LNG Terminal Operators Design Feedbacks and Technical Challenges

Gyu-Hyuk Lim
Head of Pyeongtaek LNG Terminal
Lae-Hyun Park
Manager, Technology
Pyeongtaek LNG Terminal
Korea Gas Corporation

ABSTRACT
Pyeong-taek Terminal II (560,000m3 and 720 t/h) is now under construction in order to comply
with the abruptly increasing gas demand in Korea. For the optimum design of the new terminal, the
impacts of the main equipments reliability and availability on both the stream line availability and
construction and operating costs have been carefully evaluated. Other important design parameters,
such as the variation of the imported LNG heating values and the high seasonal gas sendout demand,
have also been optimized in the new terminal design.
This paper presents the practical design improvements that have been directly applied to Pyeong-taek
Terminal II in order to reduce costs and to enhance the terminals availability. These involve
economical vapor handling and re-condensing, zero emission of LNG vaporization, and an optimum
sparing level of the main equipment based on an actual 18-year operating record of reliability and
availability of the main equipment.

Gastech 2005

INTRODUCTION
In order to meet the abruptly increased natural gas demand, Pyeongtaek terminal has
continuously been expanded. The terminal added consecutively LNG storage tanks, re-gasification
facilities, and an unloading berth. Presently, 10 units of storage tanks are under operation with a total
capacity of one million cubic meters and 2,020 t/h re-gasification facilities.
During 18 years of operation of the terminal, the existing conventional designs have been
improved upon enhancing the terminal reliability, achieving high controllability, and keeping a high
level of safety. The terminal operators design improvements, as well as experiences in operation and
maintenance, are valuable for the LNG industry. However, the operation feedbacks have been limited
so far even though their role of receiving LNG is important in an LNG chain.
This paper presents the terminal operators practical design improvements against the
conventional design problems occurred unexpectedly during terminal operation and maintenance.
These design improvements, applied to the design of Pyeongtaek Terminal II for reducing costs,
involve economic vapor handling and recondensing, zero emission vaporization, and an optimum
sparing level of the main equipment with their 18 years of operation records. This paper also
discusses the impact of reliability and availability of main vapor handling equipment on revenue losses
and total expenditures based on life cycle costs.

PRACTICAL DESIGN IMPROVEMENTS

Boil-off Gas Handling

LIC

The mixing of pressurized Boil-Off Gas (BOG) with the sub-cooled LNG in the re-condenser will
increase the temperature of the LNG, resulting in a decrease in liquid density. The temperature and
density of mixed LNG depends on the temperature and flow coming to the re-condenser of both the
ESD
LNG and BOG. Consequently, the
PIC
change in liquid density affects
BOG Compressor
pump performance. One or two
Cold Energy
PSV
boosting pumps are running
Utilization Plant
according to the send-out
demand. The first role of a
Re-condensing
boosting pump is to compensate
Heat
ORV
Exchanger
the low suction pressure of
HP Vaporizer
secondary pumps due to the
operating
pressure
of
rePIC
PIC
PIC
liquefaction system. In order to
save operating costs of boosting
Boost Pump
SMV
2ry Pump
pumps, the variable frequency
HP Vaporizer
drive pumps were installed so LP discharge line
ORV
LP
Vaporizer
that operating costs of the
Legend
LNG Line
boosting pumps can also be
Vapor Line
saved.
The process flow
diagram for vapor recondensing
Fig. 1 Process Flow Diagram of BOG Recondensing System
is shown in Fig. 1.
ES

HP Gas
network

ES

The total BOG rate depends on the terminal operating mode, season, temperature, day/night,
etc. It varies from 20 to 30 t/h in normal holding mode operation and increases by about 10 t/h
during LNG unloading mode. The terminal has high BOG rate because of a high BOG rate of storage
tanks (0.1% per day and 10 storage tanks) and vapor returned from cold energy utilization facility.
Normally, one BOG compressor will be added during the LNG unloading operation (in some cases, it
requires adding two units). The required number of BOG compressors depends on the LNG sources and
ships saturation pressure.
Two different types of BOG compressors have been used: Horizontal ring-type reciprocating
(4sets) and vertical compressors with contactless labyrinth pistons (2 sets). The design capacity of

