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LNG
A Guide to Severe Service Control Valve Applications in the LNG Process
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The LNG Process
Introduction: What is LNG?
When natural gas is cooled to a temperature of approximately –256 F
(–160 C) at atmospheric pressure it condenses to a liquid called liquefied
natural gas (LNG). One volume of this liquid takes up about 1/600th the
volume of natural gas at a stove burner tip. LNG weighs less than one-half of
water, actually about 45% as much. It is odorless, colorless, non-corrosive,
and non-toxic. When vaporized, it burns only in concentrations of 5% to
15% when mixed with air. Neither LNG nor its vapor can explode in an
unconfined environment. LNG is a safe and efficient way to transport gas
across long distances and bodies of water.
Composition
Natural gas is composed primarily of methane (typically, at least 90%),
but may also contain ethane, propane and heavier hydrocarbons. Small
quantities of nitrogen, oxygen, carbon dioxide, sulfur compounds, and water
may also be found in “pipeline” natural gas. The LNG process removes the
oxygen, carbon dioxide, sulfur compounds, and water. The process can also
be designed to purify the LNG to almost 100% methane.
Have There Been Any Serious LNG Accidents?
First, one must remember that LNG is a form of energy and must be respected
as such. Today LNG is transported and stored as safely as any other liquid
fuel. Before the storage of cryogenic liquids was fully understood, however,
there was a serious incident involving LNG in Cleveland, Ohio in 1944. This
incident virtually stopped all development of the LNG industry for 20 years.
The race to the Moon led to a much better understanding of cryogenics and
cryogenic storage with the expanded use of liquid hydrogen (–423 F /
–253 C) and liquid oxygen (–296 F / –182 C ). LNG technology grew from
NASA’s advancement.
In addition to Cleveland, there have been two other U.S. incidents sometimes
attributed to LNG. A construction accident on Staten Island in 1973 has been
cited by some parties as an “LNG accident” because the construction crew
was working inside an (empty, warm) LNG tank. In another case, the failure
of an electrical seal on an LNG pump in 1979 permitted gas (not LNG)
to enter an enclosed building. A spark of indeterminate origin caused the
building to explode. As a result of this incident, the electrical code has been
revised for the design of electrical seals used with all flammable fluids under
pressure.
THE LNG PROCESS
INTRODUCTION 2
A Brief History of LNG 3
PROCESS UNITS OF AN LNG PLANT 5
SEVERE SERVICE APPLICATIONS THROUGHOUT AN LNG PLANT
Gas Receiving 6
• Vent to Flare
• Separator Level Control
• Gas Intake/Regulator
Acid Gas Removal 7
• Rich Amine Letdown
• Lean Amine Recirculation
• Vent to Flare
Gas Compression 8
• Compressor Recycle
• Vent to Flare
Dehydration 9
• Gas Regulator
Hydrocarbon Separation Propane Cycle 10
• Compressor Recycle
• Vent to Flare
Liquefaction 11
• Compressor Recycle
• Joule Thomson
LNG & NGL Storage and Landing 13
• Compressor Recycle
• Joule Thomson
Utilities and Depressurizing System 14
• Fuel Gas Vent System
• Emergency Depressurizer
Steam Boiler 15
• BFW Recirculation
• BFW Regulator
• Steam Head Pressure Control
• Steam Vent
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A Brief History of LNG & NGL Production
Liquefied Natural Gas (LNG) production started in the 1960s when it became
clear that there was a need for long-distance overseas shipment of clean-
burning gas to be applied as a fuel for motor vehicles, or for residential and
industrial consumption.
Before that time, natural gas was primarily transported via long-distance gas-
transmission pipelines on the main continents. This transport is obviously
limited to cross-country pipelining.
Natural gas was introduced in the USA on a large scale just after W.W.II.
Europe started a few years later when large quantities of natural gas were
found in Western Europe, the North Sea and many other locations on that
continent. Major gas finds in Siberia led to long distance gas-transmission
systems all over Western Europe. Algerian gas was pipelined across the
Mediterranean Sea to Italy. Many developing countries like Japan, however,
could not benefit from those pipeline systems, as there was no local gas
source of significance in the area available to them.
The need for clean-burning energy became a high priority for Japan, so a
program was developed to ship natural gas in liquefied form from overseas
sources. Sonatrach in Algeria was the first operator to install a natural gas
liquefaction project in Arzew, which was called the Camel project. This
project was recently rejuvenated (early 1990s) and is now called GL4Z.
LNG from Arzew was primarily shipped to European countries and the USA.
The development and experience with the cryogenic gas tankers proved to
be very successful in moving large quantities of fuel from one continent to
another.
At the same time the major oil producers in the world started to consider
energy conservation. Gas was routinely flared before the early 1960s as a
useless by-product of oil production.
At this point in time, most of the associated gas (gas produced in conjunction
with crude oil) is being gathered and used for NGL and fuel-gas production.
The NGL, or Natural Gas Liquids, are exported as ethane, propane and
butane.
Ethane is primarily a feed-stock for the petrochemical industry, while
propane and butane are mainly used as LPG (liquefied petroleum gas) for
motor fuel and residential fuel in rural areas. Another important application
for LPG is its use as “peak-shaving” gas in natural gas distribution systems
during periods of high consumption.
