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CONFERENCE PROCEEDINGS

Seventh Annual Conference onCarbon Capture & Sequestration

May 5-8, 2008 Sheraton Station SquarePittsburgh, Pennsylvania, USA

Recent Init iatives and the Current Status of MHIs PostCombustion CO2Recovery Process; Aiming to Realize

the Rapid Commercial Application of CCS

Ronald Mitchell & Masaki Iijima

Tokyo Japan

SEVENTH ANNUAL CONFERENCE ON CARBON CAPTURE AND SEQUESTRATION - DOE/NETLMay 5 8, 2008

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ABSTRACT

Mitsubishi Heavy Industries Ltd., (MHI), which provides commercial CO2recovery plants for

natural gas fired installations, is now focusing on providing commercial CO2capture solutions

for coal fired power generation. The next critical step to achieve this important aim is to

demonstrate the post combustion CO2recovery process, together with the advanced, corrosion

resistant solvent (KS-1) on medium to large scale (>500 metric ton per day). MHI has

furthered the development of the CO2recovery process through several important initiatives.

Process enhancements have reduced the utility consumption requirements and; additional heat

and process integration improvements between the power plant and the CO2 recovery plant

will help to further minimize operating costs and the energy penalty of CO 2 capture. In

addition, MHI has just carried out large scale liquid distribution tests at a commercial size

multi-pollutant test facility in Japan, which is the largest of its type in the world. Highly

efficient gas and liquid distribution within the rectangular absorber tower is essential for

application on commercial capacity flue gas streams. Lastly, MHI has also completed further,

successful demonstration testing of CO2capture for coal at a capacity of 10 metric ton per day,

from a slip stream at a commercial power station in Matsushima, Japan. These wide-ranging

initiatives are designed to move this technology to a position where it can firstly be

demonstrated at significant scale, for coal application, to reduce associated risks and thus

facilitate commercial deployment which, it is hoped, will lead to the provision of practical

carbon abatement solutions for industry.

Keywords;

CO2capture; flue gases; heat and process integration; energy penalty; demonstration testing;coal application; carbon abatement solutions.

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INTRODUCTION

It is now widely accepted that capturing CO2from flue gases and the subsequent injection into

geological formations can significantly contribute to reducing emissions of CO2, the principal

greenhouse gas. Apart from having obvious benefits in terms of reducing the emissions of CO2

into the atmosphere, CCS will also allow nations around the world to continue using important

domestic fossil fuels such as coal in an economic and environmentally friendly way. However

for CCS to be deployed in any meaningful way, it is necessary for Governments to urgently

provide a legal and regulatory framework which allows industry to make strategic investment

decisions relating to the future procurement and supply of energy. Furthermore the EIA

predicted that coal, liquid fuels (excluding biofuels), and natural gas will meet 80 percent of

total U.S. primary energy supply requirements in 2030 (EIA, 2008). The report also suggested

that total coal consumption would increase from 1,114 million short tons in 2006 to 1,545

million short tons in 2030. Coal consumption is also projected to grow at a faster rate toward the

end of the projection period, particularly after 2020, as coal use for new coal-fired generating

capacity grows rapidly. CCS can therefore play a very important role in the future of the US and

other nations. However the early stage deployment of CCS depends on the provision of

appropriate incentives, by governments, and the advancement of large scale demonstration

projects to overcome both technical and financial barriers which currently exist.

MHIs COMMERCIAL CO2CAPTURE ACHIEVEMENTS

Mitsubishi Heavy Industries (MHI) has been involved in research and development relating to

CO2capture from flue-gas streams of fossil fuel-fired power stations since 1990. This has led to

the development of advanced, proprietary equipment and processes and the successful

commercial deployment of four (4) CO2capture plants, currently operating in Malaysia, Japan

and India (2 units at separate locations). MHI has also been awarded a further three (3)

commercial license contracts for CO2 capture plants which are expected to complete

construction and be on stream within the next few years. An additional CO2 recovery plant

license contract is currently under negotiation and FEED has also been completed for an 800

mt/d plant with the final investment decision pending. MHIs commercial CO2 capture plant

experience is highlighted in Figure 1 below.

