy-firing a coal-fired boiler. However, with
stainless steel alloys, the temperature can reach >800°C at the low pressures of
oxygen required. For instance, using 304/304L or 316/316L the temperature can
reach 540°C. Therefore, preheating the oxygen is feasible, and is practiced in the
production of hydrogen using oxygen blown autothermal reformers, where shell and
tube heat exchangers are used to preheat the oxygen using steam.
In the C1-A2 retrofit cases, oxygen will be preheated using LP steam. This will be carried
out in a shell and tube heat exchanger located as close to the oxygen injection point as
possible to minimise the length of piping at the higher temperature.
5.6.5 Safety & Operability
ASU Safety Issues
Safety is a major factor in the design and operating strategy of ASUs:
• Rapid oxidation (which falls into two categories: Accumulating fuel in O2 enriched
streams, and O2 enriched streams reacting with normally non-combustible
materials).
• Interfaces between the ASU and downstream equipment, with the risk for sending
high pressures and cold temperatures that are incompatible with the downstream
equipment.
• Building high pressures due to vaporising cryogenic liquids.
• Oxygen enriched and deficient atmospheres.
There is a strong commitment to safety from the ASU equipment manufacturers
based on nearly 100 years of operating experience as the air separation industry
has developed. Safety standards are the responsibility of the industry as a whole
and are a result of the cooperation between companies on a continuing basis.
Notable areas of activity in recent years have included:
• Standards for materials compatibility with oxygen, covering flammability and
material properties
113
• Design standards for oxygen compressor systems, both centrifugal and
reciprocating
• Considerations for the design of reboiler/condenser systems
These specific safety considerations are backed by procedures used in the design,
construction, operation and maintenance of air separation equipment.
The following specific items form an integral part of the design of the plant to ensure
safe operation:
• The design allows for the elimination of potential hydrocarbon build-up due to the
location of the fuel burning power generation facility.
• The oxygen plant is designed for fail-safe emergency shutdown as a result of
internal or external upset. All process control power supplies are connected to an
uninterruptible power supply that will provide a power back-up for 30 minutes.
• The design of oxygen injection system into the fuel burners which would include
direct oxygen injection into the burner and mixing of oxygen with recirculating hot
flue gas.
• The location of vents and drains to avoid discharge of oxygen deficient or oxygen
rich gas or liquid streams that might be hazardous to the surroundings.
The plant and equipment is designed in accordance with recognised
national/international codes and standards appropriate to its location and its point
of manufacture.
Oxygen Cleanliness
Standards have been developed for the required cleanliness of all oxygen
containing systems. It is particularly important that the design of the oxygen
injection and mixing system associated with the coal burners must ensure that no
hazardous mixing of coal dust and oxygen can take place in the upstream piping
system due to back flow or upsets during boiler operation, particularly during startup
and shutdown. Suitable purge systems will be installed using pure nitrogen to
ensure safe operation.
All equipment supplied as part of the air separation package will be designed,
manufactured and constructed in accordance with the latest safety standards and
following a rigorous quantified hazard review procedure.
5.6.6 ASU Plant Process Control
Control System Design Philosophy
The control system is designed to meet the following overall objectives:
•
To provide a safe system.
•
To meet the plant reliability and availability targets.
•
To enable the plant to run routinely within the particular operation constraints.
Control Strategy
114
The following control strategy outlines the control loops in place on a typical
companded LOX boil ASU such as the one considered for this study. There will be
an overall supervisory control program which will allow the ASU and CO2
compression and purification systems to be adjusted automatically in response to
planned load changes on the power boiler system in response to changing electrical
demand from the grid. This control program will also allow for a controlled rate
change of oxygen from the ASU by ramping the plant up or down at a rate between
2-3% of full flow per minute.
ASU Air Supply
Main Air Compressor
Air to the cold box supplied by the Main Air Compressor (MAC) is flow controlled by
varying the guide vanes on the compressor. As the guide vanes are opened up, the
flow rate through the compressor will increase which will ultimately increase the
product flow of O2 with a delay subject to the time constant of the system. There
will be an associated increase in the discharge pressure of the MAC and this is
monitored by a separate pressure control loop which will vent the MAC product air
should the calculated approach to the compressor surge line become unacceptably
close.
Air Purification System
The air to the main exchanger is passed through the adsorber beds where water,
carbon dioxide, acetylene and heavy hydrocarbons and some N2O are adsorbed.
The beds operate on a Thermal Swing Adsorption process (TSA), with bed
regeneration obtained by heating the adsorbent at low pressure. Regeneration heat
is provided by heating part of the low pressure waste N2 stream leaving the Main
Heat Exchanger (E101) as shown in Figure 5.6-1a (PFD 1) in a steam reactivation
heater and passing it through the bed in the reverse direction.
This is followed by a cooling period when the heater is by-passed. The on-stream
time for each bed is typically 3 to 6 hours, and while one vessel is on-line the other
undergoes regeneration. The changeover of the on-line bed and subsequent
regeneration is controlled entirely by a pre-programmed sequence in the DCS.
During the sequence when no re-generation gas is required, all waste gas is vented
under pressure control. When the sequence moves from the depressurisation step
onto the heating step the required valves are ramped slowly under automatic
control minimising disturbance to the plant. Feed forward control is used when
switching from the cooling step to the re-pressurisation step to further minimise
disturbance to the ASU when the TSA inlet valve closes.
The temperature of the regeneration gas is controlled by regulating the regen gas
flow through the reactivation heater. The steam supply through the heater has no
temperature control and can vary, therefore there is a bypass of the reactivation gas
around the heater to help to control the heating of the reactivation gas. The
temperature controller acts to limit the reactivation feed flow through the heater by
increasing the bypass flow to control the outlet temperature.
115
Automated front-end regeneration is provided for plant start-up, returning air from
the on-line bed as regeneration gas through the reactivation heater. A coldbox trip
also sets the TSA to front-end regeneration, allowing the compressor and TSA to
continue running. There is a CO2 analyser to sample the CO2 content of the air to
the coldbox leaving the
TSA. The analyser is switched to sample the reboiler sump at regular intervals,
generally coinciding with molecular sieve bed changeover.
Main Heat Exchanger
The air leaving the TSA adsorbers is passed through the main heat exchanger
(E101) as shown in Figure 5.6-1a (PFD 1), where it is cooled by counter current
heat transfer with the returning waste N2 and product GOX flows. The total air flow
is controlled by the MAC guide vanes, with the split between expander and HP
column flow controlled by the expander inlet guide vanes. The boosted air flow is
determined by a temperature controller at the cold end of the main heat exchanger
which regulates the flow of liquid air to the HP column via the JT valve.
ASU Compander
The energy produced by the expander part of the compander is used to drive the air
booster compressor part. The Medium Pressure (MP) air flow through the
expander is controlled by the expander inlet guide vanes and the booster discharge
pressure varies as the booster and expander flows are adjusted.
ASU Column System
The general principle for maintaining the correct mass balance for the column
section is detailed in the following sections. Air flow into the plant and product flows
out are all flow controlled hence any gas not taken as product leaves the plant as
waste.
Distillation Columns
The amount of nitrogen reflux flow from the condensers to the high and
intermediate pressure columns is modulated using remotely operated control valves
to maintain the correct column operating composition profile in both columns.
Liquid air is withdrawn from the middle of the HP column and fed to the LP column
via the subcooler under flow control.
Level controllers maintain the sump levels in the high and intermediate pressure
columns by controlling the transfer of liquid to the LP column. These streams enter
the LP column as crude LOX.
The LP column is split into three sections. In the top section, a waste nitrogen
stream is taken off under pressure control at the warm end of the MHE. Liquid air
from the high pressure column enters at the top of the second section and the
Crude LOX (from the high and intermediate pressure column sumps) and LP air
(from the expander) are fed to the column at the top of the third section. The LOX
product collects in the column sump and is fed to the main heat exchanger where it
116
is boiled and warmed to form the GOX product against cooling and condensing
liquid air.
GOX Product
LOX from the LP column sump is vaporised and warmed in the main heat
exchanger as described above. The GOX product is delivered to the plant on both
pressure control and flow control. The pressure control acts by controlling the
amount of LOX taken off the LP column sump and the flow rate is controlled by
adjustment of the air flow from the MAC. A vent valve is provided to discharge
excess oxygen if downstream problems arise.
The oxygen flowrate required by the oxy-combustion system determines the total
demand on the two ASUs. At any total flow below the maximum, the two ASUs will
automatically adjust their flows to produce the required total oxygen flow. As the
total oxygen flow approaches maximum, the computer system will be programmed
to indicate to the operators the oxygen flow and enable adjustments in demand to
be made.
LOX Storage Control
A tank containing up to 500 tonnes of liquid oxygen will be available to allow for
increased operational flexibility. This would, for instance, allow the ASC boiler to be
changed from oxy-combustion to air-firing with no disturbance to steam generation
or electrical power output or to allow the ASC boiler to be reduced in load to match
the available oxygen from the remaining ASU. It will allow faster ramping of the
oxygen supply than can be met by the ASU alone. Backup LOX flows from the
storage tank through a steam vaporiser into the back-up oxygen pipeline. To
minimise any pressure disturbance an ASU trip signal initiates the back-up system
response activating the LOX flow to the vaporiser.
Note: despite the high reliability of the ASU, in the event of one unit being out of
service it is envisaged that the ASC boiler would be able to operate at 50% MCR
load on a single ASU.
A pressure controller on backup GOX header opens the control valve on the
discharge of the vaporiser. Because of the time lag in the system to initiate the
GOX back-up flow through the vaporiser, a temporary means of providing GOX is
required. The GOX pressure is maintained by a GOX buffer vessel at 30 bara
pressure, which discharges into the GOX header under pressure control (PIC).
Once the backup supply from storage is at full capacity the buffer vessel supply
route is backed out, and the vessels are recharged by a small compressor, set to
start on a low pressure switch and stop on a high pressure switch.
Liquid oxygen is stored in a vacuum insulated cryogenic vessel under a pressure of
2.5 bara. Two pressure controllers control the storage tank pressure. One acts on
the tank vent valve to reduce the storage pressure. The other allows liquid to pass
through a vaporiser and return to the tank as pressurising vapour. The set point of
the vent valve controller is set to a higher value to avoid controller run-away.
117
5.6.7 ASU Ramping
The maximum ramp rate for an ASU is 3%/min, however the boiler requires up to
6%/min. The deficit can be overcome by vaporising LOX from storage.
5.5
Oxygen, t/min
5
4.5
Oxygen
Required t/min
4
Oxygen From
ASU t/min
3.5
3
0
5
10
15
20
Time, minutes
Figure 5.6-4: ASU Ramping Oxygen Requirements
Figure 5.6-4 shows the plant oxygen requirements assuming a ramp from 50-100%.
Also plotted is the ASU supply rate, neglecting the complications of going from one
ASU at full load (50% oxygen supply) to two ASUs operating and then ramping
down the first ASU as the second ASU comes on line. The difference between the
ASU supply rate and the demands of the boiler is less than 11 tonnes of oxygen in
this case. Therefore a 100 tonne LOX tank would be more than adequate to deal
with the requirements of ramping that the boiler imposes upon it. It is proposed that
a 500 tonne tank be installed to allow for ramping and startup requirements and to
deal with the uncertainty in the demand profile for the power production system. If
the plant was to run continuously on base load backup would only be required to
allow safe changeover from oxygen firing to air firing should there be an ASU trip.
160 tonnes, equivalent to 30 minutes supply, would be adequate. In a load-following
scenario the provision of a 500 tonne tank improves flexibility especially in the
operational area where demand goes across 50% and so requires the second ASU
to be started up.
5.6.8 ASU Start-up
A main feature of the oxyfuel power plants is air firing for both plant start-up and
shut down. The maximum load level that can be achieved with air firing is
dependant on the load which the burners could accomodate. On plant start up air
firing would be used but in order to minimise uncontrolled emissions from the plant
during switch over to oxyfuel it would be advisable to operate at the minimum
allowable flowrate that the burners could handle.
One reason for including a liquid oxygen tank onsite is that it will allow time for the
second ASU to be started-up whilst vaporising liquid from storage without affecting
the ramp rate of the boiler. Table 5.6-5 shows typical durations for starting up an
118
ASU. The durations given are the time it takes for the plant to reach purity, in this
case 95% oxygen. The burners in the furnace are able to operate under air-firing,
hence a purity of approximately 23% oxygen. This means that the ASU will be able
to supply gas to the boiler system despite purity being lower than the design
specification of 95%. The only detrimental effect will be a reduction on the amount
of CO2 that can be captured, as this is directly influenced by the purity of the oxygen
used in the combustion process. This is because it leads to an increase in the inerts
into the feed to the CO2 purification system, which results in a reduction in recovery.
Scenario
Time to Purity
After defrost
24 hours
After 24 hour shutdown
6 – 8 hours
After 16 hour shutdown
4 – 6 hours
After 8 hour shutdown
3 – 5 hours
Less than 1 hour shutdown
Less than 1 hour
Table 5.6-5: Typical start-up times for an ASU
In the current project air firing for startup is a conservative approach that will be
used in the first few oxyfuel boilers only. For future projects it would be aimed for
startup on oxygen firing alone.
The time taken to start up the oxyfuel power plant and transitioning from airfiring to
oxyfiring with the appropriate emission control systems operating would require
dynamic simulation modelling of the boiler.
The CO2 plant will be able to start operating when the feed flowrate to the
compressor is within the compressor's operating range. The CO2 plant would not be
able to handle all of the power plants flue gas on air firing alone but it could be
started, and so start removing SOx and NOx as acid streams, As the plant is
"ramped" from air only to oxyfuel firing when the net flue gas flowrate comes within
the range of the compressor (the first stage in particular).
It is possible that the compressor could be operated from the very start with a
suitable control system controlling upstream equipment (such as the DCC) thus
delivering the required downstream flowrate range, which the compressor could
handle.
As the air firing is backed down (transitioning from air to oxy firing) the control
system would ramp up the oxygen supply, since this is controlling the excess
oxygen required for combustion. Also the flue gas recycle would start, since this is
required to control the boiler temperature. The damper that allows the net flue gas
to go to the stack to protect the downstream equipment will close as the net air flow
reduces.
5.6.9 Plant Flexibility
Each of the 500MW boiler/steam turbine/generator systems in Case C1-A1 would
require 7700 tonnes/day oxygen. It is proposed that we supply two cryogenic
oxygen plants, each producing 3850 tonnes/day O2 and each equipped with a
single electric motor-driven axial flow air compressor. These compressors will be
119
capable of continuous air flow reduction of 70% of maximum flow. The cryogenic air
separation plant will operate at constant oxygen recovery from the air over this flow
range. The power consumption at 70% air flow will be approximately 72% of power
at 100% loading. This characteristic will give flexibility to operate efficiently in the
range 70% to 100% with two oxygen plants in operation and from 35% to 50% with
one plant in operation.
Running between the load ranges 50 – 70 % is possible using both ASUs but with
reduced efficiency due to limitations of the air compressors. For example running
both ASU’s at 70% of maximum flow will give 70% load (35% from each ASU plant).
In order to achieve a 60% loading, 14.3% of the 70% load will need to be removed.
This can be achieved by a number of methods:
1. Recycling a portion of the compressed air back to the inlet of the main air
compressor since the distillation equipment will be able to turn down more than
the 70% limit of the main air compressor.
2. Venting a portion of the produced oxygen (385 tonnes/day from each ASU
based on the above example)
3. Producing a certain quantity of liquid oxygen for backup storage (385 tonnes/day
from each ASU based on the above example).
The plants can be shutdown during periods of low power demand. The time
required for restart of a cold plant after say a 12 hour shutdown would be about 3
hours to reach full plant output at design purity of oxygen. Production of liquid
oxygen during periods of low demand for gaseous oxygen will allow liquid back-up
to be maintained.
The plants will be provided with a supervisory control system which will cover
automatic operation, including start-up, shutdown and ramping either up or down.
Maximum ramp rate should be 3% of maximum flow per minute.
5.6.10 Plant General Layout
Figures 5.6-5a, 5.6-5b and 5.6-5c present the schematic general layout of the ASU
and LOX plants proposed by Air Products for the Oxyfuel CO2 capture power plant
options in this project.
120
Figure 5.6-5a Proposal Plot Plan of A7700 ASU (Plan View)
121
Figure 5.6-5b Proposal Plot Plan of A7700 ASU (Isometric View)
122
Figure 5.6-5c Proposal Plot Plan for LOX (Isometric View)
123
5.7
CO2 COMPRESSION AND PURIFICATION PLANT (UNIT 1200&1300)
This section presents the CO2 Compression and Purification Plant proposed by Air
Products for the Oxyfuel CO2 capture power plant options in this BERR 366 Project.
5.7.1 CO2 Compression and Purification Plant Process Description
The net flue gas from the oxyfuel-fired ASC PF coal-fired boiler must be cooled,
dried, compressed, and purified to the required level. A summary of the
performance of this system is shown in Table 5.7-1.
Performance Summary for CO2 Treatment System : 95mol% CO2 Purity
C1:
Sub-bituminous
C1-A1
C1-A2
7.72
7.57
66.90
65.57
Flue Gas Heater
(MWt)
Net Compressor/Expander Power (MWe)
Cooling Water (MWt)
Condensate Preheating (MWt)
Boiler Feedwater Preheating (MWt)
CO2 Captured:
Purity (%v/v)
Contained CO2
(tonne/hr)
Recovery (%)
C2:
C3:
Bituminous
C2-A1
7.43
57.88
Lignite
C3-A1
8.85
72.08
92.64
62.03
13.01
99.74
89.02
60.27
11.93
99.84
65.26
52.34
10.41
99.76
67.64
67.28
13.81
99.85
365.78
91.80
363.26
91.35
319.23
90.97
402.83
91.38
Table 5.7-1: Performance Summary for CO2 plant
The CO2 treatment plant is designed to take the raw CO2 from the ASC PF boiler
and purify and compress it to meet the product specification shown in Table 3.1-3 in
previous section 3.1.3. As indicated in Figures 5.7-1 and 5.7-2, the CO2 treatment
plant consists of:
•
•
•
•
•
•
A direct contact cooler (DCC)
A compression system
BFW and Condensate preheating exchangers
A drier system
A cold box containing CO2 purification equipment
A power recovery expander
The CO2-rich flue gas leaves the heat recovery system of the ASC PF oxyfuel
power plant at approximately 65-75°C. The first part of the CO2 treatment system
(Figure 5.7-1) cools the flue gas, thus removing the moisture by condensation, and
compresses it to 30bara.