The LNG Process
SEVERE SERVICE CONTROL VALVES
CCI Control Valves 16
DRAG® Velocity Control Technology 18
Severe Service Control ValveSpecifications for the LNG Process 20
Surge Control System 21
Control Valve Application:
Compressor Recycle/Anti-surge 22
Vent to Flare 23
Steam Vent 23
Amine Handling 24
Joule Thomson 24
Depressurizing 25
Steam Header Pressure Control 25
Separator Level Control 26
Gas Intake/Regulator 27
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The fuel-gas often supports a petrochemical industry in the country of
production. It is very suited for the production of chemicals like methanol
and a large number of chemicals based on that product. It is a key source
for ammonia production and nitric acid, which leads to the production of
artificial fertilizers and many related chemicals. As a last resort, the lean-gas
can be re-injected into the oil producing formation to maintain a sufficiently
high pressure in the oil field and support the future oil-production efficiently.
Surpluses of this gas, however, could theoretically be liquefied for export use.
New gas finds in the world are still quite abundant and can provide for a
new source of long-term supply. Firm long-term supply contracts are the
cornerstone of the LNG industry; the investments are significant and involve
not only the provider of the liquefied gas but also the customer and the
shipping companies. All have to make very large investments in equipment
that is only suitable for one type of product —LNG.
The key suppliers of liquefied natural gas are at this point in time: Sonatrach
in Algeria (North Africa); PT Arun in Sumatra, Indonesia; PT Badak Bontang
in Borneo, Indonesia; Brunei-Coldgas in Brunei; Petronas in Bintulu Serawak
East-Malaysia; Woodside, in the northwest shelf of Australia; Qatar and Ras
Laffan in the Middle East; Atlantic LNG in Trinidad; and Bonney Island in
Nigeria. Smaller suppliers of LNG are Adgas on Das-Island in Abu-Dhabi;
and Libya and Alaska. With demand for LNG increasing, more suppliers are
expected to come online. The primary consumers are Japan and South Korea,
who have their prime sources in Australia, Indonesia, and the Middle East.
France, Spain, Italy and Belgium import primarily from Algeria. Taiwan,
Italy, and the USA import small quantities from Algeria. Most of the LNG
production facilities are increasing production by adding additional trains.
The major contractors involved in LNG projects are KBR, Bechtel
International, Technip, Snamprogetti, Nippon-Kokan, Chiyoda and JGC.
New to this field are the local contractors in Malaysia and Indonesia like
PT Int. Karya Persada Tehnik (IKPT) that has been deeply involved in
expansions in Badak as the prime contractor. The major participants in LNG
projects are Royal Dutch Shell, Exxon Mobil, Phillips-Petroleum, British
Petroleum, Total, Mitsui Gas and Atlantic LNG.
Royal Dutch Shell is the key author of many design specifications for
cryogenic service that most operating companies adhere to.
On the receiving end in Japan there are Tokyo Gas and Electric, Hiroshima
Gas, Osaka Gas and Nippon Gas. In Taiwan the terminal is operated by CPC
Kaohsiung and in France the main operator of the terminals is Gaz de France.
In the USA, Colombia Gas and Boston Gas are the main operators.
The LNG Process
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Process Units of an LNG Plant
Most modern plants do not contain fired boilers for steam generation. LNG
facilities such as Bontang in Indonesia utilize fired boilers to generate steam
for driving the compressors.
The more modern plants contain waste heat recovery units associated with
the tailpipe exhaust system of the gas turbine. This low-pressure steam and
heated water is used in various process units where heat addition is required.
The LNG Process
10
H2S
stri
pp
er
CO
2st
rip
per
rich amineletdown
9
8
1
3 4
5 6
2
7
8
7
11
11
11
propaneprecooling
hp mp lp
lp
mp
hp
propaneprecooling
c3-3
c3-2
c3-1slug catcher
pro
pan
eta
nk mcr
tank
9
13
13
14
12 11
1211
mcr-2
mcr-1
production processing liquifaction transport
8
1. choke2. compressor anti-surge3. gas-to-flare blowdown4. line depressurizing5. flow pressure regulator6. import pressure - flow regulator7. level control8. depressurizing gas-to-flare9. lean amine pump recycle min. flow control10. export pressure - flow regulator11. compressor anti-surge12. hot gas bypass13. joule-thomson letdown14. boil-off-gas compressor anti-surge
FEED GAS SUPPLY
GAS RECEIVING
ACID GAS REMOVAL
GAS COMPRESSION
DEHYDRATION
HYDROCARBON PROCESSING
LIQUIFICATION
NGL TREATMENT
NGL STORAGE
SULFER SHIPPING TO CUSTOMERS
FRACTIONATIONUTILITIES
• STEAM• ELECTRICITY• WATER• NITROGEN• FIRE & GAS
SULFER RECOVERY
LNG STORAGE & LOADING
LNG SHIPPING TO CUSTOMERS
NGL SHIPPINGTO CUSTOMERS
Applications in LNG Processing
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Figure 1: Typical Gas Receiving System
CONDENSATE
PRODUCED WATERTO DISPOSAL
WELL GASCOOLER
VENT TOFLARE
FROM GAS GATHERING
P
L
SOUR GAS TO ACID GAS REMOVAL
CONDENSATESTRIPPER
WATERTO NGL
1
2
L
2
3SEPARATOR
COLD SEPARATOR
Gas Receiving
The gas receiving facility, often referred to as a slug catcher, receives the
product from the gathering station and consists of multiple sloped pipe
sections. The sour gas is taken from the top end of the sloped pipe to the
first separator. Condensed water and hydrocarbon is drained to the second
and third separators where the water is separated from the condensed
hydrocarbon.