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Malaysia

Client: Petoronas

Start-up: 1999~Capacity: 200 t/d

Source: Nat. Gas Reformer

Product: Urea

Japan

Client: A Chemical Co.

Start-up: 2005~Capacity: 330 t/d

Source: Nat. Gas Boiler

Product: General use

India

Client: IFFCO

Start-up: Dec 2006~Capacity: 450 t/d x 2 units

Source: Nat. Gas Reformer

Product: Urea

340

2010

Nat. Gas.

Reformer

Contract

Negotiation

Asia

800

TBC

Nat. Gas.

Boiler

FEED

Complete

China

450450400CO2 Capture

Capacity (T/D)

Nat. Gas.

Reformer

Nat. Gas.

Reformer

Nat. Gas.

Reformer

Flue Gas

Source

201020092009Expected onstream

Under

Construction

Under

Construction

Under

ConstructionProject Status

BahrainIndiaAbu

DhabiOTHER

PROJECTS

340

2010

Nat. Gas.

Reformer

Contract

Negotiation

Asia

800

TBC

Nat. Gas.

Boiler

FEED

Complete

China

450450400CO2 Capture

Capacity (T/D)

Nat. Gas.

Reformer

Nat. Gas.

Reformer

Nat. Gas.

Reformer

Flue Gas

Source

201020092009Expected onstream

Under

Construction

Under

Construction

Under

ConstructionProject Status

BahrainIndiaAbu

DhabiOTHER

PROJECTS

CO2 Recovery CDR) Plant IFFCO Aonla Unit (India)

Figure 1. MHIs commercial CO2capture plant experience.

CO2CAPTURE FROM A COAL FIRED BOILER

MHIs flue gas CO2recovery plant utilizes an advanced amine solvent, termed KS-1, as the

CO2absorbent. As coal fired flue gas streams contain more impurities than natural gas, flue

gas pre-treatment is required to reduce the respective composition of a number of these

impurities, namely SO2, NOx and dust, as identified in Figure 2. Following pre-treatment, the

flue gas enters the water cooler/deep FGD where the flue gas is cooled to around 104 F

(40 C) and additional impurities are further reduced. The flue gas then enters the absorber

tower where it contacts with the KS-1 absorbent, distributed over stainless steel structured

packing material, and the CO2is removed from the flue gas, via an exothermic reaction, which

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generates heat. The flue gas subsequently proceeds into the top section of the absorber tower

where it is further washed to maintain water balance within the system and to remove

vaporized KS-1 solvent. The rich KS-1 solvent then moves into the stripper column

(regenerator) via a pump and here the CO2is separated from the solvent via 248 F (120 C)

low pressure steam, introduced via a reboiler at the bottom of the stripper. The high purity CO2

then proceeds into a condenser before being directed to a compression and dehydration facility

where it is prepared for pipeline delivery. The lean KS-1 solvent is then heated up via the

plate heat exchanger before been re-introduced into the absorber and the process continues

within a closed cycle.

C.W.

C.W.

Steam

Reboiler

C.W.

ABSORBER

Flue GasCooler/Deep FGD

Flue Gas

Outlet

Flue Gas

STRIPPER

(Regenerator)

CO2 Purity 99.9 %

Treated Flue Gas

Boiler

StackDeNOx

ParticulateCaptureFacility

CO2Product

Flue

GasCompression

&Dehydration

FGD

CO2Capture

Treated Flue Gas

Boiler

StackDeNOx

ParticulateCaptureFacility

CO2Product

Flue

GasCompression

&Dehydration

FGD

CO2Capture

Pre-treated Flue gas

Figure 2. MHIs CO2recovery process flow showing pre-treatment requirements for coal fired

flue gas.