124
Figure 5.7-1: CO2 Compression to 30 bar and Acid Removal
The net flue gas from the coal-fired boiler requires cooling before compression so
as to minimise power consumption. This cooling is carried out in a conventional
direct contact cooler, C101, containing plastic packing.
The hot gas enters the column below the bottom layer of packing. It moves up
through the packing and is cooled against liquid flowing down the bed. Part of the
liquid stream is taken from the bottom of the column and pumped through a heat
exchanger where it is cooled against cooling water before returning to the top of the
column, returning above the top stage of packing. The flue gas leaves the top of the
column at approximately 33°C and a liquid water stream is removed from the
bottom of the DCC at approximately 43°C. In cases C1-A1 and C3-A1 part of the
flue gas is then recycled to the boiler (see Figure 5.7-1)
The net flue gas is now around 69% by volume CO2 and at atmospheric pressure
and should be compressed to 30bara for further drying before purification.
Compression to 30bara is carried out in two stages. First K101 compresses the CO2
adiabatically to 15bara. The heat of compression is then used to preheat boiler
feedwater in E102 and condensate in E103. These two heat exchangers are
stainless steel diffusion bonded compact heat exchangers. The boiler feedwater
and condensate streams are returned to the oxyfuel boiler. There is sufficient
holdup in E102 and E103 for some SO2 to convert to sulphuric acid in streams 7
and 8.
125
Stream 8 then enters the contacting column C102. This column provides holdup
and contacting time to allow the reaction to produce sulphuric acid to reach
completion. Some nitric acid will also be formed in this column. Pump P102 pumps
a fraction of the liquid from C102 around, through cooling water heat exchanger
E104, to the top of the column. The direct contact between liquid and vapour allows
the reactions to produce sulphuric acid to reach completion. The heat of reaction is
removed by exchanger E104.
The holdup in C102 is chosen to allow complete conversion of SO2 to sulphuric acid
together with some conversion of NOx to nitric acid. Smaller holdup will decrease
first the conversion of NOx to nitric acid and then the conversion of SO2 to sulphuric
acid. Stream 9 is discharged to the water treatment system.
Water can be injected into the top of column C102 in a separate packed section
should it be necessary to ensure that no acid drops are carried over into the
compressor K102.
Stream 12 should now contain no SO2 and its NOx content will be reduced. With
sufficient NOx in the feed gas and sufficient holdup in C102, there would be no SO2
in stream 12, as is the case in Cases C2-A1 and C3-A1. In case C1-A1 there is
insufficient NOx in the feed stream to remove all of the SO2 in C102 and C103. In
case C1-A2 there is more NOx and less SO2 so more of the SO2 is removed in
C102 and C103. Stream 9 is returned to K102 and compressed to 30 bar further
increasing the reaction rate of the conversion of NOx to nitric acid. C103 provides
further holdup for the reaction to take place that will convert NOx to nitric acid. The
dilute nitric acid stream leaves in stream 15 to the water treatment system. Pump
P103 pumps around a fraction of the liquid from the bottom of C103, through E108
which removes the heat of reaction, to the top of the column C103. In this column it
is preferable to add fresh water to the top of C103. Although this water dilutes the
nitric acid, its addition increases the conversion of NOx to nitric acid for a given
column holdup and pump-around rate.
The flue gas from the oxyfuel combustion process now contains less than 3 ppm
SO2 and most of the NOx has been removed. In cases C2-A1 and C3-A1 all of the
SO2 has been removed. Any SO2 not removed in C102 and C103 will pass through
to the CO2 product. If this is not desirable (CO2 contains only 3 ppm SO2 in C1-A1)
then increasing the holdup in C102 and C103 will lead to increased SO2 removal, as
would increased NOx in the feed stream. Any mercury or mercury compounds
present in the CO2 flue gas from the power station will also be quantitatively
removed by reaction with nitric acid in C102 and/or C103.
The process then moves on to the process summarised in Figure 5.7-2 where the
raw CO2 is dried and the inerts (N2 and Ar) and oxygen are separated to meet the
final CO2 products specifications listed in Table 5.7-2. This process is confidential.
The CO2 is then compressed to 138bara for pipeline transmission.
The raw CO2 gas passes through a temperature swing dual bed desiccant dryer
(C182) to reach a dew point of below -55°C before entering the “Inerts Removal
System”. This desiccant dryer system prevents ice formation which could cause a
126
blockage in the cold box as well as causing corrosion in the pipeline. The cold
equipment is contained in a steel jacketed container with perlite granular insulation.
The inerts removal process uses the principle of phase separation between
condensed liquid CO2 and inerts gas at a temperature of –55°C which is very close
to the triple point, or freezing temperature, of CO2.
Figure 5.7-2: CO2 Inerts Removal and Product Compression
The dry gas is fed to the cold box and is cooled by heat exchange with the returning
streams in the main exchanger. The main heat exchanger is a multi-stream plate-fin
aluminium block. The cooled feed stream is partially liquefied and distilled to
remove impurities to meet the final CO2 products specifications as listed in Table
2.5-2. The CO2 is then compressed to 138bara for pipeline transmission (streams
43 and 38)
The plant is furnished complete with all structural, mechanical equipment, piping,
supports, anchor bolts, electrical equipment, instrumentation, controls and
accessories as required for continuous automatic operation. The controls are
designed to interface with the existing systems. The intent would be to operate the
plant from a remote central control room with periodic inspection.
The material of construction of the low pressure inlet gas piping, direct contact
coolers and the parts of the compressor upstream of the drier must be resistant to
wet gas corrosion taking account of the possible gas composition. Suitable
materials are selected for piping and compressor parts in contact with the flue gas.
127
5.7.2 Safety and Operability
The CO2 recovery plants would typically be designed to interface with the boiler
control system, allowing ease of use and high reliability.
The design of the instrumentation and Distributed Control System (DCS) enables
safe operation of the CO2 recovery plant and provides the necessary control while
handling disturbances and certain levels of process or instrumentation degradation.
The instrumentation and distributed control system is made to be sufficiently reliable
and robust so as to require no operator involvement during normal plant operation.
The cooling water flow demand to the Direct Contact Cooler (DCC) will be
controlled under flow control. The level in the DCC sumps is controlled by the liquid
flow leaving the vessel.
The drier operation is controlled by the DCS. Valve switching and sequencing will
be automated for the entire adsorber cycle, including the on-stream and
regeneration steps. The amount of moisture in the gas stream leaving the drier is
monitored to ensure the performance of the system.
5.7.3 Plant Flexibility
The ASC PF boiler unit will be provided with a single train CO2 compression and
purification system. This means that there will be a single train CO2 compression
system provided for the oxyfuel system. This compression system will consist of a
first stage axial flow CO2 compressor followed by a multistage integrally geared CO2
compressor, each with electric motor drive. It is likely that these compressor
systems will be capable of efficient turndown to about 75% of full flow at constant
discharge pressure. The exact turndown and power consumption will be confirmed
by the compressor vendor. The units would be provided with supervisory control
systems which will cover automatic start, stop and ramping.
5.7.4 Plant General Layout Plot
The CO2 compression and purification plant schematic laypout proposed by Air Products
are presented in Figure 5.7-3.
128
Figure 5.7-3: Proposed Plot Plan for CO2 Compression and Purification Plant
129
5.8
EMISSION CONTROLS
Table 5.8-1a and Table 5.8-1b below summarises the main emission levels
achieved for each of the CO2 capture power plant options comparing to that of the
reference power plant R0.
Emissions
(MWe net basis)
NOx
SOx
Particulates
Hg
CO2
g/MWh
g/MWh
g/MWh
mg/MWh
kg/kWh
C1:
Sub-bituminous
Limit
Achieved
C1-R0 C1-B1 C1-B2
50
44.9
47.1
47.1
55
49.7
5.5
5.4
28
12.6
2.6
2.6
3.5
3.5
3.3
3.3
C2:
Bituminous
Limit
Achieved
C2-R0 C2-B1
50
35.4
44.6
55
32.0
18.3
28
10.9
13.8
3.0
2.4
3.0
C3:
Lignite
Limit
Achieved
C3-R0 C3-B1
50
36.6
49.6
55
21.5
18.5
28
10.7
14.5
5.5
4.5
5.5
NA
NA
NA
0.79
0.10
0.10
0.69
0.09
0.88
0.12
Table 5.8-1a Summary of Amine Scrubbing Power Plant Emissions
Emissions
(MWe net basis)
NOx
SOx
Particulates
Hg
CO2
g/MWh
g/MWh
g/MWh
mg/MWh
kg/MWh
C1:
Sub-bituminous
Limit
Achieved
C1-R0 C1-A1 C1-A2
50
44.9
8.0
10.9
55
49.7
0.31
0
28
12.6
0
0
3.5
3.5
0
0
NA
0.79
0.08
0.09
C2:
Bituminous
Limit
Achieved
C2-R0 C2-A1
50
35.4
2.3
55
32.0
40.2
28
10.9
13.8
3.0
2.4
3.0
NA
0.69
0.09
C3:
Lignite
Limit
Achieved
C3-R0 C3-A1
50
36.6
4.1
55
21.5
0
28
10.7
0
5.5
4.5
0
NA
0.88
0.10
Table 5.8-1b Summary of Oxyfuel Power Plant Emissions
All the CO2 capture power plant options achives the emission no greater than the target
limit specified by CCPC for this project. Note that the emission listed above are the
emission level achieved based on power plant net output which varies slightly depending
on the individual equipment design performance of each power plant option.
For an Oxyfuel power plant, no FGD, deNOx or deHg equipment is necessarily required
within the Boiler Island in order to meet the overall oxyfuel power plant emission targets.
Although depending on the sulphur content of the coal, a FGD on the flue gas recycle may
be required to limit SO2 concentrations in the furnace. These emission components are
prelimininarily proposed to be removed within the CO2 compression and purification system
(Unit 1200). However SOx, NOx and Hg removal in the CO2 compression and purification
system is novel and will require further development and also needs evaluating against well
proven DeNOx and DeSOx technologies.
5.8.1 NOx Emission Control (Unit 300)
All the power plant options in this project are designed to achieve NOx emissions
no greater than 50g/MWh (net) target level. The DeNOx plant serving the C1 (subbituminous coal) site was defined by Doosan Babcock, while the SCR facilities at
the C2 (bituminous) and C3 (lignite) sites were defined by Neill & Gunter on behalf
of CCPC.
Air/PF-fired Power Plants:
For each of the air/Pf-fired cases below, namely:
• Options C1-R0, C1-B1 and C1-B2: Sub-bituminous air/coal-fired boiler
• Options C2-R0 and C2-B1:
Bituminous air/coal-fired boiler
• Options C3-R0 and C3-B1:
Lignite air/coal-fired boiler
130
NOx control is achieved by using two control measures. The first is in-furnace NOx
reduction control through Doosan Babcock’s low-NOx burners with staged boosted
overfire air (BOFA). This process is expected to reduce NOx emissions by 40%,
compared to single stage combustion. The second measure is a Selective Catalytic
Reactor (SCR) plant installed between the boiler economizer outlet and the
regenerative air heater gas inlets. The two methods in combination are expected to
remove 95% of NOx present in the flue gas.
Selective Catalytic Reduction (SCR)
The SCR is based on state-of–the–art well proven technology which utilizes the
reaction of ammonia (NH3) and NOx to form water (H2O) and free nitrogen (N2) in
the presence of a catalyst at economizer outlet temperatures. The reactions that
take place are:
4 NO + 4 NH3 → O2 = 4 N2 + 6 H2O
6 NO2 + 8 NH3 → 7 N2 + H2O
2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O
Two 50% capacity Selective Catalytic Reduction (SCR) reactors are employed to
reduce the NOx leaving the economizer to the emission target level specified.
Reactor Vessel
The SCR reactor vessel is located in line of the flue gas, immediately downstream
of the economizer and before the air heaters. The reactor is sized based on catalyst
type, process conditions, anticipated NOx flue gas loading and NOx emission limits.
The reactor is usually designed using either plate type catalyst elements made of
stainless steel expanded metal plates coated with active catalyst compounds, or
honeycomb type elements made of extruded metal coated with catalyst elements.
The catalyst elements are designed to ensure good contact between the flue gas
ammonia mixture and the catalyst, while minimizing pressure drop through the
reactor, ash accumulation and erosion. Catalyst performance is key to NOx
reduction, and all catalyst compositions are proprietary, although they generally fall
into one of three categories; base metal, zeolite, and precious metals. While the
reactor vessel is designed to limit ash build up, cleaning equipment such as sonic
horns or sootblowers will be included to ensure catalyst surfaces remain clean
during normal operations.
The reactor housing is structurally supported and sealed to force all flue gas
through the catalyst bed. Access ports, platforms, and monorail systems are
provided for SCR inspection and maintenance, and to periodically remove and
replace the catalyst as it reaches the end of its design life.
Ammonia Injection
The ammonia is injected via an ammonia injection grid consisting of a network of
spray headers and nozzles. The injection grid is located in the flue gas stream, far
enough upstream of the SCR unit, and with a sufficient distribution of nozzles that
uniform mixing between the ammonia and flue gas before the catalyst bed is
ensured. A representative layout is shown in Figure 5.8.1-1.
131
AMMONIA
INJECTION GRID
SCR
REACTOR
BOILER
AIR
HEATER
SECONDARY
AIR
FLUE
GAS
Figure 5.8.1-1 Location of SCR Unit
Design of injection grid systems is proprietary and varies between manufacturers.
The SCR reactors proposed by Doosan Babcock for C1-R0/B1/B2 are designed to
accommodate either honeycomb or plate type catalyst. The reducing agent to be
used is anhydrous ammonia. The quantity of catalyst has been selected so that the
ammonia slip through the reactor during the 24,000 hours of catalyst lifetime will not
exceed 2 ppmvd @ 6% O2. Ash and slag have the potential to cause catalyst
erosion, block catalyst pores or even plug catalyst elements. These factors
influence the selection of catalyst pitch. The upstream flue, ash hopper and popcorn
screen design takes into consideration the minimization of popcorn ash carryover to
the SCR and downstream regenerative airheater. For each catalyst layer, routine
operation of sonic horns will be used to prevent the accumulation of fouling
materials including fly ash.
Downstream of the boiler economiser outlet the flue gas is divided into two equal
streams, each with one Ammonia Injection Grid (AIG) mounted between the
economiser outlet and SCR reactor inlet. The AIGs are mounted in the rising flue
gas ducts upstream of each SCR reactor. The AIGs are designed and arranged to
ensure uniform mixing between the ammonia and the flue gas stream before
reaction in the SCR catalyst, where the NOx reacts with ammonia to form nitrogen
and water vapour.
Ammonia Storage and Handling
Anhydrous ammonia will be off loaded by trucks into one of two horizontal ammonia
storage tanks, sized for 14 days storage. Adequate tank pressure will be maintained
to deliver ammonia to the injection grid using electric ammonia vaporizers, along
with insulated heat traced transfer lines. Prior to being injected into the flue gas
stream, the ammonia will be diluted to approximately 5 percent by volume with
recirculated flue gas to improve distribution upstream of the SCR.
Ammonia flow will be determined through a distributed control system using real
time inputs from the fuel and oxygen systems, as well as NOx monitors at the inlet
and outlet of the SCR, compared with the defined NOx set point.
System Requirements
132
For a 95% reduction of NOx it has been assumed that a four layer bed system will
be used. The catalyst was selected and sized to minimize “ammonia slip” through
the SCR reactor to acceptable levels (2ppmvd @ 6% O2). Ammonia slip is the result
of non effective catalyst or an undersized or poisoned catalyst bed.
Sizing the catalyst bed is very specific to the project and the methodology used for
this is also proprietary to the catalyst manufacturer. Using a scale up factor from
other projects as well as the data available from the EPA NOx Control handbook the
catalytic volumes shown in Table 5.8-2 have been calculated.
The amount of ammonia used as a reagent has been estimated using the defined
fuel and boiler technologies and the results presented in Table 5.8.1-1. This
information was in turn used to determine capital and operating costs for the SCR
Unit for the C1, C2 and C3 plant sites.
TABLE 5.8.1-1 SCR UTILITY REQUIREMENTS
Scenario
C1R0/C1B1/C1B2
C2R0/C2B1
C3R0/C3B1
NOx
Loading
kg/hr
308
333
427
Estimated
Catalytic
Volume (m3)
990
1024
1296
Ammonia
Required
kg/hr
338
187
239
Oxygen/PF-fired Power Plants:
Compared to an air/PF-fired boiler, an Oxyfuel boiler features that nitrogen is
eliminated from air by the ASU and excluded in the combustion process. The NOx
formation during combustion process mainly results from fuel NOx. Hence NOx
emission from the Oxyfuel boiler is significantly lower that that of air/PF-fired boiler.
For C1-A1, C2-A1 and C3-A1 oxyfuel power plant options, there is no in-furnace
NOx control required, neither SCR is employed. The NOx in the main flue gas
stream is separated into acid effluent in the CO2 purification process, which has
been described in detail in previous Section 5.7
5.8.2 Mercury Removal (Unit 400)
All the power plant options in this project are designed to achieve the Hg emission
no greater than the target level specified. Coals contain various percentages of
both elemental and oxidized mercury. The percentage of oxidized mercury in coal
can range from 20 to 90 percent. Based on the coal/ash analysis data presented in
Table 3-4, it was assumed that the coal mercury contains approximately 60%
oxidized mercury. Mercury existing as oxidized mercury can be easily removed in a
wet FGD system, however, elemental mercury requires additional treatment for
removal to occur.
Air/PF-fired Power Plants:
133
For all air/PF-fired power plant options in this project, the mercury removal system
employed is as proposed by MHI[5]. The mercury removal system enables
conventional flue gas treatment system with SCR and FGD to remove mercury with
minimum investment. Features of this system are that HCl is injected upstream of
the SCR for mercury oxidation to enhance the removal ratio at the FGD absorber.
Re-emission from the FGD absorber is prevented by Oxidation Reduction Potential
(ORP) control system. The schematic process diagram is illustrated in Figure 5.8.21 below.
Mercury present in coal in low concentration is vaporized as elemental mercury in
combustion zone. As the flue gas cools after combustion before the SCR plant,
oxidation reaction occurs, reducing the concentration of the elemental mercury
forming HgCl2 (oxidized mercury) and particle-bounded mercury. The particlebounded mercury can be removed at the particulate control devices from the flue
gas. The elemental mercury, which is water-insoluble, remains in the flue gas after
passing the FGD on to the cooling tower, while more than 95% of oxidized mercury,
which is water-soluble can be removed at the FGD by the contact with a waterbased solvent. Therefore, to effectively remove mercury from flue gas using a
water-based solvent, the mercury has to be in its oxidized form. HCl is injected
upstream of the SCR to enhance oxidation of the elemental mercury.
