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ARAB ACADEMY FOR SCIENCE, TECHNOLOGY ANDMARITIME TRANSPORT
College of Maritime Transport
Marine Engineering Technology Department
B.Tech. Final Report
LNG CHAIN
AhmadZerba
Presented by:
Ebrahem shalesh Mohamad Slwaya
Johny EbrahemHaretha Khalil Ahmad Araki
Supervisors by:
Eng: Nassr Abdalrhma Eng: Khaled Senary
July-2010
ABSTRACT
atural gas is becoming one of the most important resources of with its share in the world
consumption expected to increase as much as 50% by 2020. Currently, natural gas is transported
to the markets by pipelines and as liquefied natural gas (LNG). Transporting the natural gas by
pipelines is convenient and economical for onshore purpose. For offshore transport of natural
gas, pipelines become challenging as the water depth and the transporting distance increase.
LNG, an effective mean of transporting gas for long distances overseas, constitutes 25% of the
world gas movement. But LNG projects require large investments along with substantial natural
gas reserves and are economically viable for distances longer than 3000 miles.
In this report we will discuss the life time of natural gas from extracting fields and the treatment
operations then the liquefaction process requires the natural gas to be cooled using various
methods of cryogenic processes for easier and safer storage. After liquefaction LNG most be
transported by using different types of LNG carrier with taking in consideration the boiling of
point and how we can overcome this point. When LNG carrier reaches to its final destination it's
time to regasificat the LNG into natural gas by one of the regasification methods. And now
natural gas within pipe lines ready to use by us.
LNG CHAIN I
Acknow ledgement
First of all thanks God for everything and for helping us to complete this research. Then we
would like to express our sincere gratitude to engineer Nassr Abalrhman and engineer: Khaled
Senary for the opportunity to explore the field of LNG. Their encouragement, guidance, and
support were valuable in our work. They were always there to listen and to give advices. They
are responsible for involving me in this project in the first place. They showed us different ways
to approach a research problem and the need to be persistent to accomplish any goal. And special
thanks for the head of maritime engineering department engineer: Adel Abdalazez
And we would like to thank our families, we present our successful to them and we hope to begood as they always wanted us to be.
LNG II
Contents
Abstract. IAcknowledgement. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IIList of figures. III
CHAPTER 1: INTRODUCTION
1.1What is natural gas?...................................................................................................... 11.2 What is Liquefied natural gas (LNG)?......................................................................... 1
CHAPTER 2: Natural Gas Production2.1 Introduction 4
2.2 Natural gas is nonrenewable 6
2.3 History of Natural Gas 6
2.4 Methane.......................................................................................... 7
2.5 Oil and Gas Traps................................................................................ 7
2.6 Producing Natural Gas......................................................... 11
2.6.1 Drilling for natural gas 12
2.6.2 Horizontal Drilling..................................................... 14
2.6.3 Reservoir Recovery............. 15
2.6.4 Drilling the well... 15
2.6.5 Gas injection... 16
CHAPTER 3: Processing & Liquefaction Techniques
3.1 Natural gas processing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
3.1.1 Introduction ,............................... 18
3.1.2 Acid gases, water, mercury and other components removal.. 19
3.1.3 Process Description of an Integrated NGL and LNG plant. 21
3.2 ~~llLJFli\~ (}~S ~I(2LJIlF~<=llI()~...................................................... ... 24
3.2.1 Introduction.............................. 24
3.2.2 ~~(} Liquefaction Techniques 28
