Long-Term Demonstration of
CO 2 Recovery from the Flue
Gas of a Coal-Fired Power
StationMASAKI IIJIMA* 1

TORU TAKASHINA* 2

SHOJIRO IWASAKI* 1

SUSUMU OKINO* 2

SHINYA KISHIMOTO* 1

There is now a growing demand for coal, which provides countries throughout the world with a cheap, stable andabundant fuel source. The problem, from an environmental perspective, is that the combustion of coal produces large
concentration of CO2 which is the most abundant greenhouse gas contributing to global warming. Therefore, we andmany scientists believe that CO2 capture and sequestration (CCS) from coal-fired power plants will be an essential
countermeasure against global warming in the future. Working in collaboration with Kansai Electric Power Co., Inc.
(KEPCO), Mitsubishi Heavy Industries, Ltd. (MHI) has developed an outstanding technology- KM-CDR process torecover CO2 from the flue gas of natural-gas-fired boilers and is now applying the technology at a commercial scale inseveral countries. However to be truly effective at reducing global CO2 emission we must apply this technology to thecoal-fired boilers. In recognition of this important fact MHI constructed a 10 ton/day demonstration plant at a coalfired power station in Matsushima, Japan along with funding received from the Research Institute of Innovative Technology for the Earth (RITE) and in cooperation with Electric Power Development Co., Ltd. (J-POWER). MHI has
recently completed 4,000 hours of demonstration operation at this site and this document seeks to provide a summaryof those achievements.
fired power plants are essential countermeasure against
global warming.
Working in collaboration with KEPCO, MHI has developed KM-CDR process to recovery CO2 from the fluegas of natural-gas-fired boilers and gas turbines withhigh energy-saving performance (see Fig. 11). MHI hascommercial delivery records which include facilities utilizing CO 2 for chemical processing and general use
products (dry ice, etc.). One of these CO2 recovery plants
has been in operation since 1999 at a urea production
facility in Malaysia and has achieved consistently highlevels of performance (see Fig. 2
2).

1. Introduction
The prices of petroleum and natural gas are being
pushed up by the concern that the supplies of these resources will run short in the near future. On the contrary,coal is relatively cheap and stably available over the longterm. In fact, many analysts believe that coal-fired power
generation is expected to become the main method ofthermal power generation in the future.
There is an obvious problem, however, as coal-fired
power plants release abundant CO2. Thus, CCS for coal-Flue gas outlet(treated)

Recovered CO2
Purity: 99.9 % or more

Regenerator

C.W.

Absorber
C.W.
Flue gas
coolerC.W.
Flue gas

C.W.

Reboiler
Steam

Fig. 1 Flow diagram of CO2 recovery plant
Flue gas is cooled by the flue gas cooler and CO2 in the flue gas is
absorbed at absorber by contacting an alkaline solvent.
Solvent containing abundant CO2 is transferred to the regenerator.
The solvent is regenerated by heating with steam and releases CO2.
The regenerated solvent is returned to the absorber and reused.

Fig. 2 CO2 recovery plant delivered
to Malaysia

Mitsubishi Heavy Industries, Ltd.
Technical Review Vol. 44 No. 2 (Jul. 2007)*1 Plant and Transportation Systems Engineering & Construction Center*2 Hiroshima Research & Development Center, Technical Headquarters

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The flue gas of coal-fired boilers includes SOx, dust,
and other impurities not normally present in natural gas.
Through the cooperation of RITE and J-POWER, MHI
constructed a CO 2 recovery demonstration plant which
incorporated countermeasures capable of effectively removing these impurities prior to induction in the CO 2
recovery plant. Demonstration by continuous operationcommenced in July 2006. In this article we report on
the results of this demonstration test and describe ourapproach moving forward in the future.

and to identify factors that hinder stable operation.
(2) Understanding the influences of dusti. Understanding the capture efficiency
Dust accumulation may lead to scaling of the equipment, plugging of strainers, and other undesirable
impact. Equipment designs therefore need to significantly accommodate the potential impacts of dust
accumulation. Successful design work requires accurate knowledge on the amounts of dust accumulated
and the efficiency with which dust is captured in thevarious systems.
ii. Understanding the influence on solvent
Dust accumulation in the solvent may lead to anincreased foaming tendency of the solvent. If the
foaming tendency increases, the flooding(Note 1) occurs
more readily in the regenerator and absorber, hindering stable operation of CO2 recovery plant. Therefore
it becomes necessary to firstly confirm the interaction between the amount of dust in the solvent, thefoaming tendency, and flooding phenomenon. We thendesign equipment and implement operational control
strategies in response.