Mercury Removal System
Process Flow
Hg
Monitor
HCl Tank
FGD
HCl
Monitor
Boiler
DeNOx・
Hg Oxidation
Air
Heater
Particulate
Control
Device
ORP
Stack
Controller
Hg0+2HCl+1/2O
2
HgCl2+H2O
Belt
Filter
Air
Gypsum
(with HgCl2)
2E09-2ZA98EA
Figure 5.8.2-1 Schematic Process Diagram of Mercury Removal System
Mercury form in flue gas is dependent upon temperature and gas composition and
the equilibrium composition of mercury is affected by HCl concentration. To
minimize HCl injection before the SCR, HCl concentration in the flue gas before the
FGD plant and Hg concentration at the FGD outlet are monitored to regulate HCl
injection amount.
Oxidized mercury is removed effectively at the FGD with prevention of mercury reemission by ORP (Oxidation Reduction Potential) control illustrated in Figure 5.8.22 indicating the degree of oxidization tendency and reduction propensity. ORP in
the FGD absorber is controlled by regulating oxidation air amount to the FGD
absorber. ie with increase of the oxidation air amount ORP increases, reducing
sulphite concentration in the absorber slurry and visa verse.
134
Mercury Removal System
ORP* Control
(*ORP : Oxidation Reduction Potential )
Absorber
Operation
Range
SO3 Conc.
in
Absorber
Slurry
(mmol/l)
mmol/l)
ORP
CONTROL
ORP
Reduction
Atmosphere
Oxidation
Air
2E09-2ZA98EA
Figure 5.8.2-2 ORP (Oxidation Reduction Potential) Process Control
One boiler unit employs one ‘Mercury Removal Plant’ which comprises:
•
1 unit of HCl injection system
•
1 unit of ORP control system
The volume and characteristics of SCR catalyst affect the oxidation performance and HCl
injection amount. It is assumed that the oxidation performance of SCR is equivalent to
MHI‘s catalyst and the catalyst volume is also assumed to be equivalent. Then it is possible
to remove more than 90% of the inlet mercury with addition of HCl.
5.8.3 Particulate Removal (Unit 500)
Primary particulate control will be provided by the inclusion of an electrostatic
precipitation (ESP). The precipitator configuration used in the site plans and
described below is based on two precipitators arranged in parallel, The ESP designs
were proposed by Neill & Gunter on behalf of CCPC.
Process Description:
The Particulate Removal Plant is based on a dry electrostatic precipitator (ESP).
The ESP consists of an insulated, gas tight, carbon steel casing with openings at
either end to receive and discharge flue gas. Perforated inlet and outlet flow
distribution devices ensure even gas flow entering and leaving the unit. A series of
collecting plates and electrodes are top supported from a structural steel frame, and
hoppers hang from the casing bottom to collect and temporarily store fly ash. The
entire assembly is supported on a series of structural steel columns.
The ESP internals are primarily composed of sheet steel collecting plates spanning
the width of the casing. The plates are spaced in several series of rows at 300mm
to 400mm centres, edge on to the gas flow. They are grounded and connected to
the positive polarity of a 55 to 85kV DC power source. Discharge electrodes are
suspended from electrical insulators between the collecting plates, and connected
to the negative polarity of the same power source. When the ESP is operating an
electric field is created between the collecting and discharge electrodes.
135
The flue gas flow is directed between the individual collecting plates, through the
electric field, where particles entrained in the gas become negatively charged by
either field charging or diffusion, depending on particle size. The charged particles
are attracted to the grounded collection plates and migrate to them. Since particles
exhibit large variation in their ability to accept or hold a charge, the ESP has a
series of collection and discharging sections to ensure design particulate collection
levels. Generally each of these collection fields is designed to capture roughly 80%
of the particulate entering the field.
The ash particles collecting on the collector plates quickly build up an agglomerated
ash layer that must be periodically removed by rapping, or mechanically striking the
plate. The dislodged ash layer then falls in sheets to the hoppers below. The
hoppers are emptied as needed and the ash directed to the Fly Ash Silo for final
removal. Ash can collect on the discharge plates as well, and they too are
periodically rapped to remove ash build up.
The electrostatic precipitator is designed to accept flue gas and entrained ash from
the air heater outlet, and remove particulate to meet the emission limit of 28g/MWh.
In practice, an emission rate of 2.8g/MWh can be expected, comparable to an
overall removal percentage of 99.95%. The ESP sizing is based on the project’s
required collection efficiencies and the Deutsch-Anderson equation using the
following sizing factors:
•
•
•
Charged particle migration velocity, which is in turn affected by the fuel and ash
characteristics, operating conditions, and gas flow distribution,
Gas flow, and
Collection plate surface area.
List of Major Equipment:
•
•
•
•
•
•
•
16 – 110kVP – 1500mA TR sets
2 Seal Air Systems
112 CE Rappers per ESP
48 DE Rappers per ESP
8 Transformer/Rectifiers per ESP
32 Hopper Vibrators
32 Hopper Heaters
The indicative characteristics of the ESPs are presented in Table 5.8.3-1 below:.
136
Parameter
Units
Keephills
Pt Tupper
Shand
C1:
Sub-bituminous
C2:
Bituminous
C3:
Lignite
No of Chambers
2
2
2
No of Fields/Chamber
4
4
4
Am3/s
704
659
836
3
23.7
5.1
25.8
Total Flue Gas Volumetric Flow
Inlet Particulate Loading
Emission
g/SDm /s
mg/SDm3/s
120
120
120
%
99.49
97.65
99.53
80
39
81
56304
25701
67716
Collection Efficiency
Specific Collecting Area
Total Collecting Area
2
3
m /Am
2
m
Table 5.8.3-1 Estimated Characteristics of Electrostatic Precipitator
5.8.4 Flue Gas Desulphurization (FGD) System (Unit 600)
The function of the Flue Gas Desulphurization (FGD) system is to scrub the boiler
exhaust gases to remove most of the SO2 content prior to release to the
environment. The FGD is designed to achieve the SOx emission no greater than the
target level of 55g/MWe (net) and also for the pre-treatment system for the CO2
capture plant.
For all the air/PF-fired power plant options, the FGD system with one train
configuration is based on Wet Limestone Gypsum Process technology by Mitsubishi
Heavy Industries Ltd [4]. The wet limestone-gypsum process is chosen for flue gas
desulphurization process for its advantages of the following:
•
Abundant low cost, global availability and environmentally friendly.
•
Simple process, highly flexible, easy operation with no secondary pollution.
•
Recovers as commercially valuable by-product material suitable for manufacture
of cement and gypsum wallboards.
Figure 5.8.4-1 below presents the indicative FGD and handling plant process flow
diagram proposed by MHI for this project.
5.8.4.1 FGD System Description
The FGD plant is designed by MHI to treat the flue gas to be suitable for the CO2
capture process to ensure the reliable and economical operation. The FGD system
(Figure 5.8.4-2) is a single-loop, in-situ oxidation, gypsum recovery type wet
limestone process. For the strict SO2 and impurity removal efficiency requirement, a
twin-tower double contact flow scrubber (DCFS) is applied. The DCFS of MHI
features high SO2 removal efficiency, high plant reliability, simple operation, easy
maintenance and low operation and construction cost.
137
The absorber consists of two twin-tower DCFS installed above an integrated
oxidation and neutralization tank. The flue gas is introduced directly into the first
stage absorber before it makes a 90 degree turn at the inlet of the second stage
absorber. The liquid absorbent is spouted upwards by a multiple number of simple
single pipe nozzles installed on the single spray pipes located at 1st and 2nd stage of
the absorber lower section to form the so-called liquid column (Figure 5.8.4-3) in the
DCFS.
Further in the DCFS, a dense liquid layer generated by the interference action
between the falling liquid drops and the liquid drops being spouted up enables the
absorber to be compact by increasing the gas velocity.
The absorbed SO2 while being neutralized by the limestone absorbent flows into the
tank at the bottom of the absorber where maximum oxidation of SO2 to HSO3- and
HSO3- to SO42- is achieved by air supplied to the absorber by an Air Rotary Sparger
(ARS) (Figure 5.8.4-3). The oxidized HSO3- in the form of SO42- reacts with the
calcium carbonate (CaCO3) contained in the absorbent slurry to form gypsum slurry
(CaSO4.2H2O).
The limestone slurry is fed to the absorber to form gypsum slurry after absorption
and oxidation of sulphur dioxide contained in the flue gas.
138
Boiler
DeNOx
(Hg
Oxidation)
A/H
Particulate
Control
Device
IDF
Stack
Reheater
Hea Extractor
Gypsum Slurry
Dewatering
HCL Injection System
From
CO2
Absorber
Absorber Mist
Eliminator
GYPSUM
SILO
Oxidation Air Blower
Waste Water
Absorber
Recirculation
Pump
Treatment
Filtrate
Note :
Shows scope of
Absorber
Bleed Pump
Off Load Drain
Section
Limestone Slurry
Limestone Slurry
Preparation
Limestone
Storage Silo
Figure 5.8.4-1 FGD and Handling Plant Process Flow Diagram
139
Gas Inlet
Gas Outlet
Spray Pipe
Spray Pipe
Oxidation Air
Air Rotary Sparger
Recirculation Pump
Figure 5.8.4-2: Double Contact Flow Scrubber (DCFS)
CLEAN GAS
ABSORBENT
DIRTY GAS
Figure 5.8.4-3: View of the Liquid Column
5.8.4.2
FGD Process Description
(1) Absorption and Oxidation Sections:
Untreated flue gas is fed to the absorber, where cooling occurs during
desulphurization and oxidation. After contacting with the absorbent slurry the clean
flue gas flows upward and passes through a mist eliminator to have its entrained
140
liquid removed before being discharged via the cooling tower.
a) Oxidation ARS Air Nozzles: The absorber tank is equipped with ARS oxidation air
nozzles to maximize the efficiency of the oxidation of HSO3- to SO42-. Oxidation air
from the atmosphere is sent through these ARS nozzles into the absorber tank. By
the introduction of air through these ARS nozzles, fine bubbles are produced in the
absorbent slurry circulating in the absorber tank. This generates a high gas-liquid
contact surface area between the air and the slurry resulting in a high oxidation rate.
b) Oxidation in Absorber Tank: The absorber tank is sized to hold enough liquid
volume and to ensure adequate residence time for the complete oxidation of HSO3to SO42-. The sizing of the absorber tank provides efficient limestone utilization
before the absorbent slurry flows to the gypsum dewatering section. The absorber
slurry bled from the absorber tank is transferred to the gypsum dewatering section.
c) Neutralization in Absorber Tank: In the absorber tank, the absorbent slurry is
mixed with the supplied fresh limestone slurry to compensate the calcium carbonate
consumed in both the absorber tank and absorber tower. The agitator in the
absorber tank mixes the slurry to ensure consistent concentration of absorbent and
to prevent settlement of solids.
d) Absorbent Slurry, Spray Header Pipe and Recirculation Pumps: The refreshed
absorbent slurry is recirculated from the absorber tank to the absorber header pipe
by the recirculation pumps. The absorber recirculation pumps are specifically
designed to transfer solids in suspension.
The spray headers distribute the absorbent slurry equally to a multiple number of
nozzles from which the absorbent slurry necessary for SO2 absorption is provided.
The absorber tank is sized to achieve complete neutralization of H2SO4 using
CaCO3 slurry with consequential production of crystallized gypsum (CaSO4.2H2O).
e) Absorber Mist Eliminator: A highly efficient mist eliminator is located between the
absorber and the stack. The flue gas-entrained mist reaching the mist eliminator is
collected and returned to the absorber tank.
(2) Gypsum Dewatering Section
The gypsum slurry is bled from the absorber tank to the gypsum belt filter system.
The belt filter dewaters the gypsum slurry. The dewatered gypsum is stacked on the
gypsum stacking area through the gypsum belt conveyor. The stacked gypsum is
taken out by the truck and shovel loaders.
(3) Limestone Slurry Preparation and Feed Section
The FGD process uses limestone as SO2 absorbent. Initially, limestone rock with a
grain size of up to 10mm is supplied and delivered to the FGD plant in bulk usually
by truck. The truck discharge limestone into under ground unloading receiving
hopper. The limestone unloading conveyor and transfer conveyor transports the
limestone from the limestone receiving hopper to the limestone storage silo. The
weight feeder conveys the limestone to the limestone ball mill unit.
Limestone ball mill system is arranged in closed circuit with hydro-cyclone
141
classifiers designed to deliver the underflow as the ball mill feed. In the ball mill, the
limestone is mixed with make up water and overflow is discharge in to the mill
overflow tank. The hydro-cyclone classifier overflow is fed by gravity to the
limestone slurry tank, with limestone slurry mechanically agitated until it is pumped
to the absorber. Figure 5.8.4-4 presents an indicative limestone/gypsum process
flow diagram.
Figure 5.8.4-4: Indicative Limestone/Gypsum Process Flow Diagram
(4) Off-Load Drainage Section
When it is necessary to drain the Absorber Tank and absorbent slurry lines for
periodical inspection and maintenance, the absorbent slurry is drained to the Hold
Up Tank via trenches and Sump. Pumps are provided to return the slurry to the
absorber from which it has been drained.
Formatted: Bullets and
Numbering
5.8.4.3
FGD Utility Auxiliary System
The main FGD auxiliary systems comprises of a Water System and a Air System
(1) Water System: The Water System comprises of the following sub-systems:
(b) Process Water System: Process water is used for Absorber make-up and
washing water in the system
Formatted: Bullets and
Numbering
(c) Cooling Water System: Cooling water is used for the equipment. Cooling water
pumps and tank are not including in MHI’s scope of supply, but are included in
the Balance of Power Plant
Formatted: Bullets and
Numbering
(2) Air System
• Instrument Air System: used for instrumentation or control equipment for the
FGD system.
• Seal Air System: Seal air from the seal air fans is supplied to the dampers.
142
5.9
BALANCE OF POWER PLANT (UNIT 2000)
This section presents the major balance of the power plant. The balance of power
plant studies were undertaken by Neill & Gunter on behalf of CCPC.
5.9.1 Coal and Ash Handling (UNIT 100)
5.9.1.1 Process Description
Design Criteria
The design criteria used for the material handling system is based on “Project
Specifications and Design Basis Ground Rules” [1].
Coal Handling System Function
The coal handling system for each option is intended to:
1.
2.
3.
4.
5.
6.
7.
8.
Receive coal by truck,
Weigh and sample incoming coal,
Crush coal to the requirements of the mills,
Provide 14 days of active live covered storage,
Provide 20 days of dead open storage to secure supply for the power plant.
Transport coal to the boiler day bins,
Store a 12 hour supply within day bins, and;
Deliver coal from the day bins to the mills.
For the basis of the design, all storage capacities have been based on 100% MCR
unless otherwise indicated.
Coal Delivery
The coal receiving hopper will receive pre-crushed coal (50 mm minus) by road
transport. The hopper, designed to receive coal from a single truck, will have a
minimum waterline volume equivalent to 2.5 trucks. Scales will be provided on the
approach road (by another system) to weigh full and empty trucks.
The coal receiving and transport system will be able to unload 15 trucks within one
hour.
Coal will be transported from the hopper using a combination of feeders and
conveyors to an incoming coal sampling facility.
Coal will then be placed in storage or delivered directly to the crushing plant.
Annual Coal Consumption
The design is based on minimum unit availability greater than 85%. For
comparison within this project, all new units should be designed with a base load of
7884 running hours per year (90%) for an operational life of 30 years. The
estimated annual coal consumption is given in Table 5.9-1:
143
TABLE 5.9-1 ANNUAL COAL CONSUMPTION
Case
100% MCR
(kg/sec)
Annual Operating
Hours
C1
C2
C3
62.74
35.91
84.14
7884
7884
7884
Annual Coal
Consumption
(t x 106)
1.8
1.0
2.4
5.9.1.2
Coal Handling Systems
Operational Security
The redundancy for rotating equipment was based on installed spares on a “plus
one” basis; ie one 100% pump has a 100% spare; two 50% pumps shall have one
50% spare. Major rotating equipment such as the air compressor was not spared;
ie no redundancy was allowed.
Adequate operational security was ensured by providing the following features and
emergency systems with the coal handling system:
1. Not less than two conveyors were provided from the coal yard to the boiler day
bins of the power block. Each of the paired conveyors will be able to feed coal from
the coal yard to any day bin
2. The in-ground emergency reclaim hopper can be fed by mobile equipment. This
system was tied into the last suitable transfer point before the coal is delivered from
the coal yard to the power block.
3. The ability to feed directly from the coal receiving facilities to either of the paired
conveyors feeding the day bin.
4. Security storage pile
Security Storage
Security storage will be provided as a form of operational insurance against
unforeseen, infrequently occurring events and will total twenty (20) days of
consumption at 100% of the maximum burn rate. The required security storage
capacity of the coal yard is given in Table 5.9-2:
Case
C1
C2
C3
TABLE 5.9-2 COAL SECURITY STORAGE (TONNES)
100% MCR
20 Days Security Storage
(kg/sec)
(t x 103)
62.74
108.4
35.91
62.5
84.14
145.4
Security storage will be uncovered, dead storage, stacked and reclaimed by the
materials handling system using operating labour and mobile equipment.
Security storage will be compacted, covered or sprayed to prevent and/or minimize
dusting.
144
Active Storage
Active storage will be provided to accommodate the normally experienced
imbalances between the rate of coal delivery to the power plant and coal
consumption in the generators. The causes of the imbalances could include:
1. Non-uniform arrival of ROM coal.
2. Delays incurred during arrival and unloading.
3. Variations in the burn rate (tonnages consumed by the power plant) due to
system demands, fuel quality and power plant maintenance schedules, compared
to deliveries to the power plant, which are expected to be uniform.
Sub-bituminous and bituminous coal in active storage shall be live, enclosed and
sufficient for 14 days of power plant operation at maximum burn rate. Active
storage for lignite shall be based on 5 days storage. All active storage systems
shall use material handling systems that require a minimum of operating labour and
minimum use of mobile equipment.