It is not uncommon to find a small refrigeration unit to allow for additional
condensation of the water from the hydrocarbon condensate.
The separators, usually three or four in series, provide separation of the water
and hydrocarbon condensate. Sour gas is also pressure controlled from the
separators to gas treating.
The hydrocarbon condensate is usually routed to a condensate stripper where
the light components are stripped from the heavier products. The heavy ends
of the stripper (NGL) are routed to storage and sold as a separate product.
This product may enter a pipeline to an additional processing unit but is most
often loaded onto condensate or NGL tankers. The lighter hydrocarbon is
routed to the gas treating plant.
When starting a unit or train it is required to establish a reliable gas flow,
which is accomplished using a vent valve to flare. After sufficient flow is
established the flow is diverted from the flare to the treating area.
Table 1: Applications in Gas Receiving
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2
3
The LNG Process
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Acid Gas Removal
In some LNG facilities, an acid gas removal unit will be contained in each
liquefaction unit (LNG train). In other LNG facilities, a large acid gas
removal unit will feed multiple LNG trains.
Figure 2A represents an acid gas removal system feeding multiple LNG
trains, two of the three blocks would be in service with the other in standby.
Unit sparing philosophy will be such that no single unit failure will result
in shutdown of all LNG trains. This philosophy is often referred to as n + 1,
where n is the total requirement for full production.
The acid gas removal processes are typically Licensor packages.
The acid gas removal system removes the sour gas components – hydrogen
sulfide (H2S), carbon dioxide (CO2) and carbonyl sulfide (COS) – from the
raw feed gas. This operation prepares the feed gas for further processing.
The amine contactor process removes primarily H2S and COS. The Benfield
contactor process removes the CO2. The H2S rich sour gas from the amine
stripper acts as feedstock for the manufacturing of elemental sulfur. Figure 2
shows a typical treating unit.
Figure 2 is a simplified sketch of a treating block in Figure 2A. This sketch
shows one contactor and flash drum, but there will be several sets of this
equipment. Figure 2A illustrates a possible configuration that may be
required based on feed gas composition.
Each of the blocks in Figure 2A is a grouping of equipment similar to that in
Figure 2. Multiple sets of this equipment may be required based on the flow
through the facility and the amount of the unwanted component in the feed
gas composition.
Figure 2: Acid Gas Removal BlockFigure 2A: Acid Gas Removal System
FLASH DRUM
SOUR GAS TO SULFUR PLANT
VENT TO FLARE
CO
NTA
CTO
RS
ST
RIP
PE
R
SOUR GASFROM GASRECEIVING
(RAW FEED GAS)
1
3
L
2
SWEET GAS TOCOMPRESSION AREA
CO2
REMOVAL
CO2
REMOVAL
CO2
REMOVAL
H2SREMOVAL
H2SREMOVAL
H2SREMOVAL
FROM GASRECEIVING
TO GASCOMPRESSION
Table 2: Applications in Acid Gas Removal
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3
The LNG Process
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Gas Compression
Earlier LNG facilities (1960s and 1970s) are equipped with steam boilers and
use steam drivers for the compressors. These facilities typically use sea water
cooling for the process. In 1984/85 studies were performed by Shell and gas
turbines and air coolers were found to be more cost effective. The gas turbine
by this time period was very reliable and the cost of boilers and alloy piping
to route the steam to the compressor was more expensive than the use of gas
turbines.
Train capacities have increased over the past 15 to 20 years as have the size of
the gas turbines. The mid-1980s typically used frame 5 (~30 MW) machines.
It is not uncommon to find frame 6 (~50 MW) and even frame 7 (~70 MW)
machines used in today’s LNG facilities. The typical compressor discharge is
approximately 600 psi (41 barg).
Figure 3: Gas CompressionNote 1: Steam turbine driven compressor shown. Newer plant will generally be equipped with a gas turbine
VENT TO FLARE
1
COMPRESSOR RECYCLE
WATER
NOTE 1
TO LP STEAM SYSTEM
HP STEAMFROM STEAM
BOILERKO
KO
VENT TO FLARE
TO DEHYDRATION
WATER
600 PSI
AMBIENT TEMPERATURE
SWEET GASFROM ACID
GAS REMOVAL
2
2
CO
MP
RE
SS
OR
COOLER
Table 3: Applications in Gas Compression
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The LNG Process
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Figure 4: Dehydration
SH STEAM
COOLING
DR
YE
R IN
REG
EN
ER
AT
ION
C
YC
LE
HEATINGWET GAS FROM COMPRESSOR
REGENERATION VALVE
THROTTLING VALVE
COOLER
DRYERS IN DEHYDRATION CYCLE
KO
1
1
1
DRY GAS TOHYDROCARBON
PROCESSINGTRAINS
KO
COOLING
1
Table 4: Applications in Dehydration Dehydration
Figure 4 shows three dehydration vessels which are most often contained in
the typical LNG train. These vessels are often referred to as molecular sieves.
The figure shows two dryers in the normal gas drying mode and one dryer in
the regeneration mode.