MHI acknowledged, several years ago that coal will continue to play an important part of the

energy production matrix, well into the future. Accordingly it set about demonstrating the

proprietary CO2 capture process (termed KM-CDR) for coal fired flue gas application. After

initially testing the process at the Hiroshima R&D center at a scale of 1 metric ton per day

(mt/d) the experience and know how gained from other R&D and commercial experiences was

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applied to the construction of a 10 mt/d pilot plant (Fig. 3), at a commercial coal fired power

station in southern Japan, which processes a slip stream of the flue gas.

Figure 3. Photograph of the 10 mt/d CO2capture plant fitted to a commercial coal fired power

station in southern Japan.

The coal fired CO2capture pilot plant was very important in confirming the results of specific

test items. The results of these test items and the operational performance, shown in Table 1,

have led to advanced know how of CO2 capture from coal fired flue gas streams and

confirmation that the KM-CDR Process can be applied to coal.

Table 1. Test items and operational performance of MHIs 10 mt/d coal fired CO2capture pilot

plant

Test Item Result

Achieve long term stable operation >5000 hours of near continuous operation

(shutdown during power plant outage)

Confirm effect of various impurities on CO2 Advanced know-how of the impacts of dust, SO2 and

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capture process & equipment NOx (confidential know how)

Achieve high CO2purity performance >99.9% achieved

Confirm heat consumption required for CO2

recovery (MHI conventional process)

730-820 kcal/kg-CO2

(Improved process reduced by a further 15%)

Record pressure loss observed in the cooler and

absorber

No major pressure fluctuations

Confirm process can be applied to coal fired

flue gas

Yes, with the installation of flue gas pre-treatment

facilities (FGD etc) the KM-CDR Process can be

applied to coal fired flue gas

NEXT STEP LARGE SCALE CO2CAPTURE DEMONSTRATION FOR COAL

The next step is to apply this proven and trusted technology process to a large-scale CO 2-

capture demonstration plant utilizing a coal-fired boiler. This will lead to greater understanding

of the larger-scale effects of coal fired flue gas impurities and the options for heat and process

integration between the CO2capture plant and power plant.

In recognition that MHI has completed extensive R&D programs and to address flexibility

issues, which will offer further robust incentives for post combustion CO2 capture using

absorption technologies, we believe it is critically important to progress into the medium scale

(~500 tpd) demonstration phase for coal fired flue gas streams. This will lead to a greater

understanding of the larger-scale effects of coal fired flue gas impurities and the options for

heat and process integration between the CO2 capture plant and power plant, ultimately

providing insights into respective efficiencies, cost reduction and a foundation for future wide-

scale commercial implementation with a range of guarantees.

MHIs PROCESS IMPROVEMENTS TO REDUCE ENERGY & STEAM

REQUIREMENTS

The development of the advanced KS-1 amine solvent has a number of significant advantages

over standard MEA based solvents (30%wt basis). These include; higher rates of CO 2

absorption, lower solvent degradation, low corrosion and no requirement for a corrosion

inhibitor. Furthermore MHI has developed an Improved Process which results in a reduction

in steam requirement of 15% over the conventional MHI CO2 recovery process. The process

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incorporates additional plate heat exchangers which utilize lean solvent and steam condensate

heat for regeneration inside the stripper (Fig. 4). This process was first developed at the Nanko

1 mt/d pilot plant and has since been applied to a commercial project in Abu Dhabi and is

expected to be applied to future commercial scale CCS projects. This improvement means that

the steam consumption is reduced to 1.30 metric ton steam/ metric ton CO2or, from an energy

perspective; 660 Kcal/ Kg CO2(Steam basis = 3 BarG saturated).

Recovered CO2

Steam

Lean solvent

Steam Condensate

Stripper

CO2

Heat Recovery&

Solvent

Regeneration

Recovered CO2

Steam

Lean solvent

Steam Condensate

Stripper

CO2

Heat Recovery&

Solvent

Regeneration

Heat Recovery&

Solvent

Regeneration

Figure 4. MHIs Improved process which results in a 15% steam reduction requirement

compared with the conventional MHI process.