The required active storage capacity of the coal yard is shown in Table 5.9-3:
TABLE 5.9-3 COAL ACTIVE STORAGE (TONNES)
Active Storage
100% MCR (kg/sec)
(t x 103)
62.74
75.9
35.91
43.4
84.14
36.3
Case
C1
C2
C3
Total Storage Capacity of the Coal Yard
The total storage of the coal yard is the sum of the active and security storage as
indicated in Table 5.9-4 below.
Case
C1
C2
C3
TABLE 5.9-4 COAL STORAGE CAPACITIES (TONNES)
Active Storage
Security Storage
Total Storage Capacity
(t x 103)
(t x 103)
(t x 103)
75.9
108.4
184.3
43.4
62.5
105.9
36.3
145.4
181.7
Maximum Coal Pile Height
Maximum coal pile height of 15 m was assumed for the base case although heights
up to 18 m may be considered for areas if justifiable by geotechnical and dusting
factors.
Belt Speeds
The maximum belt speed will be 4.5 m/s, except where other speeds are beneficial
and justifiable.
145
Storage Day Bins
Twelve hour coal storage at 100% MCR will be provided using a series of day bins
providing fuel for the grinding mills (Table 5.9-5 below)
TABLE 5.9-5 STORAGE BIN CAPACITY (TONNES)
100% MCR
12 Hour Day Bin Storage
(kg/sec)
(tonnes)
62.74
2,710
35.91
1,551
84.14
3,635
Case
C1
C2
C3
Each day bin will have one associated weigh-metric feeder to weigh the feed going
to each mill. Each mill will have not less than two dedicated day bins/feeders.
Coal Processing
1.
Blending
Blending was not considered for Cases C1 and C3. Belt blending of
bituminous coal and petroleum coke using the security storage reclaim
system in combination with the active storage system was considered for
Case C2. No additional capital expenditures for the coal storage and
handling system over those of Case C1 were considered for this study.
2.
Crushing and Screening
As-delivered coal is crushed and screened prior to storage, to control the top
size fed to the power block. Tramp iron material will be removed by magnets
prior to entering the crushers.
Coal from storage is crushed again during reclaim using a frozen coal
cracker to remove any frozen lumps. Tramp iron material will removed with
the use of metal detectors and self cleaning tramp iron magnets prior to the
lump breaker.
Weighing and Sampling
As delivered coal quality is measured using an automated sampling facility. Weigh
belt scales will also be utilized to weigh the coal being received. These scales are
designed to comply with ISO standards.
The quality of the coal delivered to the day bins is monitored online with the use of
an online analyzer for process control purposes. Belt weigh scales are also
provided for process control, not for commercial purposes. The process control
scales have a manufacturer’s rating of plus/minus 0.5%. Depending on installation
and operating conditions actual scale accuracy can vary substantially.
Tramp Material Control
The coal receiving system utilizes metal detectors and tramp iron magnets.
146
The coal storage and reclaiming system has metal detectors and a self cleaning
tramp iron magnet located prior to the lump cracker.
Servicing Priority
In the event of equipment breakdown or where a conflict exists, feeding to the
Power Block day bins will take precedence over coal receiving.
Characteristics of Coal
Design coal characteristics are given in previous Section 3.1-2 and are summarized
in Table 5.9-6 below.
TABLE 5.9-6 COAL CHARACTERISTICS
C1:
C2:
Sub-bituminous
Bituminous(1)
Fuel Analysis
(%w/w, as received)
Proximate
Moisture
20.00
11.23
Ash
15.10
5.15
Volatile Matter
27.03
29.79
Fixed Carbon
37.87
53.83
Ultimate
Moisture
20.00
11.23
Ash
15.10
5.15
Total Carbon
48.01
73.63
Hydrogen
2.77
4.78
Nitrogen
0.59
1.50
Oxygen
13.32
2.45
Sulphur
0.21
1.26
(1)
Design Coal Blend is Colombian Coal 80% + Pet Coke 20%
Coal
C3
Lignite
33.54
13.46
24.39
28.61
33.54
13.46
39.58
2.57
0.67
9.7
0.49
As delivered coal can range to a maximum size of 50 mm.
Boiler Feed Requirements
The day bin coal storage for the Boiler will have a capacity of approximately 12
hours of coal at maximum burn rate. Coal will be hoisted to the storage bins twice a
day; seven days per week.
TABLE 5.9-7 DAY BIN STORAGE
100% MCR
12 Hour Day Bin Storage
(kg/sec)
(tonnes)
62.74
2,710
35.91
1,551
84.14
3,635
Case
C1
C2
C3
Each day bin feed conveyor will be capable of maintaining feed to boiler and also
topping off the day bins within a 12 hour period of time.
Case
100% MCR
(kg/sec)
C1
C2
62.74
35.91
TABLE 5.9-8 DAY BIN FEED CAPACITY
12 Hr Refill Rate
100% MCR
(tonnes/hr)
(t/hr)
226
129
226
129
147
Feed Conveyor
Capacity (min)
(tonnes/hr)
452
258
C3
84.14
303
303
606
Feed conveyor capacities may be increased by 20% to allow for altering the day bin
discharge points
Fuel Properties
Although the physical properties vary between lignite, bituminous and subbituminous coals, this study uses the following composite physical fuel properties:
Bulk Densities:
0.8 for active storage stockpile volume calculations and
volumetric capacity calculations for conveyor belts.
0.9 for load, power and structural calculations.
0.95 for compacted storage pile calculations.
Angle of Repose:
37° (45° for freshly stacked damp coal).
Surcharge Angle:
20° for volume, handling capacity and power calculations.
Coal Handling Systems
Belt Conveyors
The design parameters for belt conveyors are:
Maximum Speed:
Trough Angle:
Maximum Incline or Decline:
4.5 m/s
35°.
16°
To provide adequate reserve free board at the edges of the belt, conveyors were
designed for a capacity 1.1 x the required maximum nominal tonnage. This reserve
free board will minimize spillage during occasional overloads or when the belt is not
running centrally.
Belt conveyors will be designed in accordance with recognized codes and standard
practices based on ISO or the CEMA Handbook.
Belt protection devices will include the following:
1. Shut down of the conveyor drives if the belt does not start within a preset time
after the drives start. On each conveyor, a motion sensing switch, driven by an
idler pulley, will provide a signal to the control system for this purpose.
2. Shutdown of the conveyor drives if there is differential belt speed at the driven
pulley indicating belt slippage due to loss of belt tension or belt breakage.
3. Side travel switches mounted at the head end, the drive area and at the tail end
(or loading area) of each conveyor to detect when the conveyor is off centre by
more than a preset amount. Signals from these switches will be combined in the
control system with suitably pre-selected time delays and will shut down the
conveyor drives in the event of misalignment.
4. Transfer chutes will have high level switches to minimize overfilling and spillage.
148
Vertical curves on conveyors mounted on fixed structures are designed so that the
belt will not lift off during steady state running – either empty or loaded lightly. Soft
starting drive systems are used where necessary to facilitate this objective. Where
lift-off is expected, the belt will be controlled with hold-down rollers. Where the
conveyor is uncovered, vertical wind guards will be provided to protect the belt from
side winds.
Head boxes, transfer chutes and loading skirts will be fully sealed dust tight.
Conveyor entry into the head box and material exit from the loading skirts will be
sealed with dust curtains. Where practical, transfers will be equipped with dust
collectors. Traveling equipment will be evaluated on an independent basis, where it
is difficult to provide effective dust collection.
Differential conveyor stopping times is considered in the design. Adequate capacity
will be provided in transfer chutes and head boxes to contain a surge build-up
resulting from unequal stopping times for adjacent conveyors. Brakes and quick
disengaging drive couplings will be provided where necessary to control the
stopping times and limit surge volume. Provisions will be made in the design of the
discharge chutes to limit the coal cross section on the downstream conveyor on
restarts after a loaded shutdown.
Provisions will also be allowed for belt changing, including:
1. Setting up rolls of new and used belting when changing the belt on a conveyor.
2. A work area for preparing the belt for splicing and for setting up the press
(including power supply for the press).
Where practical, all conveyors are covered with weather hoods. Walkways are
located inside conveyor trusses adjacent to the conveyor. Walk way access is
provided on one side of the conveyor and around all transfers. Maintenance access
is provided on the alternate side of the conveyor. Open conveyors are protected
from side winds by wind guard structures mounted along both sides of the
conveyors.
Clean up around and under belt conveyors must be considered during design and
layout of the coal handling system. Areas which receive particular attention include
the underside of all loading points and underneath yard conveyors.
Coal Yard Services
1. A service water system provides raw water to the day tanks of site buildings,
and dust suppression facilities.
2. A dust suppression system provides treated water to the coal yard via spray
guns to control the coal dust. The addition of a chemical binder to the water can
also be used to form a crust on the coal pile surface which helps to prevent coal
heating value losses and dust formation.
149
3. A water supply piping system will provide raw water to the conveyor fire
protection system, standpipes of buildings, outdoor fire hydrants, and deluge
systems for transformers.
4. Drainage System
In order to minimize risk of environmental contamination, ponds and drainage
systems will be designed to accommodate maximum run-off due to an extreme
intensity rainstorm.
The rainfall criterion for design of these systems was taken as the 60 minute
maximum rainstorm having a return period of 10 years.
The coal yard storage area will be sloped 1:300 from the centre of the stockyard
to promote runoff. Shallow v-shaped trenches, one at each side of the stackerreclaimer foundation will be provided. A 1.8 metre wide main trench around the
perimeter of the coal yard will collect all rain water runoff and discharge to a
collection pond.
5. Collection Pond
The coal pile runoff will be collected in a pond with capacity to accommodate the
volume of runoff. The collection pond will allow coal fines to settle out.
Sediment accumulating at the bottom of the pond will require occasional
removal. Discharged water from the pond, will need further treatment to meet
local standards. The treated water can be reused as the coal pile dust
suppression water.
Sizing the pond is critical to strike a balance between space required to retain
runoff from an extreme storm event and make up water capacity upstream of the
wastewater treatment plant. Sizing will be based on the runoff generated during
the 10 year, 24 hour storm, plus an allowance of approximately 20% for
accumulation of sediment, plus suitable storage volume to reduce make up
water requirements for the coal stockpile dust control sprays.
The coal pile runoff treatment system will consist of, but not be limited to the
following:
•
•
•
•
•
•
Collection Pond
Mixing and pH adjustment tank
Sedimentation tank with clarifier
Final pH adjustment tank
Sludge thickener and sludge dewatering facilities
Chemical storage, preparation and feeding systems as required
Material Handling - Electrical Design Parameters
General Parameters
The coal handling system will be fed from the existing power plant switchyard.
150
Two sets of power transformers will be installed near the coal yard to step-down the
voltage. The power distribution configuration will consider load redundancy as well
as suitable bus voltage levels.
Electrical Equipment Rooms (EER) will be located at different load centres. Each
ERR will accommodate 1 step-down transformer(s) and MCC(s).
Power centre transformers will further step-down the voltage to supply small motors
and lightings.
Overall electrical equipment will include coal handling service power transformers,
switchgears and motor control apparatus, power centres and motor control centres,
DC system, inverter and miscellaneous electrical equipment, such as indoor and
outdoor lighting, public address and telephone communication system, grounding,
fire protection and all conduit, tray and cables necessary to complete the electrical
distribution system.
System Control, Communication and Data Transmission
All control, monitoring management and operation functions will be from a Central
Control Room (CCR). The control system will consist of a master computer for
man-machine interface, control monitoring and report generation, a colour graphic
system and a redundant PLC system for system controls.
Also located in the CCR will be the line printers, an industrial Closed Circuit
Television (CCTV) and the plant communication system.
The control system is to provide total automatic safe control for the terminal
operation and monitoring of the system and equipment with completed report
generation. The system will utilize the most technologically advanced hardware
and software approaches available.
Signal multiplexing will transmit control and monitoring signals between remote
I/O’s, the machines, and the master computer.
Status Monitoring and Data Processing
The primary PLC will contain the program for control and monitoring of the conveyor
system and provide interface data to, and receive interface data from, the PLC’s
located on each travelling machine, and monitors the dust collection and dust spray
suppression systems.
List of Major Equipment
Coal Plant
•
•
•
•
•
•
Portal Reclaimer
Transfer Conveyors
Transfer Towers
Vibrating Feeders
Metal detectors
Weigh Scale
151
•
•
•
•
•
•
•
•
•
•
•
•
•
•
5.9.1.3
Fixed and Travelling Trippers
Divertor Gates
Enclosed Storage Building
Coal Sampling Station
Receiving Hoppers
Crusher House
Dust Extraction System
Dust Suppression System
Ventilation System
HT Switchgear
Transformer
415 V MCC
Motors
PLC System
Ash Handling Process Description
General Overview
The ash handling and storage systems continuously remove ash from the furnace
bottom, air heater hoppers, economizer hoppers, and the ESP ash hoppers.
Furnace bottom ash is removed using a Submerged Scraper Conveyor (SSC),
covered under Unit 200 - Boiler. Ash is transported from the SSC discharge using a
belt conveyor to an exterior partly enclosed concrete ash storage bin. This ash is
periodically removed from the storage bin by front end loaders, loaded into trucks,
and transported to the ash disposal area.
Ash from the economizer, air heater, and ESP hoppers is transported to a common
storage silo using a positive pressure dilute phase pneumatic conveying system.
Pressure feeders complete with airlocks and hopper level indicators are provided at
all collection hopper locations. The capacity of each feeder is dependent on the
quantity of ash collected in the hopper.
Transport air for the fly ash is provided by 3 x 50% rotary positive displacement
blowers mounted in parallel and installed in a common heated and ventilated
enclosure. Transport air for the economizer ash is provided by two x 100% rotary
positive displacement blowers. Ash transport piping is made of mild steel with
ceramic lined elbows.
The steel silo is sized to store up to 3 days production of ash. Ash discharged from
the silo is conditioned to control dusting, loaded onto trucks, and transported to the
disposal area. The silo has a fluidizing bottom designed to ensure an even flow to
the unloading equipment and is equipped with level indicators, pressure relief
devices and a vent filter sized to receive air from all transport pipes operating
simultaneously.
152
Ash Production
The ash handling systems are based on the ash production rates given in Table 5.99 below:
Table 5.9-9
Option
C1-R0
C1-A1
C1-A2
C1-B1
C1-B2
C2-R0
C2-A1
C2-B1
C3-R0
C3-A1
C3-B1
Total Plant Ash Flows
Flow
kg/s
9.6
11.2
11.2
11.2
11.2
1.9
1.9
1.9
11.3
11.3
11.3
tonne/yr
256,300
300,200
300,200
300,200
300,200
51,000
51,000
51,000
302,900
302,900
302,900
List of Major Ash Handling Equipment
Bottom Ash
• Submerged Conveyor
• Transfer Conveyor
• Receiving Pad
Fly Ash
• Receiving Hoppers
• Fly Ash Conveying System
• Compressed Transport Air System
• Storage Silo c/w Fluidizing Air System
• Vent Filter
• Ash Conditioners
• Dry Unloaders
• Ventilation System
5.9.2 Civil Works (Unit 2000)
This section describes key criteria which form the basis of the civil works.
Scope of Work
The Civil Scope of Work includes earthwork, foundations and structures associated
with the following facilities:
•
•
•
•
•
•
•
Site Preparation, Grading, Feedstock Laydown Liners, and Landscaping
Site Roads
Water Supply and Fire Fighting Systems
Sewage and Site Drainage Systems
Fences and Yard Lighting
Boiler and Turbine House Buildings and Equipment Foundations
Cooling Water Tower and/or Stack Structure, including buried CW lines
153
•
•
•
•
•
•
•
•
•
•
•
•
Fuel and Ash Handling and Storage Systems
ESP Foundations
FGD Building and Equipment Foundations (if required)
Fan Foundations
Heat Exchangers
Ducting Supports
Water Treatment Plant
Waste Water Collection and Treatment Facilities
ASU plant (if required)
CO2 Compression Plant (if Required)
Mechanical Cooling Towers (if required)
Amine Based CO2 Scrubber plant
Basic Design Criteria
Site Climatic Conditions
Site conditions and climate will be based on design information from the National
Building Code of Canada (NBCC) 1995 for the following locations:
Site C1 (Keephills) - Edmonton, Alberta
• Site Elevation
645 metres ASL
• Design January Temperature (2.5%)
-32°C
(1%)
-34°C
• 15 min rain
23 mm
• One Day Rain
90 mm
• Annual Total Precipitation
460 mm
• Ground Snow Load
Ss
1.6 kPa
Sr
0.1 kPa
• Hourly Wind Pressure (1/10)
0.32 kPa
(1/30)
0.40 kPa
(1/100)
0.51 kPa
• Seismic Data
Za
0.0
Zv
1.0
Zonal Velocity Ratio 0.05
Site C2 (Pt. Tupper) – Port Hawkesbury, NS
• Site Elevation
• Design January Temperature (2.5%)
(1%)
• 15 min rain
• One Day Rain
• Annual Total Precipitation
• Ground Snow Load
Ss
Sr
• Hourly Wind Pressure (1/10)
(1/30)
(1/100)
• Seismic Data
Za
Zv
154
40 metres ASL
-19°C
-22°C
15 mm
120 mm
1450 mm
1.9 kPa
0.5 kPa
0.59 kPa
0.69 kPa
0.80 kPa
1.0
1.0
Zonal Velocity Ratio 0.05
Site C3 (Shand) – Estevan, Saskatchewan
• Site Elevation
• Design January Temperature (2.5%)
(1%)
• 15 min rain
• One Day Rain
• Annual Total Precipitation
• Ground Snow Load
Ss
Sr
•
•
565 metres ASL
-32°C
-34°C
36 mm
85 mm
420 mm
1.5 kPa
0.1 kPa
Hourly Wind Pressure (1/10)
0.42 kPa
(1/30)
0.51 kPa
(1/100)
0.62 kPa
Seismic Data
Za
0.0
Zv
0.0
Zonal Velocity Ratio 0.0
Design Loads
Dead Loads
Dead Loads will be determined according to Subsection 4.1.5 “Dead Loads” of the
NBCC. Dead loads include the self weight of the structural steel and all
construction materials permanently fastened to it or supported by it.
Live Loads
Live loads will be based on Subsection 4.1.6 “Live Loads due to Use and
Occupancy” of the NBCC.
Snow, Ice, and Rain Loads
Design loads due to snow, rain, and ice will be based on Subsection 4.1.7 “Live
Loads Due to Snow, Ice, and Rain of the NBCC 1995, and Commentaries H and I.
Wind Loads
Design wind loads will be determined according to Subsection 4.1.8 “Live Loads
Due to Wind” of the NBCC 1995, and Commentary B.
