cci lng guide

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


• Vent to Flare

Liquefaction 11


• Joule Thomson

LNG & NGL Storage and Landing 13


• 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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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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2

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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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2

The LNG Process

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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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The LNG Process

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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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The LNG Process

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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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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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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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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


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)



Recommended Specification for Steam Vent Valve

g Trim exit velocity head less than 70 psi (450 kpa)


g Noise level less than 85 dBA


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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 Trim exit velocity less than 75 ft/sec (23 m/sec)


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.


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


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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:[email protected]

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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