2. The need for CO2 recovery in coal-fired power stations
To continue using fossil energies for thermal power
generation effectively in the coming years, we need toconsider the options of both natural gas and coal. It is
expected that petroleum will be used as a secondary fuelfor thermal power generation to respond to peak demand.
Large reserves of natural gas exist in Russia and the
Middle East. However the production of natural gas isnow forecasted to peak about 10 years following the peakin petroleum. With the recent dramatic rises in the priceof natural gas, the ratio of fuel coal for electric power
generation will continue to increase well into the future.
Gas-producing countries are expected to apply natural gas combined cycle (NGCC) to their newer thermal
power stations, while other countries are expected toapply coal-fired power generation.
When we consider the countermeasures against global warming, we know that CCS will be essential as longas we continue to utilize fossil fuels. Research on CCS
has made good progress in recent years, and there are
now calls for concrete implementation. Thermal power
stations account for about one-third of CO 2 emissions
worldwide and are concentrated sources of CO2 release.
These stations are therefore extremely attractive sites
for CCS implementation.
MHI has been developing CO 2 recovery technology
from the flue gases of power station aiming an effective
use of CO2 and a countermeasure against global warming. MHI commercialized the technology for applicationin boilers and furnaces that fire natural gas (a relatively
clean flue gas). Our next aim is to commercialize thistechnology for application in coal-fired power stations,and thus we have commenced a demonstration test.

Note 1: The rising gas restrains the descent of a flowing
liquid in a packed column.

iii. Understanding the influences on the equipment
Dust in the liquid is known to scale and plug equipment and potentially reduce heat transfer efficiency.
It thus becomes necessary to understand the influences of dust on the equipment, and to design theequipment and control the operation in response to
those influences.
(3) Understanding the influences of SOx
i. Removal ratio in the flue gas desulphurization
sectionSOx promotes the degradation of solvent. A fluegas desulphurization section using caustic soda istherefore installed to reduce the concentration of the
SOx introduced into the absorber. It thus becomes
necessary to confirm the removal ratio of SOx, in order to verify the desulphurization efficiency in the fluegas desulphurization section.
ii. Understanding the influence on solvent
The gas that passes through the flue gas
desulphurization section may contain trace amounts
of SOx. This trace level SOx may then accumulate
in the solvent to produce heat-stable salts(Note 2). The
behavior of these heat-stable salts therefore needs beconfirmed.

3. Technical considerations of CO2 recovery from coalfired flue gas streams
The flue gas of coal-fired boilers contains SOx, NOx,dust and other impurities. For this reason it is critically important to develop this technology to achieve thefollowing tasks:(1) Confirming long-term operation
To monitor the operation of the CO2 recovery plant
for a long period to confirm whether stable operationis possible with the assumed pretreatment equipment

Note 2: Compounds of acid and alkali that resist disassociation by steam heating.

(4) Understanding the influences of NOx
NOx influences the degradation of the solvent. It
thus becomes necessary to identify the sections whereNOx is absorbed in a CO 2 recovery plant and to assess the amounts absorbed.
Mitsubishi Heavy Industries, Ltd.
Technical Review Vol. 44 No. 2 (Jul. 2007)2

(5) Understanding the influences of chlorine and fluorine
The accumulation of chlorine and fluorine may leadto corrosion of the equipment. When selecting thematerials for the equipment, it is important to identify the sections where chlorine and fluorine
accumulate in a CO2 recovery plant and to assess theamounts accumulated.
(6) Understanding solvent loss
The cost of solvent accounts for a large portion of
the operation cost, next to that of steam. Therefore
minimizing solvent loss is very important and accordingly, the solvent loss need be confirmed.