2. Prico Process... ... ... ... ... ... ... ... 283. Conocol'hillips Simple Cascade 294. Dual Mixed Refrigerants 325. Mixed Fluid Cascade Process (LINDE)... . 346. APCI... 36
CHAPTER 4: LNG TRANSPORTATION
4.11lFli\~SP()RllW(} BY PIPE~rnS 39
4.1.1 Pipeline Components. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
J Pipes 39
2 Compressor Stations 40
3 Metering Stations ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... .... 40
4 Valves 40
5 Control Stations and SCADA Systems 40
6 Pipeline Inspections and Safety ,. 4J
4.2 ~~(} Carriers 42
4.3 ~~(} Tank types and their classification 45
4.3.1 Membrane Tanks 45
1- NO 96Membrane System 452- MARK III Membrane System 463- CSJ Membrane Systemfor LNG Integrated Tanks 48
4.3.2 Spherical Tanks 50
CHAPTER 5: Boil-Off GAS
5.1 BOG treatment 53
5.1.1 Avoid boil-off... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .... . . . . . . . . . . . . . . .. 54
5.1.2 Re-Iiquefaction.. , . .. . .. .. . 54
5.1.2.1- Total Reliquefaction 55
5.1.2.2- Self-sustained Reliquefaction 56
5.1.2.3- Partial Reliquefaction 57
5.1.3 LNG Propulsion Systems 58
5.1.3.1 Steam Turbines 58
5.1.3.2 Gas Turbines 60
5.1.3.3 Dual Fuel Diesel Engines 62
CHAPTER 6: RE-GASIFICATINO
6.1 Introduction 69
6.2 Best Available Commercial Technologies 69
6.3 VAPORIZATION SYSTEMS 71
6.3.1 Intermediate Fluid Vaporizers 71
6.3.2 Ambient Air Vaporizers 74
6.3.3 Shell and Tube Vaporizers 76
6.3.4 Open Rack Vaporizers 78
6.3.5 Submerged Combustion Vaporizers 80
6.3.6 Lower Emission LNG Vaporization Process 83
CHAPTER 7: CONCLUSION
References...................................................................................... 87
(
List of Figures
Figure (1-1) LNG chain 2
Figure (1-2) growth in LNG demand 3
Figure (2-1) oil & natural gas formation......... 5
Figure (2-2) oil & natural gas formation 5
Figure (2-3) Methane formula 7
Figure (2-4) structural trap 8
Figure (2-5) structural trap... 9
Figure (2-6) drilling into sandstone 10
Figure (2-7) types of traps.......................................................................... 11
Figure (2-8) Problems due to faulting 12
Figure (2-9) well location .. .. 13
Figure (2-10) benifts ofhorizental drilling 14
Figure (2-11, natural gas well 16
Figure (2-12) using nitrogen injection in natural gas production 17
Figure (3-1) natural gas processing unit 18
Figure (3-2)-Block diagram for typical NGL extraction plant 20
Figure (3-3)-Block diagram for typical LNG plant 21
Figure (3-4)-Block diagram showing the integrated NGL and LNG process 22
Figure (3-5) TYPES OF HEAT EXCHANGERS. .. .. . 25
LNG III
Figure (3-6) a basic refrigeration cycle 26
Figure (3-7) pure& mixed cooling curve 26
Figure (3-8) Prico Process 28
Figure (3-9) ConocoPhillips Simple Cascade 30
Figure (3-10) ConocoPhillips Simple Cascade 31
Figure (3-11) Dual Mixed Refrigerants 32
Figure (3-12) Parallel Mixed Refrigerant (PMR) process 34
Figure (3-13) Mixed Fluid Cascade Process (LINDE) 35
Figure (3-14) Air Products and Chemicals Inc 37
Figure (4-1) the pig 41
Figure (4-2) historical LNG fleet growth 43
Figure (4-3) Moss sphere design 43
Figure (4-4) Membrane design...... . . .. 44-,
Figure (4-5) types & number of carriers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 44
Figure (4-6) NO 96 Membrane System 46
Figure (4-7) MARK IIIMembrane System 47
Figure (4-8) CSI Membrane System for LNG Integrated Tanks 49
Figure (4-9) spherical tank 51
Figure (5-1) BOG Treatment 53
Figure (5-2) Total Reliquefaction 56
LNG IV
Figure (5-3) Self-sustained Reliquefaction 57
Figure (5-4) Partial Reliquefaction 58
Figure (5-5) dual engine system 62
Figure (5-6) Multifuel Engine 63
Figure (5-7) comparison between dual & diesel engines 65
Figure (5-8) Schematic layout of control arrangement for Dual-fuel engines 66
Figure (6-1) vaporization systems 70
Figure (6- 2) Intermediate Fluid Vaporizers 72
Figure (6-3) TOW UNITS RUNNING ONE DEFROST 75
Figure (6-4) unit structure 75
Figure (6-5) Shell and Tube Vaporizers.......................................................... 76