MHIs HEAT INTEGRATION CONCEPTS TO REDUCE ENERGY PENALTY

Further to the advanced process improvements highlighted above, MHI is also working on

methods for heat integration, together with our Power Systems Division, to further reduce the

energy penalty of CO2recovery on the power plant. These heat integration concepts include (1)

the use of LP steam, extracted from the LP turbine, for the reboiler and recovery of overhead

condenser heat (Base Case identified in Fig. 5), (2) compression heat and (3) flue gas heat.

For the Base Case, item (1) above, LP steam is extracted from the LP turbine and supplied to

the reboiler as heat for regeneration of the solvent. This external heat is then recovered by

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cooling the CO2gas (via an air cooler) at the regeneration condenser (Fig. 5). For this cooling,

the boiler feed water in the turbine cycle is utilized (Fig. 5).

Deaerator

HP/MP

Turbine

LP Turbine

Condenser

Boiler Feed Water Pump

Boiler Feed Water Pump

Boiler Feed Water Heater

Air Heater ESP

Boiler

Reboiler

RegeneratorCondenser

Deaerator

HP/MP

Turbine

LP Turbine

Condenser

Boiler Feed Water Pump

Boiler Feed Water Pump

Boiler Feed Water Heater

Air Heater ESP

Boiler

ReboilerReboiler

RegeneratorCondenser

Figure 5. LP steam extraction and condenser heat integration options between the CO2recovery

plant and the power plant (Base case)

In order to supply renewal energy required for CO2recovery, there are several options for heat

recovery from the steam cycle of the power plant which can be utilized in the CO 2 recovery

plant. Please refer to Figure 6 below for the following description;

For part E-H, pertaining to the latent heat of the steam normally lost, this can be used effectively

by extracting low-pressure steam of 2-3kg/cm2G from the power plant steam system. This heat

can be used to heat the CO2recovery plant reboiler (part E-H). However, the quantity of heat,

until just before the steam condenses from the low-pressure state of 2-3kg/cm2G, serves as a

power generation loss attributed to the steam turbine (part G-E). We believe there is future

scope to reduce this power generation loss and this should form the basis of further, more

rigorous investigation.

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100

200

500

600

700

800

900

0Entropy (kcal/kgK)

A

B

G

E

H

F

E

D

C

Steam CondensingCurve

ReboilerCondensate

Condensate

Extraction to Reboiler

Enthalpy(kcal/kg)

HP Turbine

MP Turbine

LP TurbinePower loss of

steam turbine

Waste Heat from

the condenser

Utilize waste heat of CO2 recovery

Utilize this heat for

the reboiler

100

200

500

600

700

800

900

0Entropy (kcal/kgK)

A

B

G

E

H

F

E

D

C

Steam CondensingCurve

ReboilerCondensate

Condensate

Extraction to Reboiler

Enthalpy(kcal/kg)

HP Turbine

MP Turbine

LP TurbinePower loss of

steam turbine

Waste Heat from

the condenser

Utilize waste heat of CO2 recovery

Utilize this heat for

the reboiler

Figure 6. Options for heat integration based on the power plant steam cycle

The energy penalty of MHIs CO2 recovery process, which includes power and steam

requirements associated with deep FGD, CO2 capture and CO2 compression to 2000 psi, is

shown in figure 7 below. Further heat integration (using recovery of compression and flue gas

heat), can result in additional reductions to the energy penalty on the power plant as outlined in

Figure 8 below.

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Power Loss by LP

Steam Extraction

CO2 Compressor

0

10

20

30

40

50

60

70

80

90

100

Supercritical Pulverized Coal Power

Plant; Bituminus Coal Case

PowerOutput(Index)

Deep FGD

CO2

Recovery

Auxillary

Equipment

Net Output

+

Plant Auxiliary

Equipment

Power

Power OutputPenalty

by MHI CCCP

(Base Case)Power Loss by LP

Steam Extraction

CO2 Compressor

0

10

20

30

40

50

60

70

80

90

100

Supercritical Pulverized Coal Power

Plant; Bituminus Coal Case

PowerOutput(Index)

Deep FGD

CO2

Recovery

Auxillary

Equipment

Net Output

+

Plant Auxiliary

Equipment

Power

Power OutputPenalty

by MHI CCCP

(Base Case)