Gastech 2005

Lim 2

each compressor is 12,000 Nm3/h of BOG with a maximum discharge gauge pressure of 10.6 barg
and a discharge temperature range from 14 to 47oC. The vapor of the compressed BOG and returned
re-gasified gas from cold energy utilization plant is used as fuel gas for the tank vacuum breaker,
internal consumption (gas firing absorbed type heating/chilling unit), and neighboring KIA Motors.
The operating pressure range of the storage tank is from 50 170 mbarg. BOG compressors
are started by tank pressure manually or automatically, which can be selected by operators choice.
Combined operation concept - continuous and intermittent operation - has been used for the BOG
compressor operation. When the LNG tank operation pressure reaches 150 mbarg, a unit of compressor
stopped. If tank operating pressure continuously decreases, an additional compressor will be stopped.
Conversely, a BOG compressor will be added when the tank operating pressure reaches 170 mbarg.
Capacity controllers (50, 75, and 100%) are also used to control the compressors operation capacity.
The suction temperatures of the BOG compressors are slightly different in each operation mode
as follows:

Holding mode:

-100 to -110oC

Unloading mode:

-110 to -120oC

During the terminal intermittent operation the suction temperature varies minus 60 70oC after
10 hrs of stopping compressors (no operation of BOG compressors). It requires about 5 to 10 minutes
until the compressor reaches normal operation. The horizontal compressors require suction vapor
desuperheating by using LNG spraying at the BOG knockout drum inlet, while the vertical compressors
can quick start without desuperheating.
The basic principle of the BOG recondensing system is to cool, recondense and send-out the
excess vapor of natural gas by mixing it with a sub-cooled LNG taken from the LP LNG header line. In
order to improve the heat and mass transfer of gas and liquid phases, the condensation takes place
in a packed tower where gas and liquid enter the top of the re-condenser and flow co-currently
through the bed of metal rings, where both phases come in close contact. The re-condenser
operating level is carefully monitored and maintained at half height [1].
Thermally Integrated Vaporization
LNG is stored in storage tanks at cryogenic temperature of approximately minus 160C at
near atmospheric pressure. The LNG is regasified and warmed to temperatures near 0C and desired
send-out pressure. LNG is most commonly vaporized in Open Rack Vaporizers (ORVs) against the
seawater or in Submerged Combustion Vaporizers (SCVs) where the cold energy contained in the
stored LNG is wasted during the regasification process. An LNG terminal has a large storage of
cryogenic energy, which has to be released in order to re-gasify LNG. On the other hand, a power
plant must reject heat to condense steam and to cool equipment.
The terminal integrated thermally with an adjacent Pyeong-taek Thermal Power Plant, of
which has equipped four 350MW steam power generation and
480MW Combined Cycle Gas Turbine (CCGT). The power plant has
Gas Turbine
Exhaust
HRSG
owned and operated seawater lift structure for the power plant
cooling purpose. The seawater that used for steam condensing in the
Steam
Turbine
power plant increases in temperature. This warmed seawater is used
Condenser
Seawater
for LNG vaporization as shown in Fig. 2.
G

The thermal integration of the two plants, supplying warmer

seawater from the power plant to the terminal, results in significant
benefits:

Sendout
Gas

LNG
Vaporizer
HRSG: Heat Recovery Steam Generator

Sharing of the seawater lift facility, which reduces high capital

Fig. 2 Integration Scheme with
costs;
Once Through Seawater
Reduction in thermal pollution, which results in
environmentally friendly energy plants;
Reduction in regasification costs by using the warmed seawater;

Gastech 2005

Lim 3

Since the terminal uses the warmed seawater discharged from the power plant, the terminal
eliminates intrinsically the operation of SCVs, which can only be used for back-up or peak shaving. As
a result, this integration leads to no emission of green gas for LNG vaporization.
Combined Cycle Gas
Turbine

Thermal Power Plant

Excess
Seawater

Power Plant

LNG Terminal

Pump Station

Vaporizer Pump
Station # 1

Open Discharge Canal

In order to reduce the

natural gas (NG) production costs,
the terminal has been designed to
maximize the use of seawater
discharged from the power plant.
The lifted seawater goes to the
power plant and excess seawater
bypasses and is mixed with the
warmed seawater discharged from
both thermal power plant and the
CCGT. Figure 3 illustrates the
seawater configuration. A portion
of seawater is used for the ORV
group #1 through pump station #1.
The seawater discharged from the
ORV group #1 will be determined
to reuse it for ORV group #2 by
controlling the re-usage valves. It
depends on the available amount
of seawater, seawater temperature,
and gas sendout demand. This reusage concept of seawater could
save an additional seawater lift
structure, resulting in low costs
LNG vaporization by maximizing
heat usage from seawater.