Figure (6-6) Double Tube Bundle.................................... 77
Figure (6-7) Open Rack Vaporizers 79
Figure (6-8) stematic drawing of open rack vaporizer 79
Figure (6-9YSubmerged Combustion Vaporizers 82
Figure (6-10) Lower Emission LNG Vaporization Process 83
Figure (6-11) the vertical design of vaporizer 85
LNG VI
-
(
INTRODUCTION
1.1 What is natural gas?
Natural gas comes from reservoirs beneath the earth's surface. Sometimes it occurs naturally and
is produced by itself (non-associated gas), sometimes it comes to the surface with crude oil
(associated gas), and sometimes it is produced constantly such as in landfill gas. Natural gas is a
fossil fuel, meaning that it is derived from organic material deposited and buried in the earth
millions of years ago. Other fossil fuels are coal and crude oil. Together crude oil and gas
constitute a type of fossil fuel known as "hydrocarbons" because the molecules in these fuels are
combinations of hydrogen and carbon atoms. The main component of natural gas is methane.
Methane is composed of one carbon and four hydrogen atoms (CH4). When natural gas is
produced from the earth, it includes many other molecules, like ethane (used for manufacturing),
propane (which we commonly use for bbq's) and butane (used in lighters). We can find natural
gas around the world by exploring for it in the earth's crust and then drilling wells to produce it.
Natural gas can be transported over long distances in pipelines or as LNG transported in ships
across oceans. Natural gas can be stored until needed in underground caverns and reservoirs or as
LNG in atmospheric tanks.
1.2 What is Liquefied natural gas (LNG)?
Liquefied natural gas (LNG) is natural gas that has been cooled to the point that it condenses to a
liquid, which occurs at a temperature of approximately -256 F or 161 C at atmospheric pressure.
Liquefaction reduces the volume of gas by approximately 600 times thus making it more
economical to store natural gas where other forms of storage do not exist, and to transport gas
over long distances for which pipelines are too expensive or for which other constraints exist.
Liquefaction makes it possible to move natural gas between continents in specially designed
ships. Thus LNG technology makes natural gas available throughout the world.
LNGCAlN 1
To make LNG available for use, energy companies must invest in a number of different
operations that are highly linked and dependent upon one another.
The major stages of the LNG value chain excluding pipeline operations between the stages
consist of the following.
Exploration to find natural gas in the earth's crust and production of the gas foe delivery to gas
users. Most, but not all, of the time natural gas is discovered during the search for oil.
Liquefaction to convert natural gas into a liquid state so that it can be transported in ships.
Shipping the LNG in special purpose vessels.
Storage of LNG in specially made tanks, and regasification to convert the LNG from the liquid
phase to the gaseous phase, ready to be moved to the final destination through the natural gas
pipeline system.
Gal Aeld l~uefaction Plant LNGStorage Tank LNG Tanker LNG Storage Tank Vaporizers To Pipeline SYltem
PRODUCING RfGION CON~UMING R~GION
FIGUR (1-1) LNG chain
Consumption of natural gas has been increasing rapidly making it one of the most important
energy resources in the world. In 2002 the consumption of natural gas was 89.5 Tcf (Trillion
cubic feet) worldwide, an increase of about 3% since 2001. During the last decade the
consumption of natural gas increased by almost 25%1. By 2020 natural gas is predicted to
increase its world energy share to as much as 50% from the present of 22%2. Much of the
increased consumption is seen to be in the electric power generation.
LNG CAIN 2
6000
5000
"-t'O 4000(U~-CL>0-..-CL>Q..)
3000-<..s~=<...:>=== 2000ex:;
1000
-----~~~~~~---------~
Growth in LNG Demand
• Others.USA
Turkey• Taiwan
Belgium• S. Korea
Italy• Spain
France.Japan
o ~~-~-~-+-~-~-+-~-+-~-~-+-~--r-+-~~1970- ---1980 ----1990 --------------------1995- -------------------2000- ---2003
FIGUR (1-2) growth in LNG demand
The lower carbon emissions compared to oil and coal along with other reduced emissions of
nitrogen oxides and particulates make gas environmentally attractive. More important is that the
cost of power generation using natural gas is 50% less than using coal. These factors have led to
future projections of increase of annual consumption in power generation from 5.23 Tcf in 2000
to 9.39 Tcf in 2020.