Figure 7. Power Output Penalty of CO2capture and compression (Base Case)

0

10

20

30

40

50

60

70

80

90

100

Without CCCP With CCCP

(Base Case)

With CCCP +

Max Heat

Integration

Po

werOutput(Index)

Pow er Output

Penalty by MHI

CCCP

Net Output

+ Plant Auxiliary

Equipment

CCCP:

CO2 Capture,

Compression

Plant

Figure 8. Net output improvement with maximum heat integration

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CO2EOR EARLY STAGE INCENTIVES

MHI understands that in its current form, CCS is not economically viable and it necessitates the

induction of economic incentives in order to drive these projects into commercial development

and implementation. However CO2-EOR is widely recognized as providing key, early mover,

advantages in specific regions within the continental US. The price of oil, in 2008, has reached

numerous, record highs, of well over $100 USD per barrel, and is not predicted to drop in the

near future. For these reasons, and others, MHI has identified EOR as a developing market

capable of utilizing anthropogenic CO2 sources as a means to offset the costs associated with

deploying first stage CCS projects in the US.

CCS POLICY

The European Union Emission Trading Scheme (EU-ETS), Kyoto Protocol and associated

flexible mechanisms such as the Clean Development Mechanism (CDM), Joint

Implementation (JI) and international carbon trading markets are providing the necessary

drivers, carbon price signals and framework leading to the establishment of a demand-supply

emission reduction market arrangement. Furthermore a European Commission policy directive

on climate, released in January 2008, proposed a number of aggressive CO2emission reduction

objectives and strategies including;

20% reduction in CO2emissions by 2020 (from 1990 levels)

All new fossil fuel plants built from now until 2020 must be capture ready

All new fossil fuel plants after 2020 must have CCS system fitted

Importantly the directive also called for the inclusion of CCS within the next phase of the EU-

ETS (European Commission website, 2008). The European Commission has also proposed the

deployment of 12 large scale CCS demonstrations, within the EU by 2015. Additionally the

Norwegian Government has publicly stated that CCS will be an important part of its future,

with respect to gas fired power generation and is currently engaging multiple technology

providers for a CO2 capture FEED study for a CCS retrofit at the Karsto power station

(Ministry of Petroleum and Energy, Norway Government website, 2008). The UK Government

is also showing strong support for CCS by releasing a competition for a large scale, full chain,

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demonstration of CCS with the aim of having the CCS system deployed in the 2014 timeframe

(DBERR, 2007)

However, as well recognized by many stakeholders, one of the largest obstacles restricting the

deployment of CCS is uncertainties associated with the legal and regulatory aspects of CCS.

Generally speaking there is broad support for CCS within the EU and agreement, concerning a

legal and regulatory framework for CCS, may be reached by the end of 2008, thus allowing

industry to make key business decisions relating to power generation, with 50 new coal fired

power plants slated to be built in the next 5 years (New York Times website, 2008).

In North America, a number of recent initiatives and policy discussions are leading to more

definitive guidelines on the role CCS can play in CO2 mitigation. The Canadian Federal

Government recently issued an enhanced version of its Regulatory Framework for industrial

greenhouse gas emissions. This version adds details to the framework first announced in April

2007, and identifies carbon capture and storage as a key tool for reducing greenhouse gas

emissions across all industry, and particularly in the oil sands and electricity industries. Details

of the federal scheme will be provided via draft regulations to be released later this year.

In the United States a blueprint published by the Massachusetts Institute of Technology (MIT)

in 2007 states that CCS is a critical enabling technology allowing significant reduction in CO 2

emissions while allowing fuels such as coal to meet future energy needs. The MIT authors

comment further that the US Government should provide assistance only to coal projects with

CO2 capture in order to demonstrate technical, economic and environmental performance.