Performance values equivalent to or higher thanthe planned values could be obtained over the demonstration period (4,000 hours) for both the CO 2
recovery efficiency and CO2 recovery capacity.
ii. Specific heat consumption required for CO2 recovery
The most effective way to reduce plant operation
costs is to minimize the steam consumption of the CO2
recovery plant, the largest contributor to the operation cost. We calculated the specific heat consumption
required for CO 2 recovery from the steam consumption and the CO2 recovery capacity during this test,
as shown below.
Actual achievement of specific heat consumption
required for CO2 Recovery : 730 - 820 kcal/kg-CO2
Though the design approach for the absorber andregenerator is almost the same as that for the natural-gas-fired boiler, the performance was superior towhat was expected in terms of the specific heat consumption required for CO 2 recovery. Moreover,regarding the specific heat consumption required for
CO 2 recovery, we expect to achieve a further reduction of about 15% by applying a new process (Note 3)(jointly developed by KEPCO and MHI) to the CO 2
regeneration process.

.

4. Demonstration test results
4.1 Outline of plant
Using a subsidy (subsidy of 50 % cost share) underthe "Technology Development Program to Promote theAchievement of the Kyoto Protocol" by RITE, and throughcooperation of J-POWER, MHI was able to successfully
construct the demonstration test plant at an existingcoal-fired thermal power station in Matsushima. The
test plant specifications and flow diagram are shown in
Table 1 and Fig. 33, respectively.
4.2 Measurement methods and test results(1) Monitoring of operational status(a) Measurement methods
Input data relating to flow rates, temperatures,pressures, etc. into a computer model in time sequence, to characterize the operational status of the
CO 2 recovery plant. Confirm the CO 2 purity by gas
measurement.
(b) Test results
The installation of pretreatment equipment enabled stable operation over a long period (4,000 h)with no unexpected problems. Evaluations from theviewpoint of performance are shown below.
i. Efficiency and capacity of CO2 recovery
Fig. 4 demonstrates the time sequence data of the
CO 2 recovery efficiency calculated from the values
indicated by CO2 densitometers at the absorber inlet
and outlet and the amount of CO2 recovery measured
using flow meters.

Note 3: Energy-saving process in the CO2 regenerator using
heat recovery from the solvent and steam condensate.

BoilerDe-dust

De-SOxStack

GGH

Scope of demonstration plant

Flue gas

CO2
Flue gas
C.W.
AbsorberC.W.
Regenerator
C.W.
C.W.
Steam

BlowerFlue gas
coolerFig. 3 Flow diagram of CO2 recovery demonstration plant
The equipment composition, etc. of this figure is of a standard typeapplied commercially and differs slightly from that of the actual plant.

Parameters (planned values)

Installation location

Within Matsushima Thermal Power Station
owned and operated by J-POWER

Flue gas source

Flue gas coal-fired boiler

Amount of flue gas
to be treated

1 750 m3N /h

CO2 recovery efficiency

90 %CO2 recovery capacity

Planned value: 9.5 ton/day (Max. 10 ton/day)

CO2 concentration

14.1v %

Other impurities

Dust, SOx, NOx, etc.

Solvent

CO2 recovery efficiency (%)

Items

100
80
60
40
20
0
0

12
10
8
6
: CO2 recovery efficiency (left axis)
4: CO2 recovery capacity (right axis)
2
0
1 000
2 000
3 000
4 000
5 000

CO2 recovery capacity(ton/day)

Table 1 Specifications of CO2 recovery demonstration plantOperation period (h)Fig. 4 Movement of the CO2 recovery efficiency and CO2 recovery
capacity

KS-1 solvent

Mitsubishi Heavy Industries, Ltd.
Technical Review Vol. 44 No. 2 (Jul. 2007)3

iii. Purity of the recovered CO2
Table 2 compares the commercial CO 2 recovery
plant for the natural-gas-fired boiler and the new coalfired demonstration CO 2 recovery plant.
The result shows that KM-CDR process achieved
a high-purity equivalent compared to that of the natural-gas-fired boiler for the coal-fired boiler.

(b) Test results
The dust from the coal-fired boiler flue gas accumulated in the solvent and did not cause flooding
during this demonstration test. The amount of dustin the solvent and the respective foaming tendency
had no interaction with either the absorber pressure
loss or the regenerator pressure loss.
iii. Influence on equipment(a) Measurement methods
Monitor the operational status of the equipment
affected by dust, as shown in Table 4
4, to understandthe influences of dust on the equipment.