The dryer vessels contain a catalyst which absorbs water. Typically, three
moisture analyzers are contained in the catalyst beds at 25%, 50%, and 75%
of bed height. These analyzers work on conductivity and indicate when that
portion of the bed is saturated with water.
Moisture concentrations at the outlet of the dehydration unit must be less
than 1 ppm to prevent hydrate in the chilling/liquefaction unit.
There are no severe service valve applications in the dehydration unit. Most
of the valves associated with a molecular sieve are traditionally rising stem
ball valves. This valve is preferred due to its ability to maintain Class VI
Shutoff for a long time period in this service. Catalyst fines are very abrasive
and damaging to valve seats and the rising stem ball valve works well in this
service.
After the dehydration unit, dry gas will typically flow through a main gas
regulator valve and then be split up and regulated into the gas lines that feed
each of the LNG trains.
The LNG Process
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Hydrocarbon Separation Propane Cycle
The propane compression section is intended to remove all or most of the
NGL (natural gas liquid) in the gas stream. Figure 5 shows a gas turbine
driving a 3-stage compressor. Most multiple train facilities use a single
compression circuit using a large GT and compressor.
Figure 5 shows 3 propane chillers, one for each compressor stage. Treated
dry gas is fed into the 1st stage chiller and is then routed through the chillers
to the propane compressors. The liquid feeds from the propane chillers are
shown being routed to an NGL stripper where the heavier of the hydrocarbon
can be separated and sold as a number of individual products or sold as a
combined NGL product. When gas reaches a temperature of approximately
-22 /-40 F(–30 /-40 C), it is routed from the 3rd stage chiller to the APCI
exchanger for liquefaction.
The feed to the Mixed Component Refrigerant (MCR) compressor, which is
typically a two-stage compressor, operates in much the same manner as both
the propane compressor using the associated chillers and knock out vessels.
It should be kept in mind that most of the control valves handling liquids
in the refrigeration circuits (not shown) are flashing. Vapor pressures in the
application will be near inlet pressure of the control valve. The main purpose
is cooling via flashing fluids in these units. Care must be taken to avoid under
sizing of the control valves in the refrigeration circuits of an LNG facility.
Figure 5: Hydrocarbon Separation Propane Cycle (1 Train)Note: Vent locations may differ
PROPANERETURN
FROM MCRKO
KO
PROPANETO MCR CHILLER
CHILLER3rd STAGE
~ 30/40°CNATURAL GAS
TO APCI EXCHANGE
2nd 1st
2
KO
1
3
PROP. SURGEDRUM
3 STAGE PROPANE COMPRESSOR
KO
HELPER MOTOR
PROPANE CONDENSOR
H.P.ECONOM
IZERL.P.
ECONOMIZER
CHILLER1st STAGE
CHILLER2nd STAGEDRY GAS FROM
DEHYDRATION
NGL TO STRIPPER
TO MCR CHILLER
3rd
VENT TOFLARE
VENT TOFLARE
1
GT
1
2
2VENT TO
FLARE
Table 5: Applications in Hydrocarbon Separation Propane Cycle
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Liquefaction
APCI Process
Figure 6 shows a typical LNG liquefaction unit based on the APCI process. This exchanger, which is one of the largest vessels (except for storage), contains multiple tube bundles which operate with a number of JT valves for the liquefaction process. The feed gas that has been chilled down to about -40 F (–40 C) is now practically all methane and ethane. In some cases there may be some nitrogen in the gas stream as well.
The refrigerant used in this process (MCR) is a refrigerant that will flash over a wide vapor range. This property makes the fluid extremely suitable for a staged chilling-process using a number of JT valves to liquefy larger amounts of LNG. At the exchanger outlet, the LNG flashes into the storage tank system. The flash gas that becomes available in this letdown process is fed via a compressor into the fuel gas system (not shown). This gas often contains a high percentage of inert gas and it is not economical to try to recycle this gas back in the system in order to extract more LNG.
The MCR refrigeration compressor package functions more or less the same as the propane system. The compressed MCR is liquefied partially in an aerial condenser. It flows from there as a mixed phase to a MCR chiller that uses low-pressure propane to chill the MCR to about -40 F (–40 C). From the MCR chiller an MCR-vapor and liquid stream pass through the main LNG exchanger tubing.
The vapor tubing is chilled with JT liquid in the top of the tower. The MCR liquid is flashing in the lower part of the unit, resulting in a product temperature at the discharge of the exchanger of around -220 F (–140 C). The MCR vapor returns to the MCR compressor for recompression.
Figure 6: Liquefaction MCR Cycle (1 Train)
KOKO
2nd1st
2
2
2
2
GT
1
MCRCHILLER
COOLER
MCR FROM PROPANE CYCLE-30°C
LNG PRODUCT-142°C 39 BAR
TO STORAGETANKS
RETURNTO PROPANE
COMPRESSOR
2 STAGE MCRCOMPRESSOR
FROM NATURAL GAS PROPANE
CHILLERS-30°C 45 BAR
MCR VAP-31°C
MCR VAP-31°C
MCR LIQ. -31°C
MAIN LNGEXCHANGER
1
Table 6: Applications in Liquefaction
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Liquefaction (continued)
PRICO Process
The PRICO (Poly Refrigerant Integrated Cycle Operation) was developed for Sonatrach at Skikda, Algeria. The PRICO process is the only LNG process with proven installations in a wide capacity range, from small peak shaving to large base load plants. The process is jointly owned by Pritchard and Kobe Steel LTD. The process is modular in nature and can be designed for a broad range of capabilities to match available gas turbine drivers. Even with the FRAME 7 machine, the capacity of the PRICO process is limited to about 1/3 of the APCI or Phillips process units presently being constructed.