Additionally, during 2007, several legislative climate proposals were introduced into the US

Congress and these are currently being appraised. A number of independent analysts and

industry professionals have pointed out that the Lieberman-Warner Bill, which recommends

the implementation of a cap and trade based scheme, is the most sensible. The Bill accounts for

75% of emission sources in the US, including the electric power generation sector. The cap

commences at the 2005 emission level in 2012 and then lowers year-by-year at a constant,

gradual rate, such that it reaches the 1990 emissions level (15% below the 2005 emissions

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level) in 2020 and 65% below the 1990 emissions level (70% below the 2005 emissions level)

in 2050 (US Climate Action Network, 2007). The Bill also directs a percentage of capital

raised by an emission trading scheme into deploying advanced technologies and methods for

reducing emissions (such as CCS). Other significant legislation proposed in 2007 includes the

National Carbon Dioxide Storage Capacity Assessment Act of 2007 which requires the

Secretary of the Interior (Secretary), acting through the Director of the U.S. Geological Survey,

to develop a methodology for conducting a national assessment of the geological storage

capacity for carbon dioxide. And the Carbon Dioxide Pipeline Study Act of 2007 which

necessitates the Secretary of Energy to study, and report the results to Congress on, the

feasibility of the construction and operation of: (1) pipelines for the transportation of carbon

dioxide for sequestration or enhanced oil recovery; and (2) carbon dioxide sequestration

facilities.

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CONCLUSIONS

The climate change debate has advanced significantly over the past several years to the extent

that this issue, along with energy security, is impacting government policy in an unprecedented

way. The Intergovernmental Panel on Climate Change (IPCC) has confirmed, with 90%

confidence, that anthropogenic emissions of CO2 are directly contributing to an increase in

global temperatures facilitated by the greenhouse effect. Furthermore it is widely agreed that

demand for energy resources will continue to rise, as reflected in global energy commodity

prices which have all reached record highs. The use of coal as a primary fuel for power

generation is also forecast to increase in many countries, as it provides a relatively cheap,

stable, abundant and reliable form of energy. The deployment of CCS technology will allow

many nations to continue using these important coal reserves, in an environmentally

responsible way whilst continuing the procurement of energy to key regions throughout the

world.

The development and expansion of global carbon markets and the application of CO2EOR are

seen as key drivers for the early stage deployment of the technology in the US, due to the

attractive economic incentives they offer to project developers. MHI, whilst continuing its

extensive RD&D initiatives, have further improved CO2capture technology. Recent process and

heat integration improvements are also reducing the energy penalty and impact on the power

plant and thus ensuring CO2 capture becomes a viable future option to significantly mitigate

CO2emissions from the power generation sector whilst also securing the supply of energy to the

modern world.

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REFERENCES

1. C.D.M - Clean Development Mechanism website (2006) - http://cdm.unfccc.int/

2. EIA (2008) Annual Energy Outlook 2008, US Government, March, 2008

3. European Commission Website (2008) Climate Action proposal

http://ec.europa.eu/energy/climate_actions/index_en.htm

4. Intergovernmental Panel on Climate Change (2005). Carbon Dioxide Capture and Storage.

Cambridge University Press, New York.

5. Intergovernmental Panel on Climate Change website (2007) - http://www.ipcc.ch/

6. Ministry of Petroleum and Energy, Norway Government website (2008) -

http://www.regjeringen.no/en/dep/oed/Subject/Carbon-capture-and-storage/karsto-carbon-

capture-and-storage-projec.html?id=502211

7. MIT Massachusetts Institute of Technology (2007). The Future of Coal: Options for a

Carbon Constrained World - An Interdisciplinary MIT Study.Massachusetts Institute of

Technology.

8. New York Times website (2008)

http://www.nytimes.com/2008/04/23/world/europe/23coal.html?_r=2&ex=1366603200&e

n=31cb66311e6e90ef&ei=5090&partner=rssuserland&emc=rss&pagewanted=all&oref=sl

ogin&oref=slogin

9. Department of Business Enterprise and Regulatory Reform (DBERR) website (2007)

http://www.berr.gov.uk/energy/sources/sustainable/carbon-abatement-tech/ccs-

demo/page40961.html

10. US Climate Action Network (2007). The Leiberman-Warner Bill; Americas Climate

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