LNG CAIN 3
••
-
2.1 Introduction
atural gas is generally considered a nonrenewable fossil fuel.(There are some renewable
sources of methane, the main ingredient in natural gas, also discussed in this Jactsheet.)Natural
gas is considered a fossil fuel because most scientists believe that natural gas was formed from
the remains of tiny sea animals and plants that died 200-400 million years ago.
When these tiny sea animals and plants died, they sank to the bottom of the oceans where they
were buried by layers of sediment that turned into rock. Over the years, the layers of sedimentary
rock became thousands of feet thick, subjecting the energy-rich plant and animal remains to
enormous pressure. Most scientists believe that the pressure, combined with the heat of the earth,
changed this organic mixture into petroleum and natural gas. Eventually, concentrations of
natural gas became trapped in the rock layers like wet sponge traps water.
Raw natural gas is a mixture of different gases. The main ingredient is methane, a natural.
compound that is formed whenever plant and animal matter decays. By itself, methane is
odorless, colorless, and tasteless. As a safety measure, natural gas companies add a chemical
odorant called mercaptan (it smells like rotten eggs) so escaping gas can be detected. Natural gas
should not be confused with gasoline, which is made from petroleum.
LNG CAIN 4
OIL & NATURAL GAS FORMATION
'" /OS:_~A.ti· ./300·400 million years ago
Tiny sea plants and animals diedand were buried on the ocean floor,Over time, they were covered by
layers of sedimentary rock.
Over millions at years, the remainswere buried deeper and deeper.The enormous heat and pressureturned them into oil and gas.
Figure (2-1) oil & natural gas formation
Today, we drill down through layersof sedimentary rock to reach
the rock formations that containoil and gas deposits.
Figure (2-2) oil & natural gas formation
LNG CAIN 5
2.2 Natural gas is nonrenewable.
The natural gas we use today took millions of years to form. That's why we call it a
nonrenewable energy source. We can't make more in a short time. Someday, most of the natural
gas we can reach by drilling underground will be gone. Garbage sometimes produces methane,
the main gas in natural gas, as it rots. Methane from rotting garbage is a renewable energy
source because there will always be garbage.
2.3 History of Natural Gas
The ancient peoples of Greece, Persia, and India discovered natural gas many centuries ago. The.
people were mystified by the burning springs created when natural gas seeping from cracks in
the ground was ignited by lightning. They sometimes built temples around these eternal flames
so they could worship the mysterious fire.
About 2,500 years ago, the Chinese recognized that natural gas could be put to work. The
Chinese piped the gas from shallow wells and burned it under large pans to evaporate seawater
for the salt.
atural gas was first used in America in 1816 to illuminate the streets of Baltimore with gas
lamps. Lamplighters walked the streets at dusk to light the lamps.
Soon after, in 1821, William Hart dug the first successful American natural gas well in Fredonia,
ew York. His well was 27 feet deep, quite shallow compared to today's wells. The Fredonia
Gas Light Company opened its doors in 1858 as the nation's first natural gas company.
By 1900, natural gas had been discovered in 17 states. In the past 40 years, the use of natural gas
has grown. Today, natural gas accounts for 21.6 percent of the energy we use.
LNG CAIN 6
2.4 Methane
Figure (2-3) Methane formula
Methane is a chemical compound with the chemical formula CH4. It is the simplest alkane, and
the principal component of natural gas. Methane's bond angles are 109.5 degrees. Burning
methane in the presence of oxygen produces carbon dioxide and water. The relative abundance
of methane makes it an attractive fuel .
2.5 Oil and Gas Traps
When thousands of feet of shale have piled up over millions of years, and the animal bodies are
buried very deep (more than two miles down), an amazing thing happens. The heat from deep
inside the earth "cooks" the animals, turning their bodies into what we call hydrocarbons oil
and natural gas. At first, the oil and gas only exist between the shale particles as extremely tiny
blobs. Then, the intense pressure of the earth squeezes the oil and gas out of the shale, and the
oil and gas fluids
LNG CAIN 7
move sideways many, many miles. On their way, they may meet up with other traveling oil
fluids.