The process uses only one refrigerant compressor feeding eight exchanger cold boxes. Partially cooled feed gas -87 F (-66 C) is withdrawn from the refrigerant exchanger at an intermediate point and is forwarded to the fractionation process where the heavier components are separated. The remaining gas returns from the fractionation process, reenters and then exits the exchanger cores as a liquid at -227 F (-144 C). The liquid -227 F (-144 C) is flashed in both a high and low pressure flash drum. The flash gas in these drums is recovered, recompressed and is sent to the fuel gas system with the liquid being sent to storage.
Phillips Process
The Phillips process, a more recent process developed between Phillips and Bechtel, is now being used at Atlantic LNG in Trinidad. This process, similar to the PRICO process, separates more of the heavier hydrocarbons than the APCI process prior to liquefaction.
A benefit of the Phillips process is its modular design making it suitable for large capacity trains.
Figure B: PRICO and Phillips LNG Process
FEED GAS SUPPLY
GAS RECEIVING
ACID GAS REMOVAL
GAS COMPRESSION
DEHYDRATION
HYDROCARBON PROCESSING
LIQUEFACTION
NGL TREATMENT
NGL STORAGE
SULFUR SHIPPING TO CUSTOMERS
FRACTIONATIONUTILITIES
• STEAM• ELECTRICITY• WATER• NITROGEN• FIRE & GAS
SULFUR RECOVERY
LNG STORAGE & LOADING
LNG SHIPPING TO CUSTOMERS
NGL SHIPPINGTO CUSTOMERS
PHILLIPS PROCESS— ADDITIONALHYDROCARBON
PROCESSING
PRICO PROCESS— ADDITIONALHYDROCARBON
PROCESSING
The LNG Process
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LNG & NGL Storage and Loading
Once the gas becomes a liquid, it flows into large insulated storage tanks.
“Boil-off” gas maintains temperature and pressure in the storage system.
Periodically the LNG is pumped into tankers through insulated pipelines.
A similar unloading process occurs when the tanker reaches its port of
destination.
The load-out line is equipped with multiple pumps, and it is not uncommon
to find as many as six load-out pumps. These pumps require approximately
80% of throughput to keep from overheating. Due to this and the large
capacity for load-out, flow control consists primarily of starting and stopping
the loading pumps. There are no severe service valves in storage and loading,
other than boil-off compressor recycle valves.
An LNG facility will contain NGL storage tanks and loading facilities which
are very similar to LNG storage and loading. Unlike the LNG, NGL is stored
at ambient temperature and similar pressures. There are no severe service
control valves in the NGL storage and loading system.
Figure 7: LNG & NGL Storage & Loading
Table 7: Applications in LNG & NGL Storage and Loading
ON/OFFVALVE
THROTTLINGVALVES
RECIRC.
1.2 BAR-160 CLNG
STORAGE TANKS
12
FROM LIQUEFACATION
LNG TANKER
The LNG Process
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Figure 8: Fuel Gas and Depressuring SystemVarious gas vents in a plant will relieve to the fuel gas system rather than to flare. As a result, there will be a fuel gas vent to flare, which will be a high-noise valve requiring tight shutoff.
Table 8: Applications in Utilities and Depressuring System
DEPRESSURIZING
VENT
PROCESS
VENT GASTO FLARE
FLARE
HEADER
PSIFUEL GASHEADER
MAKE-UP
15-20 PSI
P
1
2
PROCESS
Utilities
Grassroot LNG facilities contain various units for plant operation. These
units will include electric power generation, instrument and utility air,
nitrogen, and potable water production as a minimum. Most of these units
are packages supplied by Original Equipment Manufacturers (OEMs), except
for electric power generation.
There are two other units typically found in utilities: fuel gas system and fire
protection. The fuel gas system will have fuel gas vent to flare applications.
Depressuring System
The depressuring system in a plant is typically not a plant unit or a utility, but
nevertheless is worth mentioning.
These valves will vary in quantity in a facility, and will be sized for various
depressuring times. These valves are primarily used in fire situations where
hydrocarbon inventory is depressurized to the flare prior to the relief
valves opening. As such, most end-users and contractors will accept higher
noise levels under these conditions. Most often, 105 dBA is considered an
acceptable noise level with a minimum shutoff of Class V.
These valves are typically on-off and are sized to depressurize a given area of
the facility in 15 minutes to one hour. The solenoids on these valves may be
de-energize to trip. In some cases, dual energize-to-trip valves may be used
so that if either valve energizes, air will be vented off the valve actuator.
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Steam Boiler
Several boilers supplied by a packaged vendor may be used to supply steam to
an LNG train. In some facilities multiple boilers are connected to a common
header feeding one or more LNG trains.
Figure 9 shows a typical fired boiler operation. The figure shows three
steam headers with steam drivers being fed from the high pressure (HP)
and medium pressure (MP) headers. In the event a driver or compressor is
tripped, the steam consumption normally required for that service will be
let down to the next lower pressure header through a steam header pressure
control valve. Normally, the atmospheric steam will vent on the low-pressure
header, however it may vent on all three steam headers.