Seawater Canal

Seawater Lift
Structure

LNG Vaporizer
Group # 1

Re-Usage

Vaporizer Pump
Station # 2

LNG Vaporizer
Group # 2

Return to Sea

Fig. 3 Seawater Supply and Distribution System

LNG TERMINAL OPERATION RELIABILITY

Definition of Reliability, Availability, and Risk
There is often confusion between the terms Reliability, Availability, and Risk. So far it has been seen
that there is a need for a scientific definition of reliability and for a method of reliability evaluation
which can be applied to a wide range of technological projects. Reliability related to the overall LNG
terminal can be defined as the probability that the terminal as designed will perform its function
(unloading LNG/storage/regasification) over a specified period of time under normal operating conditions.
Similarly, the availability of an LNG terminal is the fraction of time that it can perform its function under
normal operating conditions. On the other hand, a dictionary definition of risk is the possibility of loss or
injury to people and property. In this study, the following conventional definitions of the reliability and
unit availability are used [2-4].
RT =

TOT
........................................................................................................................... (1)
TOT + UT f

AT =

MTTF
...................................................................................................................... (2)
MTTF + MTTR

where,

RT
TOT

: Equipment Reliability
: Total operating time of equipment

Gastech 2005

Lim 4

UTf
AT
MTTF
MTTR

:
:
:
:

Unavailable time due to scheduled maintenance

Unit Availability
Mean time to failure
mean time to repair

Equipment Reliability and Availability

The sendout availability of an LNG terminal is largely determined by the major equipment items
included LNG pumps, vaporizers, and compressors. The equipment provided within the terminal can be
categorized as follows in terms of contributions to overall reliability and availability: static equipment
and key regasification equipment.
Static equipment include a flare stack, vent stack, and instrument air receivers (vessels).
These items are, in general, very reliable with very low failure rates (typically one failure per 100,000
operating hours), provided the design and fabrication are performed according to recognized codes
and standards.5
Key regasification equipment consists of pumps, vaporizers, and compressors. These
equipment items are provided with spare capacity so that full sendout can be maintained while one
item is out of service. Since the ORVs have no moving parts, they are essentially very reliable.
However, they are also susceptible to surface fouling due to exposure to seawater. This fouling
potential is controlled by hypo-chlorination, but periodically the units must be taken out of service for
cleaning and painting. In order to make up for this short fall the submerged combustion vaporizers
(SCVs) will be kept in a rolling standby mode so that it can rapidly respond to the increase in
sendout. Since several compressors are provided to handle excess displacement vapour during the
ship unloading operation and a few are required to handle normal BOG, a spare machine normally
exists.
In order to permit full sendout flow in spite of failures in main rotating equipment, the plant
design assumes rotating equipment failure, which is generally lower reliability than non-rotating
equipment. It is a general rule in LNG terminal design to have a couple of spare pumps. Therefore,
the availability of the pumping system is considerably high. Since the effect of an unavailability of a
pumping system, vaporizing system, and Vapour handling system directly affects the terminal stream
production, this paper focuses on the effect of reliability and availability of those key systems. This
paper also discusses the economic impact of different types of ORV and BOG compressors on both
the probable revenue losses and life cycle operating and maintenance costs.
Data Collection
The company developed the equipment history card system and has applied it from the startup
operation of the terminal. This includes the equipment tag number, purchase date, installation date,
operation history, and maintenance history. The actual operation records were analyzed to get the
operation hour of main equipment of regasification. Each of the operation hours was then summed to the
same equipment type. Since equipment capacity installed at the initial stage are different from those of
expansion, operation records were separately collected for the different equipment sizes even with the
same type. On the same token, the maintenance history records of each equipment have been
investigated and collected based on the type of failure, including preventive (regular planned)
maintenance.
Analysis of Reliability Data
The reliability data base for the main regasification process units was established based on 18
years of operation at Pyeongtaek Terminal. Table 1 presents the summarized reliability database.
LNG Storage In-tank Pumps
At the initial design of the terminal, two LNG in-tank pumps per an LNG tank were installed.
Three LNG tanks were dedicated for the initial operation in 1986. One year later, the fourth LNG tank
was added. By the consecutive expansion, ten LNG tanks (above-ground membrane type tank), of which
capacity is 100,000 m3 each, are under operation. A total of 22 LNG in-tank pumps have been operated.
An MTTF of 3,221 hours was obtained. This value is lower than the MTTF values reported by GIIGNL