Earthquake Loads
The design earthquake load will be based on Subsection 4.1.9 “Live Loads due to
Earthquake” of the NBCC 1995, and Commentary J.
155
Material Specifications
Cast-in-Place Concrete
Cast-in-Place Concrete will conform to CSA A23.1 and have a minimum
compressive strength of 35 MPa at 28 days.
Structural Steel
Structural steel will conform to CAN/CSA S16.1 with yield strengths of 300 MPa and
350 MPa.
Building Cladding
Buildings will have cladding systems consisting of steel exterior sheets sized to
resist the design wind loads, with 50 mm of semi rigid insulation, and an interior
steel liner sheet.
Roofing
Major buildings will have flat roof systems consisting of insulated two ply modified
bitumen roofing systems. Smaller building costs were based on insulated steel
cladding systems.
Standards
The project will be designed, fabricated, procured, constructed and operated in
compliance with applicable Codes and Standards such as:
•
•
•
•
•
•
•
Alberta Building Code
Alberta Occupational Health and Safety Act
American Society of Testing and Materials
Canadian Electrical Code
Canadian Institute of Steel Construction
Canadian Standards Association
Factory Mutual
Foundation & Structural Design
Soil conditions at both the Keephills and Shand sites are expected to have
moderate to poor bearing capacity. Major buildings and equipment foundations will
be assumed to need caisson or pile foundations with an average depth of 10 metres
at both locations. The Pt. Tupper site is expected to have a relatively thin soil layer
over bedrock. An average soil depth of approximately 2 metres is anticipated.
All buildings, facilities and infrastructure will be designed to CSA specifications and
the Alberta Building Code for Keephills or the National Building Code of Canada for
Shand and Pt. Tupper. Wind and earthquake loading will adhere to conditions
outlined in the Commentary to the National Building Code. Occupancy and
classification of the buildings will be in accordance with the National Building Code
and the Alberta Building Code.
156
5.9.3 Electrical Systems (Unit 2000)
Electrical System Criteria
AC Power Systems
•
•
•
•
•
Primary power supply to the plant will be at 138 kV.
Secondary power voltage will be at 6900 volts resistance grounded, and
600/347volt resistance grounded.
Lighting will be supplied at 600/347and 120/208V.
Miscellaneous power for single phase motors, chart recorders, solenoids, etc.
will be at 120V.
600V motor control voltage will use120V.
Wiring System
Station wiring will be based on TECK 90 cable in cable trays.
Grounding System
Allowance will be made for building, structural steel, electrical equipment, and large
motor grounding. A station ground mat will be included with interconnections to
various building systems. The main sub grade ground system will consist of closed
cable loops of bare copper cable run around and across the perimeter of the
building structures and connected to the main station ground mat. Cables will be
connected to driven ground rods at sufficient intervals to provide a uniform potential
gradient throughout. Perimeter grounds will be connected by risers to building steel
columns.
Building Services
Building service requirements will be provided by the Service and Distribution AC
power system which will take power from the LV power system, transform it to a
suitable working voltage(s), and distribute it to load centres or panel boards. This
will provide power for such services as lighting and receptacles. System working
voltages will be 120/208 volts and 347/600 volts. Transformers will transform three
wire supplies into four wire supply for building services. Secondary windings will be
wye connected and solidly grounded.
The LV power supplies will originate from 600V motor control centres.
Distribution
Panel boards will be used to distribute building services power.
157
Lighting
Building services lighting supplies will be 120/208 volts, three phase or 347/600
volts, 3 phases, as required. In general, lighting will be 347 volts for economies
inherent in the higher voltage system. Primary 600 volt power will be taken from
motor control centres, as required.
Yard lighting will be accomplished, wherever possible, by floodlights from buildings.
Wood poles will be used as required in areas when the lights cannot be mounted on
the buildings.
Power Systems
Main Power Supply
The station electrical systems will feed from the 138kV switchyard located
approximately 200 metres from the boiler/turbine-generator site. Insulated 138kV
cables will be used to supply the Unit and Station Auxiliary Transformers. The
cables will be installed in a trench/tunnel complex.
Allowance will be made for interconnection of differential protection as well as
interconnection of grounding systems.
The Unit Transformer and primary 138kV cable will be sized to allow full generator
output capacity to be supplied to the 138kV system.
Unit Power System
An Isolated Phase Bus (IPB) will be used to interconnect the generator and Unit
Transformer based on a Unit output voltage of 26kV and 14kA ampacity. The IPB
will be used to interconnect and supply the Unit Service Transformer and the
excitation system.
The Unit power distribution system will have A and B redundancy. The Unit Service
Transformer will have dual secondary windings to supply the A and B busses. The
medium voltage system (MV) is assumed to be 6.9kV due to the anticipated high
horsepower ratings of the MV motors and other distribution system parameters.
Motors above 250 horsepower will be supplied from the MV system.
A and B MV unit switchgear will be provided to distribute Unit MV power. This
switchgear will directly supply boiler MV motors, boiler MV Variable Frequency
Drives, 600V unit substations and motor control centres and will be used to supply
A and B switchgear located at the FGD installation. The Unit A and B switchgear
will be provided with interconnection to the Station Service Power System for power
supply when the Unit is off or has not reached minimum load levels for transfer to
the turbine-generator source. An MV breaker switching scheme will be used to
automatically transfer the source to the turbine-generator or back to the Station
Service supply. This interconnection provides backup for the Unit Service
Transformer.
158
Station Service Power System
The Station Service power system will supply start-up power to the unit and power
to common systems. The Station Service power system will be an A and B MV
redundant system. The Station Service Transformer will be provided with dual
secondary windings used to supply A and B MV busses. The assumed medium
voltage (MV) is 6.9kV.
A and B MV switchgear will be provided for distribution of Station Service MV
power. This switchgear will directly supply common MV motors, common 600V unit
substations and motor control centres. The Station Service A and B MV switchgear
will be provided with interconnection to the Unit power system for power supply
when the Unit is off or has not reached minimum load levels for transfer. An MV
breaker switching scheme will be used to automatically transfer the source to the
turbine-generator or back to the Station Service power system.
Uninterruptible AC Power System
Uninterruptible AC power will be supplied by UPS systems. Allowance will be made
to provide A and B UPS systems for the boiler/turbine-generator area and to supply
A and B UPS systems for the FGD area. UPS systems will be supplied from AC
Emergency Power supplies in appropriate motor control centres.
DC Power System
DC power will be supplied by A and B 125V DC battery systems. Allowance for DC
power systems will be made in the boiler/turbine-generator area and the FGD area.
A and B systems will be cross connected to permit battery maintenance, battery
charging and system management.
Process Electrical Systems
Boiler, Turbine-Generator, FGD, ASU, Amine Scrubbing, and CO2 Compression
Areas
The electrical systems for the boiler, turbine-generator, FGD, ASU, Amine
Scrubbing, and CO2 Compression areas include:
•
•
•
•
•
MV power distribution systems,
600V power distribution systems, including allowance for emergency power,
UPS AC power systems,
DC power systems and
Building services systems.
An allowance will be made to provide MV variable frequency drives for the induced
draft fans and the primary air fans.
5.9.4 Instrumentation and Control (Unit 2000)
A Distributive Control System (DCS) with Human Machine Interface (HMI) operator
stations shall be provided to execute all process control and monitoring functions,
159
such as closed loop control, indication trending and alarming. The DCS control and
rack room(s) shall be centrally located in the boiler house. The DCS PCU cabinets
will be housed in the rack room(s) and shall contain power supplies, control
processors, racks, I/O modules, communication hardware, etc.
Marshalling
cabinets shall be supplied to manage field cables and provide tidy cable installation
in the PCU cabinets. Remote I/O cabinets will be utilized in remote areas such as
the FGD building, cooling tower etc. and will communicate with the DCS via fibre
optic cabling.
Instrumentation and control valve technology and materials of construction shall be
selected to suit process and ambient conditions. All field instruments will be cabled
back to the appropriate DCS marshalling cabinet using suitable multi-pair and multiconductor cabling as required.
A Continuous Emissions Monitoring System (CEM) shall be installed for flue gas
monitoring. The system will comply with requirements of the Provincial Air
Monitoring directive and will monitor O2, CO2, SO2, NOx, CO and Opacity. The
Continuous Emissions Monitoring system shall have its own PLC controller that will
perform all associated hardware control, provide data processing and will
communicate via fibre optic cabling to the plant DCS.
5.9.5 Heat Rejection System (Unit 2000)
The purpose of the Heat Rejection system is to remove and dispose of waste heat
from the condenser and various other heat sources. The Keephills (C1) and Shand
(C3) sites will use natural draught cooling towers incorporating a flue gas exhaust
system to reject heat, while the Pt. Tupper (C2) site will use a sea water cooling
system, with a separate stack for the flue gas exhaust.
General Description
The cooling system is assumed to be a stand alone system with no connection to
other units. The C1 and C3 sites will include a natural draught cooling tower and a
cooling water basin. Retrofitted CO2 capture options are assumed to have been
built with smaller natural draught towers, and supplemental mechanical draught
cooling towers will be required. The C2 site will use a shore line sea water intake
and discharge structures. All sites will have a CW pumphouse with pumps and
screening equipment, concrete pipes to and from the steam turbine condenser, and
connections to and from the other areas of the plant needing cooling, which are
described later.
Cooling Tower
The natural draught tower will reject heat from the steam cycle and other areas, as
well as be used as a stack for flue gas exhaust. Natural draught towers have the
following advantages over mechanical draught towers:
•
•
•
No hot air recirculation and less sensitive to wind
Low noise (no fans)
Can be placed anywhere on site
160
•
Station service (parasitic power consumption) remains about 60-65% of
mechanical draught systems
Natural draught towers feature both direct (evaporative) and indirect (dry) cooling.
The tower typically consists of a hyperbolic concrete or alu-clad steel structure.
With this design it is possible to direct the flue gas duct to the bottom of the tower.
Due to the flue gas buoyancy the natural draught of the tower is enhanced, and the
necessity for a stack eliminated. The dispersion characteristics of the flue gas and
tower plume are also improved.
Two sizes of natural draught towers have been used in the study, to serve both a
CO2 capture plant, and a unit originally built without CO2 capture.
The smaller tower (89m in diameter and 108 m high) was designed to cool
40,820m3/hr of water by 11°C at a design wet bulb temperature of 18.6°C.
Evaporative losses were calculated at 670m3/hr, with drift losses at 0.00088% of the
total water flow (0.4m3/hr). The larger tower (108m in diameter and135m high) was
designed to cool 67930m3/hr of water by 11.8°C at a design wet bulb temperature
of 20.9°C.
CW Pumphouse (Cooling Tower)
The CW pumphouse will be integrated with the tower basin. Both horizontal and
vertical pumps have been considered, but site grading and drainage appears to rule
out a non-floodable pumphouse and, therefore, vertical pumps are be used.
Simple, double, removable screens will be placed in the tower return water
channels to protect the pumps. As planned pump maintenance would normally be
done in the winter, the pumphouse will be enclosed, heated and equipped with
suitable cranes for maintenance.
Sea Water Intake
The sea water intake for the Pt. Tupper site is expected to be a concrete box
structure; approximately 20m wide by 15m deep by 10m high, excavated and sunk
in place beyond the low tide line to bring in moderately deep cooling water. The
pump house will be just behind the intake on the shore line. The seawater will flow
from the intake’s screening chamber to pumping chambers, driven by 3 x 50% C.W
pumps.
Each unit will have two bar screens and one straight through screen with stop gate
facilities before and after the screens to facilitate isolation. 3 x 50% duty screen
washing pumps will be provided each capable of supplying wash water to all
traveling screens as well as the requirements of the screening and trash disposal
system.
The discharge structure will be a concrete retaining wall at the end of the CW
pipeline and a canal returning warm water to the sea.
161
CW Conduits
The circulating water pumps discharge through butterfly valves into a rubber-lined
common header which is provided with connections to feed each of the units
through concrete circulating water pipe. The diameter of this pipe will be 10’. If
required, short steel sections will be rubber lined.
The distribution and return lines to and from the individual systems will be of the
following diameters:
•
•
•
Condenser – 200mm
Amine System – 150mm (if required)
Compression System – 75mm (if required)
These will then divide into the appropriate diameter pipes for the supply and return
lines for the individual heat exchangers.
16” diameter supply and return lines will also be provided to feed the 2 x 100%
closed loop cooling glycol heat exchangers. Booster pumps will be provided to
supply these heat exchangers. Automatic air vent valves will be provided in the
return from the condenser.
Closed Loop Cooling
The 2 x 100% closed loop cooling glycol heat exchangers will be serviced with
400mm diameter supply and return lines complete with booster pumps. 2 x 100%
duty (or 4 x 50%) heat exchangers will be installed to meet this requirement. During
extreme CW temperature excursions heat exchangers are expected to be placed in
series on the closed loop side. All auxiliaries in the station will be cooled by the
system.
Design Parameters
The design flows are given in the Tables below for the 11 site options. For the C1
site the tables are based on the assumption of an 11°C temperature gain in the
cooling water in all systems. The supplied cooling water has a mean temperature
of 14°C and maximum temperature of 22.5°C.
Table 5.9-10
System
C1-R0 Heat Rejection System
Heat Rejected (MW)
Cooling Water Flow (kg/s)
Condenser
508
11,040
Closed Circuit Cooling
14
300
Total (kg/s)
11,340
Total (m3/hr)
40,820
162
Table 5.9-11
System
C1- A1 Heat Rejection System
Heat Rejected (MW)
Cooling Water Flow (kg/s)
Condenser
508
11,040
ASU Cooling
14
305
Flue Gas Cooling (DCC)
64
1395
CO2 Compression
15
330
Closed Circuit Cooling
14
300
Total (kg/s)
13,370
Total (m3/hr)
48,130
For the C1-A2 case the cooling tower is sized assuming the C1-R0 plant is built
first, and the CO2 capture facilities are retrofitted afterward. The cooling
requirements for the ASU and CO2 compression plants will be handled by
mechanical draught towers built as part of the retrofit. Table 5.9-11 only addresses
additional cooling demand with respect to the retrofitted ASU and CO2 compression
plants.
Table 5.9-12
System
C1- A2 Heat Rejection System
Heat Rejected (MW)
Cooling Water Flow (kg/s)
14
305
15
330
ASU Cooling
CO2 Compression
Total (kg/s)
3
Total (m /hr)
635
2,290
For the C1-B1 case boiler feedwater is applied for cooling of 61MW of the
regenerator cooling. This is equivalent to 1,330kg/s or 4,790m3/hr of cooling water.
Thus the total required cooling water flow is actually 53,570m3 per hour rather than
the 58,360m3 per hour noted.
For the C1-B2 case the cooling tower is sized assuming the C1-R0 plant is built
The cooling
first, and the CO2 capture facilities are retrofitted afterward.
requirements for the Amine Scrubbing and CO2 compression plants will be handled
by mechanical draught towers built as part of the retrofit. Table 5.9-14 only
addresses additional cooling demand with respect to the retrofitted amine scrubbing
and CO2 compression plants.
For the C2 site the tables are based on the assumption of a 13°C temperature gain
in the cooling water for all systems. The supplied cooling water has a mean
temperature of 5°C and maximum temperature of 6°C.
163
Table 5.9-13
System
C1-B1 Heat Rejection System
Heat Rejected (MW)
Cooling Water Flow (kg/s)
345
7,500
Condenser
Flue Gas Cooling
56
1,220
Absorber Wash Water Cooling
116
2,520
Regenerator Condenser
72
1,560
Lean Solution Cooling
75
1,630
CO2 Compression
68
1,480
Closed Circuit Cooling
14
300
Total (kg/s)
16,210
3
Total (m /hr)
Table 5.9-14
System
58.360
C1- B2 Heat Rejection System
Heat Rejected (MW)
Cooling Water Flow (kg/s)
Flue Gas Cooling
56
1,220
Absorber Wash Water Cooling
116
2,520
Regenerator Condenser
72
1,560
Lean Solution Cooling
75
1,630
CO2 Compression
68
1,480
Total (kg/s)
8,410
3
Total (m /hr)
Table 5.9-15
System
30,280
C2-R0 Heat Rejection System
Heat Rejected (MW)
Cooling Water Flow (kg/s)
Condenser
508
9,340
Closed Circuit Cooling
14
260
Total (kg/s)
9,600
3
Total (m /hr)
Table 5.9-16
System
34,560
C2- A1 Heat Rejection System
Heat Rejected (MW)
Cooling Water Flow (kg/s)
Condenser
508
9,340
ASU Cooling
14
260
CO2 Compression
14
260
Closed Circuit Cooling
14
260
Total (kg/s)
9,860
Total (m3/hr)
35,520
For the C2-B1 case boiler feedwater is applied for cooling of 61MW of the
regenerator cooling. This is equivalent to 1,120 kg/s or 4,040 m3/hr of cooling
water. Thus the total required cooling water flow is actually 40,095 m3 per hour
rather than the 44,135 m3 per hour noted.
164
Table 5.9-17
System
C2-B1 Heat Rejection System
Heat Rejected (MW)
Cooling Water Flow (kg/s)
Condenser
345
6,340
Flue Gas Cooling
40
735
Absorber Wash Water Cooling
100
1,835
Regenerator Condenser
52
955
Lean Solution Cooling
56
1,030
CO2 Compression
60
1,105
Closed Circuit Cooling
14
260
Total (kg/s)
12,260
Total (m3/hr)
44,135
For the C3 site the tables are based on the assumption of an 11°C temperature
gain in the cooling water in all systems. The supplied cooling water has a mean
temperature of 16°C and maximum temperature of 24.8°C.
For the C3-B1 case boiler feedwater is applied for cooling of 61MW of the
regenerator cooling. This is equivalent to 1,330kg/s or 4,790m3/hr of cooling water.
Thus the total required cooling water flow is actually 49,970m3 per hour rather than
the 54,760m3 per hour noted.