Finally, the oil and gas may become "trapped" in a rock formation like sandstone or
limestone ....a trap they can't escape! The oil and gas stay there, under tremendous pressure, until
the PG comes to get it. After they are formed, oil and gas must be "trapped" in order to remain in
place until it can be found. Without a trap, the PG has no place to drill. All oil and gas deposits
are held in some sort of trap.
There are two basic types of traps:
Structural traps hold oil and gas because the earth has been bent and deformed in some way. The
trap may be a simple dome (or big bump), just a "crease" in the rocks, or it may be a more
complex fault trap like the one shown at the right as shown in figure (2-4).
IMPERViOUSSHALE
Fault
WATERA structurallrap. Faulting in thecaused vertical movement of the rock layers.Gas and oil cannot pass through the faultboundarv. and they are trapped.
Figure (2-4) structural trap
LNG CAIN 8
Stratigraphic traps: are depositional in nature. This means they are formed in place, usually bya porous sandstone or limestone becoming enclosed in shale. The shale keeps the oil and gasfrom escaping the trap, as it is generally very difficult for fluids (either oil or gas) to migratethrough hales as shown in figure (2-5).
-~~~~;::~~:-.::--.:..:===::;:::..~~~~~.~~~:;~~;- .':
~---:, ",
~, -A stratigraphic trap. Oil is trapped in two sandstoneswhich are surrounded by shale. The shale prevents theoil from escaping.
Figure (2-5) structural trap
The hole in the figure (2-6) has been drilled into sandstone that was deposited in a stream bed.
This type of sandstone follows a winding path, and can be hard to hit with a drill bit! This type of
sandstone is usually enclosed in shale, making this a stratigraphic trap,
LNG CA1N 9
.,."<> .:::;'~:A-~ell is drilled into a sandstone••. deposited by an ancient stream.
Figure (2-6) drilling into sandstone
Here are four traps in figure (2-7). The anticline is a structural type of trap, as is the fault trap
and the salt dome trap.
The stratigraphic trap shown was formed when rock layers at the bottom were tilted, then eroded
flat. Then more layers were formed horizontally on top of the tilted ones. The oil moved up
through the tilted porous rock and was trapped underneath the horizontal, nonporous rocks.
LNG CAIN 10
!l Ant~lill9
,..,
i....
Figure (2-7) types of traps
2.6 Producing Natural Gas
· Production beings after the well is drilled .
· Production is the operation that:
a- Brings hydrocarbons to the surface .
b- Prepares them for processing .
• The mixture of gas and water from the well is separated on the surface.
The water is disposed off. And the gas is treated, measured, and tested
LNG CAIN 11
2.6.1 Drilling for natural gas
Natural gas can be hard to find since it is usually trapped in porous rocks deep underground.
Geologists use many methods to find natural gas deposits. They may look at surface rocks to find
clues about underground formations. They may set off small explosions or drop heavy weights
on the earth's surface and record the sound waves as they bounce back from the sedimentary rock
layers underground. They also may measure the gravitational pull of rock masses deep within the
earth. If test results are promising, the scientists may recommend drilling to find the natural gas
deposits. Natural gas wells average 6,100 feet deep and can cost hundreds of dollars per foot to
drill, so it's important to choose sites carefully.
YES !!What Happened tothe Oil Reservoir??
Faulting causesproblems I
D. Srrilh
Finally, structures in the earth can give the PG many challenges. As shown in figure (2-8). The
first well on the left represents a nice oil and gas-bearing rock.. YES! We have a great well,
Figure (2-8) Problems due to faulting
LNG CAIN 12
producing lots of and gas! Then the second well to the east (right) of the first one. What
happened to that hole?
The oil reservoir has been split in two by the fault, which is nothing but a place in the earth
where rock layers break in two. The arrows on the figure (2-8) show that the rocks moved down
on the left side of the fault and up on the right side of the fault. This created a gap in the gas
field right where the second well is drilled! So it is dry well.