Gastech 2005

Lim 5

(6100 hrs) and by GRI (3900 hrs) [5]. The GRI study is based on US plants that are mainly peak shaving
plants, where pumps would largely be used intermittently.
Table 1 Reliability database for key Regasification Equipment
MTTF

MTTR

TOT

UTf

RT
(%)

AT (%)

In-tank Pump

3,221

37

22

698,957

1,085

99.85

98.86

Sendout Pump

4,277

44

20

770,040

1,620

99.79

98.98

BOG Comp (Vert)

5,970

100

95,516

272

99.72

98.35

Process Unit

BOG Comp (Horz)

4,596

147

3*

220,608

1200

99.46

96.90

ORV (U type)

3,288

116

105,248

960

99.10

96.59

ORV (I type)

7,012

61

273,507

390

99.86

99.13

Notes:

1. One compressor recently operated in 2002 is not included.

2. These are operational data recorded from 1987 to 2002.

LNG Booster Pumps

A total of six units of high booster pumps, of which capacity is 80 t/h, have been operated since
the terminal started its operation. Different capacity (110 t/h) of LNG booster pumps have been installed
at the expansion stage. A total of 20 units of LNG pumps are presently under operation.
BOG Compressors
Three horizontal ring-type double stage BOG compressors have been operated since 1987 with a
recorded 4,596 hrs of MTTF, while two vertical compressors with contactless labyrinth pistons have been
operated since 1995 and showed 5, 970 hrs of MTTF (about 30% higher than the horizontal). The higher
MTTF of the vertical compressor leads to the fact that the field person has a general tendency to use
more this type of compressor, which is more reliable.
Open Rack Type Vaporizers (ORVs)
Two different types of HP ORVs have been operated: the top reserve type design (U type) and
the trough type design (I type). 3,288 hours and 7,012 hours of MTTF have been obtained for the U
type and the I type, respectively. The difference can be interpreted as manufacturing reliability, which
is also an important parameter in unit equipment reliability, as well as terminal availability. Because of
frequent problems of the U type, such as corrosion and erosion of heat exchange tubes, and thereafter
gas leaks, the company is under replacing the U type vaporizers by I type vaporizers.
Reliability Estimation of LNG Terminal
The unit equipment reliability may be different from that of the sendout system because the
sendout system consists of several types of equipment system. These involve key main equipment as
discussed in this study. However, the sendout system is simplified consisting of storage LP in-tank pumps,
HP boosting pumps, vapor handling compressors, and vaporizers (ORVs). Seawater pumps and SCVs
are excluded in this estimation. Terminal sendout operation availability can be a useful guideline in
determining the level of back-up facility.
In a serious configuration as shown in Fig. 4, a failure of any component/subsystem results in a
serious reduction in the sendout capacity. It is found that the terminal regasification is arranged
reliability-wise in a series configuration. In the case where the failure of a component affects the failure
rates of other components (i.e. the life distribution characteristics of the other components change when
one fails), then the conditional probabilities must be considered.

Gastech 2005

Lim 6

In a serious configuration, the

component with the smallest reliability has the
biggest effect on the systems reliability. There is
BOG Compressor
a saying that a chain is only as good as its
weakest link. In a chain, all the rings are in a
series and if any of the rings breaks, the whole
system fails. In addition, the weakest link in the
chain is the one that will break first. The weakest
link dictates the strength of the chain in the
Recondenser
LP Intank
same way that the weakest component
Natural
Pump
Gas
/subsystem dictates the reliability of a series
system. As a result, the reliability or availability
LNG Tank
LNG
HP Sendout
of a system is always less than the
Vaporizer
Pump
reliability/availability of the least reliable
component.
Fig. 4 Simplified LNG Regasification Process
The effect of each subsystems availability on the overall regasification system availability is
presented in Table 2. The first row of the table shows the availability of each unit. Subsystem availability
is a matter of spare unit. The next row shows the required number of units followed by the total number
of units, including spare units. Since the rotating pumps have low reliability, it is assumed that in-tank
pumps and booster pumps both have two spare pumps. It is also assumed that three BOG compressors
have 50% capacity. Each subsystem availability is shown in the table.
Table 2 Example Estimation of Regasification System Availability
Vertical
BOG
Comp.
98.35