Table 2 Recovered CO2 purity
Actual performance of commercial
plant with a natural-gas-fired boiler

Actual performance of thisdemonstration plant

99.9 % or more

99.9 % or more

(2) Understanding the influences of dusti. Understanding the capture efficiency(a) Measurement methods
Clarify the amounts of dust accumulated and capture efficiencies in the respective sections of the CO2
recovery plant by measuring the dust concentrations
in both the gas and liquid. Table 3 shows the areas
where the amounts of accumulated dust and capture
efficiencies are assessed and the measurement items
used for the assessment.

Table 4 Items monitored for understanding the influences ofdust on the equipment components
Equipment component

2. Solvent system

2. Heat exchanger* Heat transfer coefficient.

Measurement items* Dust concentration at the inlet ofthe flue gas cooler* Dust concentration at the outletof the flue gas cooler* Dust concentration in the waste
water of the flue gas cooler

Flue gas cooler pressure
loss (relative value)

1. Flue gas cooler system* Pressure loss of tower(b) Test results
Flue gas cooler pressure loss and absorber pressure loss
Figs. 5 and 6 show the time sequence data of thepressure losses in the flue gas cooler and absorber.
There was no tendency for increased pressure loss
even after an elapse of 4,000 hours of operation. The
result revealed that the plugging of packing material
and demisters can be prevented by the pretreatment
method applied on this occasion.

Table 3 Items measured for the quantification of the dust capture
efficiency
Sections where the amount ofaccumulated dust and capture
efficiency are assessed

Monitoring items

1. Flue gas cooler
Absorber* Dust concentration in gas at theoutlet of the absorber* Dust concentration in the solvent* Dust concentration in the solvent
before and after the filter (*1)

*1: Installed in the solvent circulation line(b) Test results
The measurement of dust in the respective sections
clarified the following:
The capture efficiency of dust in the flue gas is
about 40 - 50 % in the flue gas cooler and about 40- 60 % in the absorber.
The filter removes dust from the solvent, and thedust concentration in the solvent does not increase.
ii. Influences on solvent(a) Measurement methods
Assess the interaction among the amount of dust
in a solvent, the foaming tendency of the solvent, andthe flooding phenomenon of the solvent by measuring
the dust concentration in the solvent, testing the solvent for the foaming tendency, and monitoring thepressure loss in the absorber and regenerator.

2: Flue gas cooler pressure loss
1.5
1
0.5
0
0

.
.

1 000

2 000

3 000

4 000

5 000

Operation period (h)Absorber pressure loss
(relative value)

Fig. 5 Movement of pressure loss of the flue gas cooler

2: Absorber pressure loss
1.5
1
0.5
0
0

1000

2 000

3 000

4 000

5 000

Operation period (h)Fig. 6 Movement of the pressure loss of absorber

Mitsubishi Heavy Industries, Ltd.
Technical Review Vol. 44 No. 2 (Jul. 2007)4.

desulphurization system and other pretreatment
equipment).
(6) Confirmation of solvent loss
i. Amount of solvent loss(a) Test methods
Determine the amount of solvent loss throughanalysis of the solvent, etc.
(b) Test results
The solvent loss measured was close to the expected value. In this test we could assess the solvent
loss quantitatively from the coal-fired boiler flue gas.
We will apply the test result to actual projects inthe future.
4.3 Outcome of the test results
We demonstrated that the impurities from the coalfired boilers can be treated by installing a flue gas cooler
with deep flue gas desulphurization and flue gas water
washing functions as a pretreatment process. We also
confirmed that CO2 can be stably absorbed and regenerated by these pretreatments and filters. The following
concrete results were achieved:(1) Demonstration operation for 4,000 hours and a CO2
recovery performance equivalent to or better than the
expected performance.
(2) Data on the de-dust capacity of the pretreatment
equipment and the behavior of the dust in the solvent system.
(3) Data on the absorption ratios of SOx and NOx in therespective sections, and their respective behaviors.
(4) Quantitative data on the solvent loss.