Table 5.9-18
System
C3-R0 Heat Rejection System
Heat Rejected (MW)
Cooling Water Flow (kg/s)
Condenser
508
11,040
Closed Circuit Cooling
14
305
Total (kg/s)
11,345
3
Total (m /hr)
Table 5.9-19
System
40,840
C3- A1 Heat Rejection System
Heat Rejected (MW)
Cooling Water Flow (kg/s)
Condenser
508
11,040
ASU Cooling
14
305
CO2 Compression
16
350
Direct Contact Cooler
208
4,520
Closed Circuit Cooling
14
305
Total (kg/s)
3
Total (m /hr)
165
16,520
59,465
Table 5.9-20
System
C3-B1 Heat Rejection System
Heat Rejected (MW)
Cooling Water Flow
(kg/s)
Condenser
345
6,340
Flue Gas Cooling
56
1,220
Absorber Wash Water Cooling
115
2,500
Regenerator Condenser
72
1,560
Lean Solution Cooling
75
1,630
CO2 Compression
76
1,655
Closed Circuit Cooling
14
305
Total (kg/s)
3
Total (m /hr)
15,210
54,760
5.9.6 List of Major Equipment
Civil Works
Civil Works does not include a list of major equipment. Instead, the following is a list
of major buildings/structures.
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
Boiler House
Air Heater/SCR Building
Boiler Feed Pump Building
Coal Mill Building
Turbine Hall
Turbine Hall Electrical Building
LP Heater Building
FGD Building
DeHg Building
Precipitator Foundations
Cooling Tower and Pumphouse (Sites C1 and C3)
Wet Stack (Site C2)
Pumphouse and Sea Water Intake (Site C2)
Cooling Water Piping
Waste Water Treatment Plant
Water Treatment Plant
Coal Crusher Building
Coal Receiving Structure
Active Coal Storage Building(s)
Coal Reclaim Hopper and Tunnel
Coal Sampler Building
Limestone Reclaim System
Limestone Silos
Fly Ash Silo
Bottom Ash Pad
DeHg Building
Amine Scrubbers Building and Equipment Foundations (B1 and B2 Options)
CO2 Compression Building and Equipment Foundations (B1 and B2 Options)
166
Electrical Works
•
Main Transformers
Heat Rejection System
•
5.10
Cooling Water Pumps
PROJECT SCHEDULE
The schedules for the R0, A1, A2, and B1 options have estimated durations of
approximately 60 months from Corporate Project Approval to Unit in Service. This is
considered the minimum practicable time for this type of project bearing in mind the
high demand currently experienced by most equipment vendors. The critical path
for these projects is determined by the boiler schedule, which has a time frame of
10 months for Design, Specifications, and Tendering, 24 months for Manufacture
and Delivery, 13 months for Erection, and 12 months more for Unit in Service.
The schedule was developed with minimum durations on the critical path and
overlapping activities in the preliminary phases, ie it has been assumed the boiler
and turbine can both be tendered and conditionally awarded prior to Notice To
Proceed, and that Corporate Approval can be given based on the capital cost
estimate, prior to all technical information being available for the environmental
study submission.
Booking shop space for the boiler manufacture will be a key schedule constraint.
Boiler suppliers’ quoting are expected to be between 42 months to 54 months from
order placement to Unit In Service as a result of uncertainty of shop availability in
the foreseeable future.
The weather is also a key constraint on the critical path for boiler pressure parts
erection. The powerhouse must be enclosed and heated (if necessary) for pressure
parts erection, otherwise an additional 6 months needs to be added to the schedule.
Manpower availability can also impact the critical path. A slightly longer duration for
pressure parts erection may be required if too few qualified boilermakers are
available.
Other considerations that could impact the schedule include the requirement for
combined erection of boiler ductwork and boilerhouse primary structural steelwork,
and potential weather impact on powerhouse foundation construction. Ideally, piling
will be timed to be done while the ground is frozen, and pile caps and grade beams
constructed during the warm weather.
The schedule for B2 differs from the other options in that it is the only one not
involving a new or modified boiler. The critical path for the project is determined by
167
the Amine Scrubber based CO2 capture plant which has 11 months allocated for
Design, Specifications, and Tendering, 11 months for Manufacture and Delivery, 24
months for Erection, and 2 months more for Commissioning.
The CO2
Compression Plant has a similar schedule that includes 9 months for Design,
Specifications, and Tendering, 12 months for Manufacture and Delivery, 20 months
for Erection, and 2 months more for Commissioning.
168
6.
ECONOMIC ANALYSIS
6.1
PLANT CAPITAL COST
Capital costs were estimated for the five Keephills (C1) plant options. All estimates
are in 2006 Canadian dollars and have an overall accuracy range of ±30%.
6.1.1 Basis of Estimate
Costs for major equipment islands were provided by the follow consortium partners:
•
DoosanBabcock
− Unit 200 - Boiler Island
− Unit 300 - DeNOx Plant
− Unit 550 - Main Flue Gas Heat Recovery
•
Alstom Power
− Unit 700 – Turbine Generator Plant
•
Mitsubishi Heavy Industries
−
−
−
−
•
Unit 400 – DeHg Plant
Unit 600 – FGD Plant
Unit 800 – CO2 Amine Scrubber
Unit 900 – CO2 Compression Plant (B1/B2)
Air Products
− Unit 650 – Flue Gas Direct Contact Cooler
− Unit 1100 – Air Separation Unit
− Unit 1200 – CO2 Compression Plant (A1/A2)
In addition ±30 percent budget estimates were requested from several precipitator
and natural draught cooling tower vendors and a selected response was included in
the final estimate. All other costs were developed using in-house Neill and Gunter
figures. The costs presented in this section exclude:
•
•
•
•
•
•
Owner’s costs
Interest during construction
Environmental approval costs
Insurance, fees, and legal costs
Operations and plant assistance costs
Taxes
Allowances for these items were included in Section 14 for the economic analysis of
the five Keepkills options.
169
Where applicable the following exchange rates were used:
•
•
•
1.00 US$ = $1.15 CAN
1.00 € = $1.5 CAN
1.00 ₤ = $ 2.20 CAN
The labour rate used for all erection costs is $100 per hour, based on an average of
current union trade rates. This rate includes all contractor benefits, small tools, site
supervision/administration, construction trailers, consumables, construction
equipment, overhead and profit. Labour productivity is taken as 1.35 based on a
northern Alberta site. All construction labour costs are based on an 8 hour/5 day
work week.
Indirect costs include:
•
•
•
•
Engineering and head office costs
Construction costs
All site temporary facilities and services costs
Commissioning costs
These costs are estimated as percentages of total project direct costs based on
previous detailed estimates for similar projects. It is assumed that engineering for
the main equipment islands, boiler, turbine-generator, ASU plant, FGD Plant, Amine
Scrubber, and CO2 Compression Plant, is included in the received quotations.
Construction Management and Head Office Engineering costs are estimated
excluding the supply costs of these items. This is consistent with the supply of
major equipment islands being based on EPC contracts, with the remainder of the
work being engineered and managed locally.
A 20 percent contingency is added to the estimate to cover undefined work that can
be expected to occur during the life of the project.
6.1.2 Cost Estimates
The capital cost estimates are developed in accordance with the Neill and Gunter
Work Breakdown System given in the Proposal. Tables 6.1-1 to 6.1-5 provide
summary of the estimates, It can be seen that the Oxyfuel based plant has a slightly
higher capital cost than corresponding Amine Scrubber based plant. However a
retrofitted oxyfuel facility was found to be significantly more expensive than a
retrofitted amine scrubber, due to the need to demolish a portion of the powerhouse
and boiler to build the oxyfuel system.
6.1.3 Discussion Of Results
Total Capital Requirement (including Owner’s Cost) for the five C1 options are
estimated to be:
C1-R0:
C1-A1:
C1-A2:
CA$ 1,757,908,648
CA$ 2,448,430,469
CA$ 1,079,674,573
170
C1-B1:
C1-B2:
CA$ 2,320,170,586
CA$ 573,163,568
As expected, the total cost for the retrofitted oxyfuel plant (R0 + A2) is significantly
higher than the basic oxyfuel option (A1), CA$ 2,837,583,221 compared to CA$
2,448,430,469, an increase of $ 389.2 million. The major cost increases for the A2
plant compared to A1 include CA$107.3 million for an FGD system required for the
A2 option, and CA$ 109.3 million for boiler costs related to the retrofit. Much of the
additional cost increases are due to indirect construction and head office costs
caused by the higher direct capital charges.
The total cost for the retrofitted Amine scrubbing plant (R0 + B2) is slightly higher
than the basic Amine scrubbing option (B1), a result which was expected. The
retrofitted plant’s capital cost totalled CA$ 2,331,072,216 compared to the B1
plant’s estimate of CA$ 2,320,170,586, an increase of CA$ 10.9 million. When the
costs were compared, the largest single cost saving for B1 was for the turbine
generator at CA$ 12.6 million. Some B1 indirect costs were calculated to be higher
than the combined retrofitted plant due to difference in equipment island costs
omitted from the calculations described in Section 6.1.2.
A comparison of the base case Oxyfuel (A1) and Amine scrubbing plant (B1) show
the oxyfuel plant to be more expensive in CAPEX by CA$ 128,259,883, a significant
amount. The B1 plant has some significant costs not required for A1 including
CA$107.3 million for an FGD system and CA$ 293.2 million for the Amine scrubbing
CO2 capture and compression plants, as well as minor savings such as CA$ 22.9
million for the steam generator and CA$ 11.3 million for the turbine-generator.
However, the cost of the A1 ASU plant at CA$ 303.6 million and CO2 Compression
Plant at CA$ 193.6 million more than make up for these cost advantages. Most of
the additional cost differences between the options are due to indirect construction
and head office costs caused by the different direct capital charges.
The total cost of a retrofitted oxyfuel plant (A2) is found to be CA$ 506.5 million
more expensive than a retrofitted amine scrubbing plant (B2). The extra costs for
the modifying the steam generator and associated building changes of
approximately CA$116.9 million, plus the ASU plant of $ 303.6 million, are much
higher than the amine scrubbing plant’s CO2 capture system’s price of CA$ 293.2
million. The oxyfuel plant’s retrofitted mechanical cooling system however is
smaller and less costly, by CA$ 12.8 million, than the amine scrubbing plant’s
system.
In summary, the capital costs for the five C1 options were compared, and their
differences found to be reasonable given the scope of work involved with each
option.
6.2
Plant O&M Costs
Operating and maintenance costs were estimated for the Keephills (C1) options.
Summaries of the results are provided in the following sections.
171
6.2.1 O&M Cost Parameters
The following parameters are used to estimate operating and maintenance costs.
Table 6.2-1
O&M Cost Parameters
Fuel Cost
$14/tonne
Plant Capacity Factor
85%
Limestone Cost
$20/tonne
Fresh Water Cost
$0.04/tonne
Waste Water Treatment Cost
$0.26/tonne
Gypsum Landfill
$5/tonne
Boiler Ash Landfill
$5/tonne
Amine Cost
$5/kg
Caustic Cost (100% wt)
%0.35/kg
SCR Catalyst Cost
$10,800/m3
Ammonia Cost
$330/tonne
HC1 Cost
$96/tonne
Full Time Employee (FTE) Salary
$85,000/year
6.2.2 Summary of O&M Costs
Table 6.2-2
C1-R0
C1-A1
C1-A2
C1-B1
C1-B2
Summary of O&M Costs (Year 1)
Fixed Costs ($/yr)
4,625,000
5,050,000
5,050,000
5,475,000
5,475,000
Variable Costs ($/yr)
9,051,600
9,487,900
10,734,300
15,493,900
17,499,600
Total O&M ($/yr)
13,676,600
14,397,600
15,784,300
20,968,900
22,974,600
6.2.3 Solid and Liquid Wastes
The following table presents estimated solid and liquid wastes for the C1 options. It
must be noted that no reuse of treated waste water has been assumed. In practice,
large portions of the waste water can probably be reused to offset fresh water
consumption.
Table 6.2-3
Option
C1-R0
C1-A1
C1-A2
C1-B1
C1-B2
Solid and Liquid Waste
Ash
(tonne/yr)
257,300
300,200
300,200
300,200
300,200
Gypsum
(tonne/yr)
23,200
-23,200
23,100
23,100
172
Waste Water
(tonne/yr)
1,359,000
2,184,415
1,380,287
1,733,728
2,650,078
6.3
ECONOMIC ANALYSIS
6.3.1 Economic Model
The capital and operating costs presented in Sections 6.1 and 6.2, along with
selected plant process flows, were combined into a series of Excel spreadsheets
that calculated economic parameters for the five Keephills (C1) options.
Selected inputs to the Excel models are shown in Table 6.3-1. The economic model
for each option consists of eight separate tables. Table 6.3-2 provides all the inputs
and key outputs used in the analysis. Plant data, capital and operating costs, and
financial parameters are input in Table 6.3-2 in shaded cells. Output summaries and
other calculated values are shown in un-shaded cells. Key output summaries are
the three sections to the right of Table 6.3-2 that provide 40 year levelized costs for
the Total Plant and CO2 Capture Plant in cents per kWh, and the cost of CO2
capture in $ per tonne.
Parasitic energy cost is calculated by assuming that the full base plant output of
503.3 MW is available for sale for all options, with parasitic power and heat
requirements being purchased off site using the base case (C1-R0) production cost.
The levelized costs for the CO2 Capture Plant (C1-A1 and C1-B1 options) are taken
as the difference between the Total Plant Cost for the option under study and the
base case (C1-R0) Total Plant Cost.
Table 6.3-1
Inputs for Economic Analysis
Decommissioning Cost
4 % of Capital
Project Life
40 years
Coal Price
$14 per tonne
Capacity Factor
0.85
Debt Financing
50%
Preferred Shares Financing
10%
Common Shares Financing
40%
Return on Debt
7%
Return on Preferred Shares
5%
Return on Common Shares
10%
Inflation Rate
2%
Interest on Sinking Funds
6.5%
Federal Tax Rate (Preferred)
40%
Federal Tax Rate
28%
Alberta Tax Rate
14.5%
Capital Tax Rate
.225%
Capital Cost Allowance
4%
173
6.3.2 Economic Analysis Results
The results of the economic and performance analysis are presented in Table 6.3-2
and Table 6.3-3, and the economics are summarized in Figures 6.3-1, 6.3-2, and
6.3-3.
The Table and Figures show the most economic option for CO2 capture, given the
study’s inputs, is the oxyfuel plant with a levelized cost of CA$ 47.5 per tonne of
CO2 captured. The cost of a retrofitted oxyfuel plant is substantially higher at CA$
68.0 per tonne of CO2. This is primarily due to:
•
•
The additional capital costs discussed in the previous section.
The higher O&M costs for a retrofitted plant due to the less efficient cooling
system and the need to operate an existing FGD plant not present in the A1
case.
The costs for Tables 6.3-2 and 6.3-3 do not take into account the lost generation a
retrofitted option would cause while the unit is off line during construction.
Table 6.3-2
OPTION
Summary of Costs and CO2 Emissions
C1-R0
C1-A1
C1-A2
C1-B1
C1-B2
Capital Cost (CA$ x 106)
$1,757.9
$2,448.4
$1,079.7
$2,320.2
$573.2
Levelized Fuel and O&M Costs
(CA$ x 103) Per Year
$48,263.4
$48,926.5
$51,020.4
$57,148.1
$59,519.7
Levelized Cost of Electricity
(¢ per kWh)
6.475
9.860
4.694
9.827
3.435
Levelized CO2 Capture Cost
(CA$ per tonne)
--
$47.76
$66.76
$48.82
$50.04
2,960.6
242.9
325.7
387.8
387.8
CO2 Emissions (t x 1000)
Table 6.3-3
Levelized Cost of CO2 Capture (CA$ Per Tonne)
C1-A1
C1-A2
C1-B1
C1-B2
Capital
21.934
34.564
18.435
18.792
Tax
6.822
10.750
5.734
5.845
O&M
0.365
1.042
3.450
4.372
Parasitic Energy
18.755
20.403
21.196
21.027
Limestone
-0.115
--
--
--
CO2 Credit
--
--
--
--
Total Cost
47.76
66.76
48.82
50.04
Table 6.3-3 breaks down the levelized cost of CO2 capture by the main cost
categories of capital, taxes, O&M, parasitic energy, and credits. It is assumed that
no CO2 credits are received. The table shows energy losses required to operate
equipment directly related to CO2 capture are one of the largest cost items, closely
followed in most cases by capital charges. C1-A1’s lack of an FGD plant helps to
174
limit its O&M costs compared to the other options. This savings over the R0 case is
included in A1’s overall evaluation, also somewhat reducing its capital and
operating charges. Parasitic energy was developed by the consortium partners and
priced based on C1-R0’s estimated levelized cost of production. These costs are
found to be reasonably close for all study options, with the amine scrubber based
plants (B1 & B2) only slightly more expensive than the oxyfuel plants (A1 & A2).
O&M costs in contrast are found to make up a relatively minor portion of the total
charges. The B1 and B2 plants captured slightly less CO2 than the A1 and A2
plants, and this tended to increase their $ per tonne CO2 capture costs. These
results in general were expected given the high costs to build the CO2 capture
plants and the significant energy demands needed to operate both the Oxyfuel and
Amine scrubbing plants.
40 Year Levelized Cost (¢ per kWh Generation)
5.000
4.694
4.000
3.000
3.384
3.435
3.351
2.000
1.000
0.000
A1
A2
B1
1
B2
C1 (Keep Hills) Plant Options
40 Year Levelized Cost ($ per Tonne CO2 Captured)
Figure 6.3-1 Cost of CO2 Capture (¢ per kWh)
70.00
$66.759
60.00
50.00
$48.818
$47.760
$50.036
40.00
30.00
20.00
10.00
0.00
A1
1
A2
B1
B2
C1 (Keep Hills) Plant Options
Figure 6.3-2 Cost of CO2 Capture (CA$ per tonne CO2)
175
12
11
11.025
40 Year Levelized Cost of Electricity (Cents per kWh)
10
9.860
9.827
9.910
B1
B2
9
8
7
6
6.475
5
4
3
2
1
0
R0
A1
A2
C1 (Keephills) Plant Options
Figure 6.3-3 Cost of Electricity (Cents per kWh)
176
7. RECOMMENDATION FOR FUTURE R&D
The principle equipment development requirements leading to possible
demonstration of the CO2 capture technologies as perceived by the Project Partners
are outlined below.
Follow on projects would be sought to further strengthen the relationship between
the partners and between UK and Canada. These projects are likely to focus on
how best to develop and promote the introduction of CO2 Capture-ready/CO2
Capture supercritical boiler technology into Canada and elsewhere.
Comments and recommendations from the various project partners/collaborators for
future R&D and future collaboration are summarised below.
Boiler Island: Oxyfuel & Amine
1. Safety, Operability & Flexibility: Oxyfuel & Amine : To review and thoroughly
address the safety, operability and plant flexibility issues for each of the CO2
capture/capture power plant cases considered within BERR-366; of particular
interest to Doosan Babcock are the C1 and C2 power plant cases considered.