Booster
Pumps

I Type
ORV

U Type
ORV

98.86

Horiz
BOG
Comp.
96.90

98.98

99.13

96.59

Required number of units

Spare Units

Total number of Units

Subsystem Availability

1.000

0.9818

0.9946

1.000

0.9985

0.9782

Intank
Pump

Description
Unit Availability (%)

Total Sendout
Availability
with I Type
ORV
Total Sendout
Availability
with U Type
ORV

Horiz
Comp.
Vertical
Comp.
Horiz
Comp.
Vertical
Comp.

BOG

0.9802

BOG

0.9930

BOG

0.9603

BOG

0.9728

Note: Equipment combination is based on 700-900 t/h (750 1,000 MMScfd) sendout

ECONOMICAL IMPACT OF RELIABILITY/AVAILABILITY

Unavailability
LNG terminal unavailability can be defined as the number of days a year the terminal is not
on stream due to the system/equipment failure (unscheduled down time) in view of statistical
probabilities. The above include the time required for cooldown, warm up, etc. In other words, it is
the period of time the terminal is not sending out the regasified LNG. The scheduled down time
depends on the type, size and number of system/equipment requiring regular maintenance, as well
as local regulations, like statutory inspection of system/equipment. Scheduled down time also
depends on the maintenance program and the philosophy of the terminal operator.
Unscheduled downtime depends on the failure of any system/equipment in the terminal that
would force a shutdown. These failures are considered random events with constant failure rate
Gastech 2005

Lim 7

distributions, i.e., any system/equipment is equally likely to fail at any one time as any other. In an
LNG terminal, a high percentage of this downtime is associated with the type and number of rotating
equipment mainly pumps and compressors [6,7]. The total terminal unavailability is then the sum of
unscheduled terminal shutdown because the scheduled shutdown of system/equipment is either done
during the spare unit operation or during low gas demand seasons.
Figure 5 illustrates the relationship between Availability and unavailability of the BOG
compressor system. BOG system availability increases with an increase in unit availability. Conversely,
the unavailability of the BOG system decreases as unit availability increases. Mathematically,
unavailability can be obtained from deducting the availability from one (1). The unavailability of a
Horizontal compressor system is higher than that of a vertical compressor system.

100.1

0.5

0.4
0.35

99.9

0.3
99.8

0.25
Horizontal
Compressor

Vertical
Compressor

0.2

99.7

0.15
0.1

System
Availability

99.6

System Unavailability, [%]

100

System Availability, [%]

0.45

System
Unavailability

0.05
99.5
95.5

96

96.5

97

97.5

98

98.5

99

99.5

0
100

Unit Availability, [%]

Fig. 5 Relationship between Availability and Unavailability
The unavailability of the U type ORV is relatively higher than the I type. The unavailability
with Horizontal compressor and Vertical compressor are 0.0397 and 0.0272, respectively. Since lower
unavailability seriously affects the terminal on stream availability.
Economic Impact of Availability
The economic impact of the availability of the vapor system is further investigated. Table 3
summarizes the probable revenue losses of the two cases: vertical compressors and horizontal
compressors. Probable revenue losses are estimated based on $4.00/MMBtu. Figure 6 presents the
sensitivity study of revenue losses with the regasified gas price ranges $2.5 $6.0/MMBtu.The
difference between the four cases of the probable revenue losses with the different types of ORVs
and BOG compressors increases with an increase in the regasified LNG price. The revenue losses are
based on probability.