The fill condition of the steam drum makes the feedwater regulator and
recirculation valves severe service valves. The boiler feedwater pump
discharge will be approximately 30% higher than the HP header. Until
steam pressure is established in the headers, the pressure differential is high
resulting in severe cavitation in the regulator and recirculation valve. This
will cause trim erosion which may lead to loss of control valve operation.
Table 9: Applications in Steam Boiler
Figure 9: Typical Fired Boiler with Steam Drivers
DRUM
PROCESS
1
2
P
HP STEAM
4 STEAMVENT TO
ATMOSHPERE
MP STEAM
P
3
4
STEAMVENT TO
ATM
P
3
GAS
LP STEAM
4
STEAMVENT TO
ATM
WATER
BFW
COMPRESSEDGAS
PROCESS
PROCESS
GAS
COMPRESSEDGAS
1
2
3
4
The LNG Process
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CCI Control Valves
CCI valve technology has advanced along with the LNG industry:
g Fast-stroking requirements for compressor recycle have reached one
second or less using low cost, highly reliable pneumatic actuation — a
major trademark advantage of CCI control valves. Hydraulic actuation
which was used in the past is no longer favored due to high maintenance,
high cost and problems with reliability. LNG plants have begun to
retrofit their problematic hydraulic actuator systems with the reliable CCI
pneumatic actuator system.
g Repeatable, tight shutoff is achieved using CCI’s balance seal design
unique in the industry. The design clamps the seal in the bonnet,
providing superior performance when compared to other balance seal
designs that place a groove on the plug. The resulting benefit is that the
CCI balance seal remains effective at cryogenic temperatures as the seal
shrinks to form a better plug seal, while other seal designs shrink and
move away from the cage and reduce sealing.
For gas to flare valves, tight repeatable shutoff has ensured that product/
feedstock has not been unnecessarily flared. A minimum of Class V
Shutoff, and frequently Class VI Shutoff, has been applied successfully for
this application.
g CCI was a leader in the development of multi-stage noise standards.
Acceptable noise levels below 80 dBA have been met through CCI’s severe
service installations globally.
g CCI can assist in the selection of severe service valve applications to
ensure low ownership costs. CCI control valves can lower total installed
cost due to smaller pipe sizes, fewer parallel valve installations and high
valve rangeability. For example, in compressor recycle, a startup ball valve
may be in parallel to the recycle valve. However, CCI can combine these
application requirements into one compressor recycle application, saving
the client installation costs.
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Severe Service Control Valves
CCI Produced a 30” DRAG® Feed Gas Regulator Valve for Atlantic LNG in their RSM USA Factory
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Ensure High System Reliability and Efficiency
There are many aspects related to system reliability and efficiency:
g Maintaining plant efficiency
g Maintaining high plant throughput
g Ensuring high valve and equipment reliability
g Increasing plant availability.
All of these factors are consistent with each other.
CCI control valves ensure an excellent system that is reliable and efficient.
Compromising with an unreliable technical solution having a lower initial
cost will end up costing more money in the long run than CCI control valves.
Specify Severe Service Control Valve Applications
How can you meet the above purposes? By specifying the critical control
valves important to the project at an early stage. Severe service control valves
heavily impact the aspects of the LNG plant the owners are measuring.
The specifications on the following pages ensure that the above requirements
are met. Based on the ISA Practical Guide to Control Valves, they provide a
consistent method for ensuring system reliabilty and efficiency from the
severe service control valves.
What Control Valve Applications are Severe Service?
g Compressor Recycle
g Vent to Flare
g Joule Thomson
g Separator Level Control
g Rich Amine Letdown
g Gas Intake/Regulator
g Depressurizing
g High P Applications
g Steam Vent
g Turbine Bypass
g Steam Header Pressure Control
g Lean Amine Recirculation
g Fuel Gas Vent
g Emergency Depressurizing
Figure 10: 100D Valve
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Severe Service Control Valves
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DRAG® — Velocity Control Technology
How to Solve Severe Service Valve Problems
Uncontrolled flowing velocity—a control valve’s worst enemy.
Until the DRAG® valve was introduced, the design of control valves for
handling high-pressure drop liquids, gases, or steam had changed little.
Even today, despite widespread attempts to copy the CCI DRAG® solution,
other makers’ modified trim valves still flow process fluids through some
version of a single path (Figure 12) or multi-path orifice. In most cases, the
results are the same — problems.
Taming Velocity
Fortunately, the solution is found in basic engineering principles.
The fluid in a valve reaches its maximum velocity just slightly downstream of
the valve trim’s vena contracta or minimum flow area. This high velocity in a
single path or multi-path design can produce cavitation, erosion and abrasion
— all of which can quickly destroy the valve. Even before damaging the
valve, the symptoms of excessive noise, severe vibration, poor process control
and product degradation may be observed.
Interestingly, the high velocity is an unwanted side effect of pressure
reduction through the valve and is not treated as a design criteria in other
valves. Adding harder trim, pipe lagging or downstream chokes are costly
attempts to treat the symptoms rather than the real cause of the problem.