RWE (UK) is lead on the CASS-Cap project proposal to the UK BERR,
collaborating with Doosan Babcock, Alstom and Imperial College and others.
This proposed project aims to investigate further the safety, operability and
flexibility issues for post-combustion capture power plant.
2. Range of Coals/Fuels: ASC & Oxyfuel & Amine: To investigate the impact of the
full range of coals/fuels proposed to be fired on the overall boiler island and
power plant performance. This is relevant to each of the three power station
sites considered in this study, namely: C1:Keephills, C2: Point Tupper and C3:
Shand; of particular interest to Doosan Babcock are the C1 sub-bituminous
cases and the C2 bituminous cases.
3. RAH vs TAH: Oxyfuel: To carry out a thorough techno-economic evaluation of
the use of a RAH vs TAH weighed up against the techno-economic impact of the
resultant oxyfuel flue gas composition on ASU/oxygen consumption and CO2
compression plant cost and performance.
4. Oxyfuel Demonstration: Demonstration of key components of the Boiler Island
for oxyfuel combustion is required as the next logical step. This particularly to
address the demonstration of the oxyfuel combustion system. In collaboration
with Air Products, Imperial College, EoN, RWE and others, Doosan Babcock is
the lead contractor on the OxyCoal-UK Phase 2 project proposal to the UK
BERR. Supported by the UK Utility Companies, this project aims to demonstrate
a utility boiler full scale oxyfuel burner/combustion system through conversion of
Doosan Babcock’s 90MWt Multi-fuel Burner Test Facility (MBTF).
Steam Turbine Island: Oxyfuel & Amine
1. The imposition of constant 60Hz market power requirements, regardless of
power plant installation, has stretched the Steam Turbine Aero-mechanical
technology to the point where LP Turbine efficiency has been compromised for
cases where condenser pressure is low due to low ambient cooling water
177
temperatures. Turbine expansion is increased within a flow-path flow area,
constrained by blade mechanics, resulting in performance loss due to excessive
flow Mach No.
2. Performance loss can be traded against the cost of increasing the number of
Double LPT modules to reduce flow Mach and flow size has been determined by
selected 60Hz power market and has been defined as 500MWe without CO2
capture and 400MWe with CO2 capture.
3. Thermo Economic optimisation studies for individual power plant installations
would produce different solutions for every installation in terms of power size
and
turbo-machinery
configuration
and
provide
a
basis
for
commonisation/differentiation of plant.
Technology developments that address these issues include•
LP Steam Turbine Aerodynamics development
•
LP Steam Turbine rotating blade Materials development.
Balance of Power Plant: Oxyfuel & Amine
The following are the major issues identified to have significant technical and/or
economic impact to a future CO2 capture power plant.
1. Integration of technologies into the power plant and between each sub-system
(ie turbine is the main driver for amine, flue gas conditioning for oxyfuel) This
may include determining the flexibility of boiler and turbine designs to
accommodate better integration and efficiencies, while still providing the
reliability and performance expected from a power plant
2. More technical consideration and costing for FGD plants in oxyfuel applications.
Air used for calcium sulphite oxidation in limestone based wet FGD systems
may escape into the CO2 flue gas stream. It would be beneficial to determine the
amount of flue gas contamination possible, its impact on flue gas utilization, and
the cost of flue gas clean up (if necessary). This exercise should include
evaluating the use of oxygen instead of air for calcium sulphite oxidation, against
the techno-economic impact on downstream flue gas clean up and the CO2
Compression plant.
3. Review of Auxiliary Power requirements (associated with integration). There is a
major power penalty whichever CO2 capture system is utilized and more design
review between the different partners is required to more accurately identify
penalties, while optimizing overall plant integration.
4. Real site layout considerations, used to facilitate more accurate capital costing.
5. Defining, if possible standardized purity requirements for captured CO2, which
would depend on the use or disposal point for the CO2 (ie EOR, or
sequestration) and the impact purity would have on capture costs. This can
significantly affect costs. It is not known if there is one standard for EOR, CBM,
which is applicable for all locations.
178
ASU & CO2 Compression Plant: Oxyfuel
1. Oxyfuel: There is a need for a demonstration of the oxyfuel CO2 capture
purification and compression stages of the oxyfuel technology, from the direct
contact cooler to the compressed, purified CO2 product. Although based on
known technology, demonstration at about 1 MWt scale is recommended to
allow the expected performance to be validated. Such a 1MWt pilot plant would
also allow quantification of unknowns, such as the fate of impurities in the raw
flue gas.
The BERR project, OxyCoal-UK Phase 1, will go some way to reducing any
uncertainty in performance, but at some point all the plant unit components need
to be assembled to demonstrate capture rate, purity, especially in the high purity
case where low temperature distillation is being used, materials issues, etc.
2. Oxyfuel: There is much to be gained from looking at optimisation of the CO2
compression system. In this BERR-366 study Air Products has used adiabatic
compression extensively with heat being recovered to the steam cycle. This
may not be the best overall solution, especially in cases where cooling water is
restricted. There may also be ways to utilise the fact that above its critical
pressure CO2 can be pumped. This could be combined with compression to
lower the overall power consumption.
3. Oxyfuel: Air Products have been working to improve the power consumption of
capture rate of the CO2 purification system and have cycles that increase
recovery of CO2 to above 97% without increasing power consumption. Also we
have been working on cycles that could efficiently either be producing the CO2
as a liquid product for tanker transportation, or could be combined with CO2
pumping to reduce overall power consumption, as mentioned in point 2. above.
4. Oxyfuel: Air Products is developing their Ion Transport Membrane (ITM)
technology. Allam et al [1] studied the oxyfuel conversion of boilers and heaters
on a refinery site using an ITM Oxygen system to produce the oxygen. This
showed that when integrated into the current steam system the ITM Oxygen
system resulted in a cost of CO2 capture around half that of the traditional
cryogenic ASU.
MHI ‘KM-CDR’ Process : Amine
1. Amine: Flexibility issues:
Effective integration of amine systems with power plants is becoming reasonably
well understood for baseload conditions, as studied within this BERR-366 project.
Considerations for post-combustion capture to lend itself to flexible operation in
order to:
•
allow varying electricity system requirements to met;
•
improve overall plant Reliability, Availability, Maintainability and Operability
(RAMO) issues, e.g. cycling in other components;
•
extract maximum benefit from variations in ambient conditions;
•
respond to variable price levels in the electricity and CO2 markets.
179
These require a number of areas that need to be addressed, in an interlinked way,
to assess the practicability and desirability of implementing such flexible
approaches are:
•
amine plant performance mapping over a wide range of operating conditions;
•
amine behaviour during storage;
•
design and performance analysis of the rest of the power plant system;
•
evaluation of monetary values for the benefits, to offset against costs.
2. Amine: Permitting, safety and environmental issues:
A range of practical issues arise when considering implementation of amine
capture. These apply to proprietary solvent systems, but answers must be available
in the public domain with support from independent assessors to satisfy regulators,
operators and other stakeholders. Such issues will include:
•
•
•
•
•
•
solvent life and fugitive emissions
health effects of solvents
handling procedures
environmental effects, short term and long term
residue formation rates and disposal methods
corrosion, material compatibility
3. Amine: Realistic solvent testing:
Large-scale, long-term solvent testing on real coal flue gases might be an area of
common interest, but difficulties arise due to the need accurately to assess coaland plant-specific effects on flue gas composition and hence solvent chemistry
changes in the long term. Taking this into account, it might, however, still be
possible to save significant duplication of test activities for preliminary realapplication screening of possible solvents. The information is of commercial
interest, but utilities may still wish to collaborate in this area. This activity could
obviously be combined with elements of the two above.
Summary of Recommendations for Future R&D and Future Collaboration
Within the context of the BERR-366 project and the future requirements of the
Canadian market, the key areas recommended from the BERR-366 collaborators
for Future R&D and Future Collaboration are therefore:
• Oxyfuel & Amine Scubbing: Further consideration of the specific site
requirements and constraints; including process optimisation and real plant
layout;
• Oxyfuel & Amine Scrubbing: LP Steam Turbine considerations for 60Hz
application;
• Oxyfuel & Amine Scrubbing: Capture ready considerations rather than capture
retrofit;
• Oxyfuel & Amine Scrubbing: Power Plant Safety, Operability and Flexibility;
180
• Oxyfuel: Demonstration of Oxyfuel burner/combustion at full scale;
• Oxyfuel: Demonstration of flue gas Purification / CO2 Compression;
• Amine Scrubbing: Long-term testing of solvents for PF power plant flue gas
applications.
Formatted: Bullets and
Numbering
181
182
8. CONCLUSIONS
In this BERR-366 project, the techno-economic assessment of the conceptual
designs of nominal 400MWe (net) coal-fired ASC power plants with options of both
Oxyfuel and post-combustion Amine Scrubbing CO2 capture technologies have
been established for three different Canadian coals/sites, namely:• C1: Sub-bituminous/Keephills : TransAlta Power
• C2: Bituminous/Point Tupper : Nova Scotia Power
• C3: Lignite/Shand : SaskPower
For the main coal/site C1: sub-bituminous, techno-economic assessment is
undertaken for each of the conceptual designs summarised as follows:
• R0 : an optimised air-fired Advanced SuperCritical (ASC) PF reference power
plant (RPP) with appropriate emissions control; without CO2 capture
• A1 : an optimised oxygen-fired ASC PF boiler with Oxyfuel CO2 capture
• A2 : a retrofit of the base case R0 to Oxyfuel CO2 capture (C1 only)
• B1 : an optimised air-fired ASC PF boiler with post-combustion CO2 capture
• B2 : a retrofit of the base case R0 to post-combustion CO2 capture (C1 only)
All the power plant options are designed with ASC boiler/turbine technology level
targets state-of-the-art steam turbine inlet conditions of 290bara/600°C/620°C for the
reference air-fired power plant and those power plants with CO2 capture or CO2
capture retrofit.
This D7 report presents the conceptual design and performance of the following
major power plant components of the air/PF-fired power plant with Amine Scrubbing
CO2 capture options:•
•
•
•
•
•
•
•
•
•
•
•
•
8.1
Unit 100 :
Unit 200 :
Unit 300 :
Unit 400 :
Unit 500 :
Unit 600 :
Unit 700 :
Unit 800 :
Unit 900 :
Unit 1100 :
Unit 1200 :
Unit 1300 :
Unit 2000 :
Coal & Ash Handling (CCPC/NG)
Boiler Island (Doosan Babcock)
DeNOx Plant (CCPC/NG/DOOSAN BABCOCK)
DeHg Plant (MHI)
Particulate Removal Plant (CCPC/NG)
FGD & Handling Plant (MHI)
Steam Turbine Island including STI BoP (Alstom Power)
CO2 Amine Scrubbing Plant (MHI)
CO2 Compression Plant (MHI)
Cryogenic Oxygen ASU (Air Products)
CO2 Purification and Inerts Removal Plant (Air Products)
CO2 Compression Plant for Oxyfuel (Air Products)
BoP, Civils, Electrical, I&C; excluding STI BoP Items (CCPC)
TECHNICAL ANALYSIS RESULTS
ASC Reference Power Plant without CO2 Capture
For each of the ASC reference power plants R0, with nominal net electricity output
of 500 MWe, the plant net cycle efficiency (HHV basis) achieved is as follows:
183
• C1-R0: 42.9% net (HHV basis): Sub-bituminous PF for Keephills: TransAlta
Power
• C2-R0: 44.5% net (HHV basis): Bituminous PF for Point Tupper: Nova Scotia
Power
• C3-R0: 39.7% net (HHV basis): Lignite PF for Shand: SaskPower
%
Reference Power Plant Efficiency
50
45
40
35
30
25
20
15
10
5
0
C1-R0
C2-R0
C3-R0
Study Cases - Reference Power Plant
PP Efficiency (HHV basis)
PP Efficiency (LHV)
Figure 8.1-1 Thermal Efficiencies of ASC Power Plant without CO2 Capture
ASC Power Plant with Amine Scrubbing CO2 Capture
Compared to an ASC air/PF-fired reference power plant without CO2 capture, for the
same fuel heat input, as expected a power plant with CO2 capture results in a
reduction power plant performance in terms of both plant efficiency and net output.
Figure 8.1-2 shows the power plant electricity gross outputs with major auxiliary
power consumptions.
MWe
Amine Scrubbing CO2 Capture PP Gross Output (MWe)
650
600
550
500
450
400
350
300
250
200
150
100
50
0
C1-B1
C1-B2
C2-B1
C3-B1
Amine Scrubbing CO2 Capture Cases
Conventional Aux. Power
CO2 Compression Power
Amine Scrubber Power
Net Output Power
Figure 8.1-2 Amine Scrubbing CO2 Capture Power Plant Gross Output and Parasitic
Power
184
With a nominal target of 90% CO2 capture, the relative reduction in cycle efficiency
for a post-combustion Amine Scrubbing CO2 capture power plant varies slightly
depending on the coal/site conditions. For the main project design fuel C1:subbituminous coal, the reduction in cycle efficiency is estimated at approximately 9.6%
percentage points (HHV basis) compared to the reference power plant C1-R0
without CO2 capture.
Comparatively, approximately 9.0% (HHV) percentage points, and 9.3% (HHV)
percentage points cycle efficiency reductions resulting from Amine Scrubbing CO2
Capture option are estimated for the C2 and C3 coal/site.
Amine Scrubbing CO2 Capture PP Efficiency Penalties
(HHV basis)
0
%Points Reduction
C1-B1
C1-B2
C2-B1
C3-B1
-5
-10
-15
Efficiency Penalties (HHV basis)
Figure 8.1-3 Amine Scrubbing CO2 Capture Thermal Efficiency Penalty (HHV basis)
Amine Scrubbing CO2 Capture PP Efficiency Penalties
(LHV basis)
0
%Points Reduction
C1-B1
C1-B2
C2-B1
C3-B1
-5
-10
-15
Efficiency Penalties (LHV basis)
Figure 8.1-4 Amine Scrubbing CO2 Capture Thermal Efficiency Penalty (LHV basis)
185
The overall cycle efficiencies for the Amine cases considered are as follows:
• C1-B1: 33.4 % net (HHV basis): Sub-bituminous: Amine CO2 Capture
• C1-B2: 33.6 % net (HHV basis): Sub-bituminous: Amine CO2 Capture Retrofit
• C2-B1: 35.7 % net (HHV basis): Bituminous: Amine CO2 Capture
• C3-B1: 30.3 % net (HHV basis): Lignite: Amine CO2 Capture
Amine Scrubbing CO2 Capture Power Plant Thermal Efficiencies
40
35
30
%
25
20
15
10
5
0
C1-B1
C1-B2
C2-B1
Net Thermal Efficiency (HHV basis)
C3-B1
Net Thermal Efficienciy (LHV basis)
Figure 8.1-5 Amine Scrubbing CO2 Capture Power Plant Thermal Efficiency
Note that Case C1-B2 defined as the retrofit of C1-R0, is assumed to retain the
same condenser with same cooling water mass flow rate of C1-R0, which is
approximately 50% larger than that of C1-B1, hence C1-B2 retrofit option results in a
lower condenser pressure 3.0 kPa instead of 4.0 kPa of C1-R0 and C1-B1, and
gives slightly higher gross output than that of C1-B1. This assumption requires an
additional auxiliary cooling water system to meet the requirements of the capture
plant.
Compared to what had been presented in previous D4.2 report [3], the performance
and efficiencies of the Amine CO2 Capture cases presented in this D7 final report
have been improved for approximately 1% point resulted from further process and
cycle optimisation by MHI and Alstom Power.
ASC Oxyfuel CO2 Capture Power Plant :
Within this BERR-366 project, the ASC PF Oxyfuel CO2 capture power plant designs
have been based on proven air-fired technology wherever feasible and appropriate
by maximising the application of current state-of-the-art proven technologies. The
Oxyfuel CO2 capture power plant configurations have been established with the
following aspects considered:
186
•
•
•
Target overall flue gas recycle (FGR) rate for acceptable combustion
performance in furnace.
Oxyfuel combustion system based on air fired experience;
Power plant components based on proven technologies where applicable and
appropriate;
An Oxyfuel boiler, comparing to an air/PF-fired boiler, the exclusion of N2 replaced
by CO2 enriched flue gas recycled (ranging from 65%~70% of the main flue gas at
boiler outlet), results in the increased concentration levels of sulphur and chloride
components of flue gas, hence increased acid corrosion risk to the boiler island
components which are exposed to the flue gases. Such requirements and
constraints of the Oxyfuel boiler island determine the configurations of Oxyfuel
power plant.
While the configurations of the Oxyfuel CO2 capture power plant may vary
depending on the coal/site conditions, the Oxyfuel boiler island configurations may
vary depending on the key components of the coal fired, primarily the sulphur
content which relates to furnace corrosion design constraints. With respect to the
three different design coals for this project, three slightly different Oxyfuel power
plant configurations have been adapted for each coal/site, with configurations
differences mainly in the employment of either a FGD plant or a flue gas Direct
Contact Cooler (DCC) for the FGR streams.
Figure 8.1-6 gives the gross output of the Oxyfuel CO2 capture power plants and
main auxiliary power consumptions.
MWe
Oxyfuel CO2 Capture Power Plant Gross Output (MWe)
650
600
550
500
450
400
350
300
250
200
150
100
50
0
C1-A1
Conventional Aux. Power
C1-A2
ASU Power
C2-A1
CO2 Compression and Purification Plant Power
C3-A1
Power Plant Net Output Power
Figure 8.1-6 Oxyfuel CO2 Capture Power Plant Gross Output and Parasitic Power
With a nominal target of 90% CO2 capture, compared to the reference power plant
C1-R0 with no CO2 capture, for the main project design fuel C1:sub-bituminous coal,
the reduction in cycle efficiency of the Oxyfuel CO2 capture power plant option C1A1 is estimated to be approximately 8.8%points (HHV basis). The retrofit option of
C1-A2 indicates approximately 0.7%point more reduction than that of C1-A1, ie
187
9.5% points (HHV basis) cycle efficiency reduction to the reference power plant C1R0 with no CO2 capture.