Also the well may fmd a producing reservoir very near the surface. Or we might drill into a
reservoir that has been depleted (all the oil and gas removed) by another well. There may be a
new infill reservoir between two wells that could be developed with a third well. Or one that
was incompletely drained. Maybe if we drill a little deeper we might hit a deeper pool
reservoir! we might be able to back up and produce a bypassed compartment as shown in
h:;1.'~<;,(2-9). The Petroleum Geologist has to think of all these things when planning a new well!
n,...1"1~I••.rIC<ampol'imen-,
_ Oep/e e:d'i....ompol1rrll~n<,
II
.e-w Irrill Rese •.•••cir
U 0pped Re5.e'l"'oirCOmpul'i nenl
Figure (2-9) well location
LNG CAIN 13
2.6.2 Horizontal Drilling
While limited production has occurred in the Marcellus Shale to date, drillers in the Barnett
Shale of some countries have demonstrated that new technology in the form of horizontal drilling
and hydraulic fracturing of the shale (fracturing through the use of high pressure liquids) has
helped overcome the flow capacity problem of gas shales. Horizontal drilling is a technique used
to expose long sections of the reservoir rock to the wellbore. While a conventional vertical well
penetrates and exposes only the thickness of a pay zone (e.g., 50 to 300 feet in the Marcellus
shale), horizontal drilling can expose over a mile of reservoir rock for production by steering a
drill bit to follow the pay zone. Hydraulic fracture stimulation creates additional flow paths to the
well. In this process, fluid is pumped into the formation at high enough pressures and rates to
split the rock. Sized particles such as sand are also mixed with the fracturing fluid to hold the
crack open once pumping stops. In addition, wells can be oriented to Horizontal Drilling
technology intersect natural fractures that occur in many formations as shown in figure(2-10).
Marcellus Sh-u,
HydrofracZone
Horizontal Drilling Technology
Figure (2-10) benifts of horizental drilling
LNG CAIN 14
2.6.3 Reservoir Recovery
A) Primary recovery (Natural Drive ... 15 - 20 %)
1- Water drive
2- Gas drive (Dissolved & gas cap)
B) Secondary recovery (Artificial lift ... 30 - 50 %)
1- Gas lift
2- Pumps. (Sucker rods).
C) Enhanced recovery techniques
1- Water flooding
2- Gas injection
3- Chemical flooding
4- Thermal recovery
2.6.4 Drilling the well
The well is created by drilling a hole 5 to 36 inches (127.0 mm to 914.4 mm) in diameter into the
earth with a drilling rig that rotates a drill string with a bit attached. After the hole is drilled,
sections of steel pipe (casing) , slightly smaller in diameter than the borehole, are placed in the
hole. Cement may be placed between the outside of the casing and the borehole. The casing
provides structural integrity to the newly drilled well bore, in addition to isolating potentially
dangerous high pressure zones from each other and from the surface.
With these zones safely isolated and the formation protected by the casing, the well can be
drilled deeper (into potentially more-unstable and violent formations) with a smaller bit, and also
cased with a smaller size casing. Modem wells often have two to five sets of subsequently
smaller hole sizes drilled inside one another, each cemented with casing as shown
LNG CAIN 15
-Gas T bi Sucker Rod Cementu Illg I,---~~-,~.-~.-.~~~~-~-~--.---..-----,----~ L ,
L --J.."----.. J_.__.._ ___~I____!I \
Annulus Clslng
figure (2-11) natural gas well
2.6.5 Gas injection
Nitrogen Injection:
Nitrogen gas, produced on-site by cryogemc air separation, has replaced hydrocarbon gas
injection in many enhanced oil and gas recovery applications as shown in figure (2-12). And also
nitrogen injection has many advantages:
Advantages of Nitrogen Injection
• Nitrogen is economical.
• Nitrogen is readily available and can be generated and injected wherever, whenever and in
whatever quantities are needed.
LNG CAIN 16
• Nitrogen is environmentally friendly, completely inert, and remains inert in the presence of
water.
• Nitrogen can be removed economically from a sales gas stream if necessary to increase Btu
content.