Gastech 2005

Lim 8

Table 3 Unavailability and Revenue Losses

U Type ORV

Description

I Type ORV

Horiz Comp

Vert Comp

Horiz Comp

Vert Comp

Total Sendout Availability

0.9603

0.9728

0.9802

0.9930

Unavailability of Sendout

0.0397

0.0272

0.0198

0.0070

Pressure Sendout Interruption (hrs)

348.2

238.3

173.5

61.3

63.8

43,7

31.8

11.2

Probable Revenue Losses ($million)

*Note

Note: Revenue losses are estimated based on $4.0/MMBtu gas price

Probable Revenue Loss, [US$ million]

120

I ORV + Horiz Comp

I ORV + Vert Comp
U ORV + Horiz Comp
U ORV + Vert Comp

100

80

60

40

20

0
2

2.5

3.5

4.5

5.5

Natural Gas Price, [$/MMBtu]

Fig. 6 Effects of System Unavailability on Revenue Losses

Since the comparison of equipment costs and spare part costs is beyond the scope of this study, the
same equipment costs are applied to the economic analysis. Spare part costs depend on the machine
type and the reliability of the machine. However, it is also assumed that spare part costs are
equivalent to 2.5% (Actual spare part costs for the Laby are only about 25% of the costs for
horizontal compressors, as there are no piston rings, no rider bands and no cylinder liners to replace)
of equipment cost for one time maintenance (MTTF basis). The maintenance costs are a strong

Gastech 2005

Lim 9

function of maintenance frequency, which is a reciprocated MTTF. Table 4 summarizes the life cycle
costs of maintenance and operation costs.
Table 4 Summary of Operation and Maintenance Costs
Description

(Unit: US$1,000)

Horizontal BOG
Compressors
27

Vertical BOG
Compressors
8

Yearly Allocated Utility and Consumables

3.7

2.9

Yearly Allocated Maintenance Part Costs

258

202

Yearly Allocated Labor Costs

129

88

TIC of BOG Compressors

31,725

31,725

Expense NPV

-62,615

-61,462

Probable Flaring/Venting BOG

Note: TIC stands for Total Installed Costs.

The electric costs for the compressor operation are not included in the Expense NPV because those
are assumed to be the same power consumption. Economic parameters used in economic evaluation
are as follows:

LNG terminal life time: 30 years

BOG compressor unit: 3 sets
Discount rate:
10%/y
Tax rate:
35%
Inflation rate:
2.5%/y
TIC factor:
2.25

The expense NPV of the vertical Compressors is $1.2 million less than that of the horizontal compressors.
This difference does not include difficultness of maintenance work for horizontal compressors against
vertical compressors. The horizontal compressors require more careful efforts in maintenance, which
generally takes more time (about 45% more hours). The actual maintenance records clearly show that
the vertical compressors with contactless labyrinth pistons required less maintenance hours and 20-30%
less spare parts costs.

CONCLUSIONS
1. The terminal has achieved zero emission in LNG regasification and has reduced its costs through
thermal integration with an adjacent power plant.
2. The main equipment reliability and availability have been estimated based on 18 years of actual
terminal operation records. The estimated terminal sendout availability is strongly affected by the
number of spare units or equipment reliability. Low reliability equipment reduces the terminal
sendout availability on stream production.
3. The company decided to replace the existing U type ORVs by the I type ORVs because the
U type ORV shows low reliability and would result in low availability.
4. The vertical compressors with contactless labyrinth pistons show less probable revenue losses
than horizontal compressors because of high availability.
5. The vertical compressors with contactless labyrinth pistons are highly reliable, resulting in less
operation and maintenance costs based on life cycle costs, compared to those of horizontal
compressors.

Gastech 2005

Lim 10

REFERENCES CITED
1. Cho, H., Shah, S.N., and Lim, K.H. (2000). Case History for Gas Re-Liquefaction System at the
Pyeongtaek LNG Terminal, South Korea. Proceedings of Gastech 2000.
2. Henley, E.J. and Kumamoto, H. (1981). Reliability Engineering and Risk Assessment. Prentice-Hall,
Englewood Cliffs, NJ.
3. Rao, S.S. (1992). Reliability-Based Design, McGraw Hill, New York.
4. Green, A.E. and Bourne. A.J. (1972): Reliability Technology, Wiley-Interscience, London.
5. Collins, S. (1995). Improving LNG Importation Reliability Proceedings of LNG XI, Birmingham, UK.
6. Vega, F., Hill, D.K., Collins, C. (1998). Plant Reliability Analysis in LNG Plants, Proceedings of LNG
12.
7. Sutton, I.S. (1992). Process Reliability and Risk Management, van Nostrand Reinhold.

Gastech 2005

Lim 11