The relative reductions in cycle efficiency of the Oxyfuel CO2 capture power plant
options for the three coals/sites are of approximately 8~9%points on HHV basis
despite the different coal/site conditions. The overall cycle efficiencies for the
Oxyfuel cases considered are as follows:
•
•
•
•
C1-A1: 34.1 % net (HHV basis): Sub-bituminous: Oxyfuel CO2 Capture
C1-A2: 33.4 % net (HHV basis): Sub-bituminous: Oxyfuel CO2 Capture Retrofit
C2-A1: 36.0 % net (HHV basis): Sub-bituminous: Oxyfuel CO2 Capture
C3-A1: 31.6 % net (HHV basis): Sub-bituminous: Oxyfuel CO2 Capture
Oxyfuel CO2 Capture Power Plant Thermal Efficiency
50
45
PP Efficiency (HHV basis)
PP Efficiency (LHV)
40
35
%
30
25
20
15
10
5
0
C1-A1
C1-A2
C2-A1
C3-A1
Figure 8.1-7a Oxyfuel CO2 Capture Power Plant Thermal Efficiency
%points
Power Plant Thermal Efficiency Penalty
- Oxyfuel CO2 Capture
0
-1
-2
-3
-4
-5
-6
-7
-8
-9
-10
-11
-12
-13
-14
-15
C1-A1
C1-A2
C2-A1
PP Efficiency Penalty (HHV basis)
C3-A1
PP Efficiency Penalty (LHV)
Figure 8.1-7b Oxyfuel CO2 Capture Power Plant Thermal Efficiency Reduction
188
Power Plant Emissions:
All power plants achieve the emission targets specified by CCPC for this project
achieved CO2 reduction down to approximately 0.1kg CO2/kWh, with nominal 90%
CO2 capture rate. Figures 8.1-8, 8.1-9 and 8.1-10 present the CO2 emission
reductions for each study cases in this project.
CO2 Emissions
(based on same fuel firing rate: ~ 226 t/h)
0.9
0.8
kg CO2 / kMWh
0.7
CO2 Emissions
0.6
0.5
0.4
0.3
0.2
0.1
0.0
C1-R0
C1-A1
C1-A2
C1-B1
C1-B2
Power Plant CO2 Emissions
(C1:Sub-bituminous, Keephills/TransAlta Power)
Figure 8.1-8a Power Plant CO2 Emissions (C1:Sub-bituminous)
CO2 Emissions
(based on sam e fuel firing rate: ~ 130 t/h)
0.8
kg CO2 / kMWh
0.7
0.6
CO2 Emissions
0.5
0.4
0.3
0.2
0.1
0.0
C2-R0
C2-A1
C2-B1
Power Plant CO2 Emissions
(C2:Bituminous, Point Tupper/ Nova Scotia Power)
Figure 8.1-8b Power Plant CO2 Emissions (C2:Bituminous)
189
CO2 Emissions
(based on sam e fuel firing rate: ~ 300 t/h)
1.0
0.9
kg CO2 / kMWh
0.8
CO2 Emissions
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0.0
C3-R0
C3-A1
C3-B1
Power Plant CO2 Emissions
(C3: Lignite, Shand / SaskPower)
Figure 8.1-8c Power Plant CO2 Emissions (C3:Lignite)
Despite of the different coal/site conditions, all the PF-fired power plants with or
without CO2 Capture option have the common block features as listed in Table 8.1-1
below.
Steam Generator
Turbine & Generator
Feedwater Heating
Feed Pumps
Steam Temperature Control
Steam Cycle Operation
Plant Operation Basis
Two-pass once-through BENSON steam generator with PosiflowTM
vertical tube furnace and appropriate emission reduction systems
Four module reheat steam turbine:Single flow HP reaction turbine
Double flow IP reaction turbine
Two double flow LP reaction turbine
H2 -cooled generator rotor and water-cooled stator windings
85% HP by-pass/50 % LP by-pass
10-stage feedwater heating with top heater above reheat point
(HARP), and desuperheater ahead of top heater
5 x LP heaters
1 x Feedwater tank and deaerator
3 x HP heaters + 1 x Desuperheater
2 x 70% motor-driven feedwater pump
2 x 70% motor-driven condensate pump
Superheater steam temperature control to 50%MCR, Reheat steam
temperature control to 70%MCR
Sliding pressure in the range 40% ~ 100%MCR
Base load; Nominal frequency 60 Hz; Design life 30 years
Table 8.1-1: Power Block Feature of ASC PF Power Plant
Table 8.2 below summarises the performance of Power Plants with or without CO2
Capture Options.
190
ASC Power Plant with Oxyfuel or Amine Scrubbing CO2 Capture Options
C1: Sub-bituminous
Keephills/TransAlta Power
Case Ref. No.
CO2 Capture Rate
Fuel Fired
Power Plant Gross Output
Power Plant Net Output
Plant Net Efficiency
%
kg/s
MWe
MWe
%(HHV)
%(LHV)
Efficiency Penalty on CO2 Capture (percentage points)
%(HHV)
%(LHV)
HP System
o
HP Turbine Inlet Temp.
C
o
Feedwater Temperature
C
HP Turbine Inlet Press.
bara
IP System
o
IP Turbine Inlet Temp.
C
IP Turbine Inlet Press.
bara
Condenser Pressure
kPa
Emissions
NOx g/MWh
SOx g/MWh
Particulates g/MWh
Hg mg/MWh
CO2 kg/kWh
Heat Rejection/Flue Gas Discharge
C1-R0
0
62.74
542
503.4
42.91
45.57
C1-A1
90.0
62.74
570.5
400.2
34.11
36.22
C1-A2
90.0
62.74
568.7
392.3
33.43
35.50
C1-B1
90.0
62.74
480.5
391.3
33.35
35.41
C1-B2
90.0
62.74
484.1
394.1
33.59
35.67
C2:Bituminous
Point Tupper/ Nova Scotia
Power
C2-R0
C2-A1
C2-B1
0
90.0
90.0
35.91
35.91
35.91
546.4
568.1
490.7
510.5
413.2
409.9
44.48
36.01
35.72
46.46
37.61
37.73
0.0
0.0
-8.8
-9.3
-9.5
-10.1
-9.6
-10.2
-9.3
-9.9
0.0
0.0
-8.5
-8.8
600
300
290
600
300
290
600
300
290
600
300
290
600
300
290
600
300
290
620
61.0
620
58.8
620
61.4
620
61.1
620
60.2
620
61.0
4.0
4.0
5.0
44.9
8.0
10.9
49.7
0.31
0
12.6
0
0
3.5
0
0
0.79
0.08
0.09
Natural Draught Cooling Tower
4.0
47.1
5.5
2.64
3.3
0.10
3.0
47.1
5.4
2.64
3.3
0.10
C3:Lignite
Shand / SaskPower
C3-R0
0
84.14
542.0
499.5
39.68
43.71
C3-A1
90.0
84.14
580.0
397.5
31.57
34.78
C3-B1
90.0
84.14
479.2
382.0
30.34
33.43
-8.8
-9.2
0.0
0.0
-8.1
-8.9
-9.3
-10.3
600
300
290
600
300
290
600
300
290
600
300
290
600
300
290
620
59.5
2.6
620
61.1
620
61.0
620
64
4.0
620
61.2
35.4
2.3
44.6
32.0
0
18.3
10.9
0
13.8
2.4
0
3.0
0.69
0.08
0.09
Sea Water Cooling / Stack
36.6
4.1
49.6
21.5
0
18.5
10.7
0
14.5
4.5
0
5.5
0.88
0.10
0.12
Natural Draught Cooling Tower
Table 8.1-2 Performance Summary of Power Plants with or without CO2 Capture Options
191
8.2
Economic Analysis Results
The results of the economic and performance analysis are summarised in Table
8.2-1. Among the options for the main design coal C1; Sub-bituminous coal, the
levelised costs are found to be reasonably close for all study options, with the
Amine Scrubber based plants (B1 & B2) only slightly more expensive than the
oxyfuel plants (A1).
C1: Sub-bituminous
(Keephills, TransAlta Power)
OPTION
C1-R0
C1-A1
C1-A2
(Retrofit)
C1-B1
C1-B2
(Retrofit)
Capital Cost (CA$ x 106)
$1,757.9
$2,448.4
$2,837.6
$2,320.2
$2,331.1
Levelized Fuel and O&M Costs
(CA$ x 103) Per Year
$48,263.4
$48,926.5
$51,020.4
$57,148.1
$59,519.7
Levelized Cost of Electricity
(¢ per kWh)
6.48
9.86
11.15
9.83
9.92
Levelized CO2 Capture Cost
(CA$ per tonne)
--
$47.76
$66.76
$48.82
$50.04
Table 8.2-1
Summary of Costs and CO2 Emissions
The cost of a retrofitted oxyfuel CO2 capture plant (C1-A2) is substantially higher
than other options, approximately 33% higher in the levelized CO2 capture cost and
approximately 12% higher in levelised COE respectively than the Amine Scrubbing
retrofit option (C1-B2). This is primarily due to:
•
•
The additional capital costs discussed in the previous section.
The higher O&M costs for a retrofitted plant due to the less efficient cooling
system and the need to operate an existing FGD plant not present in the A1
case.
The costs do not take into account the lost generation a retrofitted option would
cause while the unit is off line during construction.
The levelized cost of CO2 capture includes the main cost categories of capital,
taxes, O&M, parasitic energy, and credits, but it is assumed that no CO2 credits are
received. The energy losses required to operate equipment directly related to CO2
capture are one of the largest cost items, closely followed in most cases by capital
charges. The O&M costs in contrast are found to make up a relatively minor
portion of the total charges.
Compared to the reference power plant, the Oxyfuel CO2 capture power plant C1A1 is approximately 40% higher in CAPEX which is 15% less than that of the
retrofit option C1-A2.
The Amine Scrubbing CO2 capture power plant C1-B1 is approximately 10% lower
in CAPEX, but 20% higher in OPEX than Oxyfuel option C1-A1.
192
These results in general are within expectation given the high costs to build the CO2
capture plants and the significant energy demands needed to operate both the
Oxyfuel and Amine scrubbing plants.
Table 8.2-2 breaks down the levelized cost of CO2 capture by the main cost
categories of capital, taxes, O&M, parasitic energy, and credits. It is assumed that
no CO2 credits are received.
Table 8.2-2
C1-A1
21.934
6.822
0.365
18.755
-0.115
-47.76
Capital
Tax
O&M
Parasitic Energy
Limestone
CO2 Credit
Total Cost
Levelized Cost of CO2 Capture (CA$ Per Tonne)
C1-A2
C1-B1
34.564
18.435
10.750
5.734
1.042
3.450
20.403
21.196
----66.76
48.82
C1-B2
18.792
5.845
4.372
21.027
--50.04
The table shows energy losses required to operate equipment directly related to
CO2 capture are one of the largest cost items, closely followed in most cases by
capital charges. C1-A1’s lack of an FGD plant helps to limit its O&M costs
compared to the other options. This savings over the R0 case is included in A1’s
overall evaluation, also somewhat reducing its capital and operating charges.
Parasitic energy was developed by the consortium partners and priced based on
C1-R0’s estimated levelized cost of production. These costs are found to be
reasonably close for all study options, with the amine scrubber based plants (B1 &
B2) only slightly more expensive than the oxyfuel plants (A1 & A2). O&M costs in
contrast are found to make up a relatively minor portion of the total charges. The
B1 and B2 plants captured slightly less CO2 than the A1 and A2 plants, and this
tended to increase their $ per tonne CO2 capture costs. These results in general
were expected given the high costs to build the CO2 capture plants and the
significant energy demands needed to operate both the Oxyfuel and Amine
scrubbing plants.
40 Year Levelized Cost (¢ per kWh Generation)
5.000
4.694
4.000
3.000
3.384
3.435
3.351
2.000
1.000
0.000
A1
A2
1
B1
B2
C1 (Keep Hills) Plant Options
Figure 8.2-1 Cost of CO2 Capture (¢ per kWh)
193
40 Year Levelized Cost ($ per Tonne CO2 Captured)
70.00
$66.759
60.00
50.00
$50.036
$48.818
$47.760
40.00
30.00
20.00
10.00
0.00
A1
1
A2
B1
B2
C1 (Keep Hills) Plant Options
Figure 8.2-2 Cost of CO2 Capture (CA$ per tonne CO2)
12
11
11.025
40 Year Levelized Cost of Electricity (Cents per kWh)
10
9.860
9.827
9.910
B1
B2
9
8
7
6
6.475
5
4
3
2
1
0
R0
A1
A2
C1 (Keephills) Plant Options
Figure 8.2-3 Cost of Electricity (Cents per kWh)
8.3
CONCLUSIONS
The conclusions drawn for this BERR 366 project based on the technical and
economic analysis results are as follows:Technical:
1. Compared to a reference power plant without CO2 capture, for a nominal
400MWe (net) ASC power plant with 90% CO2 capture rate, the thermal
efficiency loss due to CO2 capture is approximately 8.0 ~ 9.5% points (HHV
basis) or 9 ~ 10% points (LHV basis).
194
2. The relative thermal efficiency penalty due to CO2 Capture using Oxyfuel and
Amine CO2 capture technologies are comparable with variation of
approximately 1% point.
3. For the project main design coal C1:Sub-bituminous, the optimized Oxyfuel
CO2 capture power plant C1-A1 thermal efficiency is approximately 1% point
higher than that of the Amine CO2 capture power plant C1-B1 option.
4. Compared to the optimised Oxyfuel CO2 capture power plant C1-A1, C1-A2
as a retrofit from non-capture ready C1-R0 reference, retains the SCR and
FGD plants and full air-firing capability, with thermal efficiency comparable to
that of Amine Scrubbing case C1-B1.
5. For C2:Bituminous cases, the power plant thermal efficiency for Oxyfuel and
Amine Scrubbing CO2 capture option are comparable, with similar efficiency
penalty of approximately 8.5~8.8% points (HHV).
6. For C3:Lignite cases, the power plant thermal efficiency penalty for Oxyfuel is
approximately 8% points, which is approximately 1% point less than that of
Amine Scrubbing option.
Economics:
7. The levelised CO2 capture cost and electricity cost are very much comparable
between the Oxyfuel CO2 capture option C1-A1 and the Amine Scrubbing
CO2 capture option C1-B1.
8. The Oxyfuel CO2 capture option C1-A1 has marginably higher thermal
efficiency and lower in levelised cost than the Amine Scrubbing option.
9. For the main design coal C1: sub-bituminous, the Oxyfuel CO2 capture option
is estimated 10% higher in CAPEX but 20% lower in OPEX than an Amine
Scrubbing CO2 capture option, and approximately 30 ~ 40% higher in CAPEX
than the reference power plant.
10. As a retrofit option, C1-A2 has substantially 33% higher levelised CO2
capture cost than the Amine Scrubbing C1-B2 option which is marginably
higher than that of C1-B1 new-build option.
General:
‰
This Project BERR-366 has established Advanced supercritical power plant
steam conditions and net plant output suitable for CO2 Capture Power Plant
application in Canada.
‰
Established overall CO2 Capture Power Plant designs and process integration
built on knowledge and experience of proven conventional air/PF firing power
plants.
‰
Developed conceptual designs and layout for new-build CO2 Capture and CO2
Capture-ready PF-fired advanced supercritical power plant based on both Amine
Scrubbing and Oxyfuel CO2 Capture technology, targeting near-term Market, on
proven technology for minimum risk.
‰
Established the sensitivity to technical performance of the CO2 capture
technology considered for three different Canadian coal/sites.
195
‰
CO2 Capture and CO2 Capture-ready Power Plant emissions and waste streams
are within the agreed Project BERR-366 design targets.
‰
Confirmed technically feasible to “retrofit” carbon capture technology to a coalfired power plant using either Oxyfuel technology or Amine Scrubbing
technology
‰
Achieved Capture plant performance with CO2 emissions capture level upto
90%.
‰
Optimised plant performance through process integration with consideration of
practical plant flexibility and reliability, availability and maintainability.
‰
Identified and addressed key specific issues relating to:−
Essential requirements and considerations for Capture-ready Plant
−
CO2 capture plant energy penalty and steam cycle matching
−
CO2 capture rate
−
Waste streams / emissions performance
−
Capture Plant utilities and cooling water requirements
−
Capture Plant footprint / layout requirements
−
Safety and operability
196
9.
Acknowledgment
The consortium, led by co-ordinator, Doosan Babcock, and its partners (CCPC,
Alstom Power, Air Products, Imperial College, Neill & Gunter and Mitsubishi Heavy
Industries) acknowledge the funding provided by UK Department of Trade Industry
(Contract No. C/07/00366/00/00) in support of this Project. Doosan Babcock
acknowledges the contribution of the consortium partners to this report.
197
198
10. REFERENCES
[1]
“Canadian Market Study Draft Summary Report”, CCPC, Dec 2005, BERR Ref. D1
deliverable, C/07/00366/00/00.
[2]
“D2: Project Specifications and Design Basis Ground Rules”, Doosan Babcock
Report No: E/05/090, BERR Ref. C/07/00366/00/00.
[2]
“D4.1: ASC PF Reference Power Plant C1-R0 Conceptual Design and Performance
(Sub-bituminous)”, Doosan Babcock Report No: E/06/025, BERR Ref.
C/07/00366/00/00.
[3]
“D4.2: ASC PF Power Plant with Amine CO2 Capture”, Doosan Babacock Report No:
E/06/031, BERR Ref. C/07/00366/00/00.
[4]
“D4.3: ASC PF Power Plant with Oxyfuel CO2 Capture”, Doosan Babcock Report No:
E/06/127, BERR Ref. C/07/00366/00/00.
[5]
“Amine Scrubbing/Oxyfuel Balance of Plant Study :Draft Report ”, CCPC 22 Draft
Report Issue - 43042\10, Neil & Gunter, E-mail attachment “2006-12-14-r-am Amine
Scrubbing-Oxyfuel BOP Study - Draft.doc”, A Mackenzi (Neill & Gunter) to B Xu
(Doosan Babcock), 14 December 2006.
[6]
“D4.2 Report_Amine Options_Draft_Iss1G.doc, D4.3 Report_OxyFuel Options_Draft
Iss 1G.doc”, Alstom report, E-mail attachment, Tony Wall (Alstom Power) to B Xu
(Doosan Babcock), 12 December 2006.
[7]
“D4.3 Report_Oxyfuel Options_Draft Iss 1c_AP checked.doc”, Air Products report,
E-mail attachment, Islam Hussain (Air Products) to B Xu (Doosan Babcock), 7
December 2006.
[8]
“Refurbishment of Yaomeng Power Plant”, DTI/Pub URN 03/1065.
[9]
“SCN_20061214194740_001_1-3.pdf”, MHI’s comments on D4.2 preliminary report
draft E-mail attachment, Ohishi Tsuyoshi (MHI) to B Xu (Doosan Babcock), 14
December 2006.
199
200
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