DRAG® velocity control valves from CCI solved the problem a generation
ago. DRAG® valves prevent the development of high fluid velocities at all
valve settings. At the same time, they satisfy the true purpose of a final
control element: to effectively control system pressure over the valve’s full
stroke. Here’s how the DRAG® valve accomplishes what the others can only
approach:
g The DRAG® trim divides flow into many parallel multi-path streams
(Figure 13). Each flow passage consists of a specific number of right
angle turns—a tortuous path where each turn reduces the pressure of
the flowing medium by more than one velocity head. By increasing the
number of turns, damaging velocity can be controlled while an increased
pressure drop across the control valve can be successfully handled.
V2
V1
V2
V2 V1
= 2gh
>
VenaContracta
V1 V2=
V1
V2
Figure 11: Uncontrolled Flowing Velocity—A Control Valve’s Worst Enemy
Figure 12: Single path
Figure 13: Multi-path
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Severe Service Control Valves
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g The number of turns, N, needed to dissipate the maximum expected
differential pressure across the trim is determined by limiting the velocity
to an acceptable level, then changing the equation in Figure 12 to a new
equation: V DRAG® element = √2gh/N and solving for N.
Applying this principle to the DRAG® valve’s disk stack and plug as shown
in Figure 15 means that velocity is fully controlled in each passage on
every disk in the stack and that the valve can operate at a controlled,
predetermined velocity over its full service range.
g In the DRAG® trim, the resistance, number and area of the individual flow
passages is custom matched to the specific application and exit velocities
are kept low to eliminate cavitation of liquids and erosion, vibration and
noise in gas service.
V1 V2=
V1
V2
V2 = 2gh
V1 V2=
V1
V2
V2 = 2gh/N
N Turns
Figure 15: Pressure-drop from right-angle turns
Figure 16: Number of turns depends on the differential pressure
Figure 17: DRAG® disk
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Severe Service Control Valves
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Severe Service Control Valves
Surge Control Systems
A valve that does not stroke fast enough will cause a machine to surge. This
surge may be sufficient to shut down the compressor. A compressor may trip
due to surge protection in the compressor controller or axial shaft movement
in the machinery protection package (typically 25 µm to 75 µm [or 0.001 to
0.003] axial displacement). A compressor trip will cause loss of production
for several hours. Of equal consequence, each trip increases the required main-
tenance and shortens the life of the compressor.
Resolution/Closing Speed
In the past CCI has stated that closing speeds of 1.5 times the opening speed is
acceptable. The point should be made that although acceptable, it is not pre-
ferred. Most vendors will provide even slower closing speeds as this helps the
valve attain set point with fewer oscillations about the set point value. Oscilla-
tions around the set point should be avoided.
Surge Protection
In order to protect the compressor, a surge protection system consisting of
a measurement device, a control device and a recycle valve is provided. The
key function of the surge protection system is to respond quickly to a process
upset and avoid sending the compressor into surge by recycling the process
fluid.
Measurement Most transmitters used in surge control have a 300 ms rise
time from 0 – 100%. It is fair to say that at least 1/3 of this
time is required for the measuring device to change values
detected by the controller.
Control Device A CCC controller reads all inputs in 10–15 ms. The controllers
output is averaged for three cycles, or approximately 40 ms
before a signal is sent to the valve.
Valve Approximately 150 ms after a process upset that can result
in surge (100 ms for sensor + 40 ms for controller to process
signals), the recycle valve will receive the signal to open.
Stroking speed for the recycle valve is typically specified as <2 seconds,
more than ten times the sensing and processing speed of the transmitter
and controller. However, a two second valve stroke speed is a value most
manufacturer find difficult to achieve without unstable operation. As a
compromise, they propose a three-to-five second stroke speed. Unfortunately,
this is not an acceptable compromise. Each additional (1) sec in stroke speed
can expose the compressor to 2-3 additional surges which are detrimental to
the compressor.
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Specification - Surge Control System
Protection of Major Equipment Components
The compressor is one of the most expensive pieces of equipment for an
LNG plant. A compressor can go into surge if the flow drops below 80% of
the rated flow. A well specified severe service control valve is required to
respond and open within one second to protect the compressor from surge
flow. Coupled with a good control system, the valve will provide a long life
for the compressor. This has been proven at many installations in LNG plants
around the world.
Increase Compressor Efficiency
The compressor will have the highest efficiency when the compressor recycle
valves are specified with repeatable tight shutoff. It is well known that a
major part of the cost of the compressor is the energy cost to run it over
a period of time. When a valve is leaking, the compressor requires more
energy to meet the throughput. This leaking inefficiency can far outweigh the
costs of the valve over time, in some cases, even the cost of the compressor.
Minimize Loss of Product/Feedstock
A well specified severe service control valve should not leak. If a gas vent-to-
flare valve is leaking, valuable product is going to flare where it will be wasted.
Repeatable, tight shutoff is absolutely necessary to ensure that product/
feedstock will go where it belongs, which is to the customer, and not flared.
Eliminate Unwanted Noise and Vibration
High fluid velocities through the pressure letdown process will create
aerodynamic noise. A well specified control valve will control the fluid
velocities through the letdown path to an acceptable level and will ensure
that noise and vibration is not created in the first place. Noise is not hidden—
instead it is not created. Vibration is limited.
This source treatment takes the entire pressure drop through one element
and attenuates the noise to the specified level without the use of downstream
devices, or silencers.