Heat transfer coefficient of the heat exchanger
The heat transfer coefficient decreased in the heatexchanger using cooling water after the elapse of somany hours of operation. This was explained, however, by the scaling of material in the cooling water
to the heat transfer surface of the heat exchanger.
We believe that the problem can be solved by implementing appropriate water treatment. No significant
decreases of the heat transfer coefficient were foundin the heat exchanger operated without the use ofcooling water.
(3) Understanding the influences of SOx
i. Removal ratio in the flue gas desulphurization section(a) Measurement methods
Determine the SOx removal ratio in the flue gas
desulphurization section by measuring the SOx concentration in the flue gas at the inlet of the flue gas
cooler and in the flue gas at the outlet.
(b) Test results
The SOx removal ratio in the flue gas
desulphurization section was 98% or higher.
ii. Influence on solvent(a) Measurement methods
Measure the concentration of the heat-stable salts
in the solvent.
(b) Test results
Though almost all of the SOx at the outlet of theflue gas cooler was absorbed by the solvent and became heat-stable salts, the amounts produced could
be maintained at a low level by installing a flue gas
desulphurization section. Thus, the performance ofthe solvent could be consistent with that of the natural-gas-fired boiler.
(4) Understanding the influences of NOx
i. Absorption ratio(a) Test methods
Determine the NOx absorption ratio in the flue gas
cooler and absorber by measuring the NOx concentrations in the gas at the inlet and outlet of the fluegas cooler and in the gas at the outlet of the absorber.
(b) Test results
The flue gas cooler absorbed almost none of theNOx in the flue gas. The absorber absorbed about 1- 3% of the NOx.
(5) Understanding the influences of chlorine and fluorinei. Amounts accumulated(a) Test methods
Measure the concentrations of chlorine and fluorine in the waste water of the flue gas cooler and in
the solvent.
(b) Test results
The tests confirmed that no chlorine or fluorine
was detected in the flue gas or solvent, and that chlorine and fluorine were deeply removed upstream of
the CO 2 recovery plant (by the existing flue gas

5. Approach for the future
MHI ultimately aims to provide customers with highly
reliable commercial plants (of about 5,000 ton- CO2/day)at low cost. To achieve this, we need to verify not only
the issues from the viewpoint of the chemical and equipment processes, but also the realization of larger-capacity
plants as hardware in the future.

6. Conclusion
The demonstration operation of 4,000 hours wasachieved at a coal-fired power station in Matsushima.
We clarified the behaviors of dust, SOx, and NOx inthe equipment systems and how these components influence the solvent. Accordingly, we have been able toachieve almost all of our targets of our tests to verify
the influences of impurities contained in the flue gas
produced from coal-fired power stations. In conclusion,
we confirmed that KM-CDR process can be applied to
the flue gas of coal-fired boilers through the implementation of appropriate pretreatment facilities. Having
achieved the aforementioned, it is now technically feasible to apply this process in middle-class plants (witha capacity of several hundred up to a thousand tonsCO 2 /day).
Mitsubishi Heavy Industries, Ltd.
Technical Review Vol. 44 No. 2 (Jul. 2007)

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Studies on CO 2 recovery from coal-fired power stations have been actively commencing in recent years inefforts to realize countermeasures against global warming mainly in Europe and the United States and also inJapan. We are confident that MHI's technology can takeleading role in these efforts.
We would like to take this opportunity to express
our most sincere gratitude to J-POWER for their fullcooperation and support during the demonstration testing period.

Masaki Iijima

Toru Takashina

References(1) Iijima, M. et al., Flue Gas CO2 Recovery Technology and Its
Application to EOR: an Effective Strategy for Addressing theIssues of Global Warming and Peaking Oil Supply, Mitsubishi
Heavy Industries Technical Review Vol. 44 No. 1 (2007)(2) Iwasaki, S. et al., Large Scale Flue Gas CO2 Recovering/ CO2
Cost and Total System for CO 2 Enhanced Oil Recovery,
Mitsubishi Heavy Industries Technical Review Vol. 41 No. 4(2004)(3) Iijima, M. et al., Fuel Gas CO2 Recovery Utilization, Disposal,
and Business Development, Mitsubishi Heavy Industries
Technical Review Vol. 39 No. 5 (2002)

Shojiro Iwasaki

Susumu Okino

Shinya Kishimoto

Mitsubishi Heavy Industries, Ltd.
Technical Review Vol. 44 No. 2 (Jul. 2007)6