Control Valve Technical Specification
Control ValveTechnical Specification
“Control Valves – Practical Guides for Measurementand Control” edited by Guy Borden, Jr. and Paul G.Friedmann, 1998 edition published by ISA.
Reference:
Control Valve Specifications Based on ISA.
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Table 10: Compressor Recycle/Anti-surge ValvesEnsures compressor will not surge by recycling gas from discharge to suction side of compressor when flow drops below 80% of compressor capacity.
Recommended Specification for Compressor Recycle/Anti-surge Valve
g Stroke speed less than 1 second in both open and close directions
g A maximum of one overshoot, not to exceed 1% of travel
g Leakage Class VI (minimum Class V)
g Noise level less than 85 dBA at 1 meter from valve
g Resolution less than 1%
g Trim exit velocity head less than 70 psi
Severe Service Control Valves
Control Valve Application: Compressor Recycle /Anti-surge
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Control Valve Application: Steam Vent Table 12: Steam Vent Valve: Steam to atmosphere during startup, shutdown, and steam turbine load rejection
Control Valve Application: Vent to Flare Table 11: Vent Valve to Flare: Vents Gas to Flare During Startup, Shutdown, or Load Rejection
Recommended Specification for Vent to Flare Valve
g Trim exit velocity head less than 70 psi (450 kpa)
g Noise level less than 85 dBA at 1 meter from valve
Severe Service Control Valves
Recommended Specification for Steam Vent Valve
g Trim exit velocity head less than 70 psi (450 kpa)
g Leakage Class VI (minimum Class V)
g Noise level less than 85 dBA
g Leakage Class VI (minimum Class V)
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Control Valve Application: Amine Handling
Table 13: Amine Letdown Valves: Rich Amine Letdown or Lean Amine Pump Recirculation
Table 14: Joule Thomson (JT) Valves: Allows Compressed Gas to Expand for Refrigeration
Recommended Specification for Vent Valve to Flare
g Noise level less than 85 dBA at 1 meter from valve
g Trim exit velocity less than 75 ft/sec (23 m/sec)
Severe Service Control Valves
Control Valve Application: Joule Thomson
Recommended Specification for Joule Thomson Valve
g Trim exit velocity less than 75 ft/sec (23 m/sec)
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Control Valve Application: Steam Header Pressure Control
Table 16: Steam Header Pressure Control Valves: Controls Pressure in the Steam Header
Recommended Specification for Depressurizing Valves
g Noise level less than 105 dBA at 1 meter from valveg Trim exit velocity head less than 300 psi (2060 kpa)g Leakage Class VI (minimum Class V)g Type approval for cryogenics
Control Valve Application: DepressurizingTable 15: Depressurizing Valves: Emergency Application Dumping Hydrocarbon Inventory to Flare.
Severe Service Control Valves
Recommended Specification for the Turbine Bypass Valve
g Noise level below 85 dBA at 1 meter from valveg Trim exit velocity head below 70 psi (450 kpa)g Shutoff Class V
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Recommended Specification for the Separator Level Control Valve
g Trim exit velocity less than 75 ft/sec (23 m/s)g Large passages sizes greater than 0.18-in. (5-mm) in widthg Noise level less than 85dBA at 1 meter from valveg Erosion resistant hard trim material
Control Valve Application: Separator Level Control
Table 17: Separator Level Control Valves: Maintains Fluid Level in a Separator
Severe Service Control Valves
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Severe Service Control Valves
Recommended Specification for the Gas Regulator Valve
g Rangeability >100:1g Noise level less than 85dBA at 1 meter from valveg Trim exit velocity head less than 70 psi (450 kpa)
Control Valve Application: Gas Intake/Regulator
Table 18: Gas Regulator Valves: Controls Feed Gas Flow Rate
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CCI World Headquarters—CaliforniaTelephone: (949) 858-1877Fax: (949) 858-187822591 Avenida EmpresaRancho Santa Margarita,California 92688 USA
CCI Switzerland formerly Sulzer ThermtecTelephone: 41 52 262 11 66Fax: 41 52 262 01 65Hegifeldstrasse 10, P.O. Box 65CH-8408 WinterthurSwitzerland
CCI KoreaTelephone: 82 31 985 9430Fax: 82 31 985 055226-17, Pungmu-DongKimpo City, Kyunggi-Do 415-070South Korea
DRAG is a registered trademark of CCI.©2002 CCI 429 5/02 10K
Throughout the world, companies rely on CCI to solve their severe service control valve problems. CCI has provided custom solutions for these and other industry applications for more than 40 years.
Contact us at:info@ccivalve.com
Visit us online at:www.ccivalve.com
CCI JapanTelephone: 81 726 41 7197Fax: 81 726 41 7198194-2, ShukunoshoIbaraki-City, Osaka 567-0051Japan
CCI Sweden (BTG Valves)Telephone: 46 533 689 600Fax: 46 533 689 601Box 603SE-661 29 SäffleSweden
CCI Austriaformerly Spectris Components GmbHTelephone: 43 1 869 27 40 Fax: 43 1 865 36 03Carlbergergasse 38/Pf.191233 ViennaAustria
CCI ItalyTelephone: 39 035 29289 Fax: 39 035 2928246Via G. Pascoli 10 A-B24020 Gorle, BergamoItaly
Sales and service locations worldwide.
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