• Nitrogen gas is less compressible than either carbon dioxide or natural gas, so less is required.
Nitrogen Injection Process Flow Diagram
/I PowerGeneration
NaturalGas
III Main Air SeparationAir Compressor Unit
NitrogenCompressor
High-PressureGaseousNitrogenfor Well Injection
Oil andNatural GasRecovery
Figure (2-12) using nitrogen injection in natural gas production
LNG CAIN 17
CHAPTER THREE:Processing and
Liquefaction Techniques
3.1 Natural gas processing
3.1.1 Introduction
Due to clean burning characteristics and the ability to meet stringent environmental
requirements, the demand for natural gas has increased considerably over the past few years.
Projections reflect a continued increase for the next several years. However, it is a clean burning
methane rich gas that is in demand as opposed to the typical raw gas that exists in nature, which
often includes additional components such as heavier hydrocarbons and other impurities. The
heavier hydrocarbons, once separated from natural gas, are referred to as Liquefied Petroleum
Gas (LPG) and Natural Gas Liquids (NGL). Impurities may include carbon dioxide, hydrogen
sulfide, mercaptans, nitrogen, helium, water, and even trace contaminants such as mercury and
trimethylarsine. Natural gas must be "conditioned" prior to liquefaction to remove undesired
components. This "conditioning" normally takes place in separate or standalone facilities and
typically includes the extraction of heavier hydrocarbons such as LPG and NGL. The
"conditioned" gas is then typically fed to pipelines for distribution.
Figure (3-1) natural gas processing unit
LNG CAIN 18
Pentanes and heavier hydrocarbons, including aromatics having a high freezing point, must be
substantially removed to an extremely low level in order to prevent freezing and subsequent
plugging of process equipment in the course of liquefaction. In addition, heavy components must
also be removed in order to meet BTU requirements of the LNG product. The heavy
hydrocarbons separated from LNG, may then be utilized as petrochemical sales or for gasoline
blending.
Alternatively, since all components having a higher condensing temperature than methane will
be liquefied in the liquefaction process, it becomes technically practical to integrate NGL
recovery within LNG liquefaction. Duplication of processing equipment and refrigeration
requirements are avoided with an integrated approach. In fact, a substantial cost savings may be
achieved when NGL recovery is effectively integrated within the liquefaction process.
3.1.2 Acid gases, water, mercury and other components removal:
A number of NGL recovery processes have been developed for natural gas and other gas
streams. Among various NGL recovery processes, the cryogenic expansion process has become
the preferred process for deep hydrocarbon liquid recovery from natural gas streams. Figure (3-
2) depicts a typical cryogenic expansion process configuration. In the conventional turbo-
expander process, feed gas at elevated pressure is pretreated for removal of acid gases, water,
mercury and other contaminants to produce a purified gas suitable for cryogenic temperatures.
The treated gas is typically partially condensed utilizing heat exchange with other process
streams and/or external propane refrigeration, depending upon the gas composition. The
resulting condensed liquid, containing the less volatile components, is then separated and fed to a
medium or low-pressure fractionation column for recovery of the heavy hydrocarbon
components. The remaining non-condensed vapor, containing the more volatile components, is
expanded to the lower pressure of the column using a turboexpander, resulting in further cooling
and additional liquid condensation. With the expander discharge pressure essentially the same as
the column pressure, the resulting two-phase stream is fed to the top section of the fractionation
LNG CAIN 19
column. The cold liquid portion acts as reflux, enhancing recovery of heavier hydrocarbon
components. The vapor portion combines with the gas in the overhead of the column. The
combined gas exits the column overhead as a residue gas. After recovery of available
refrigeration, the residue gas is then recompressed to a higher pressure, suitable for pipeline
delivery or for LNG liquefaction.
~\~O_P_iP_.~_lt_ll_e_O_r_L_N_'G_._p_la_n_! ~~ •.- ~
Re com pression
H2SfC02Removal(Optional)
H20 NGL Ex n-ac rio n
Feed Ga s
NGL(C2+ or CJ+)
Figure (3-2)-Block diagram for typical NGL extraction plant
The fractionation column (as described) acts essentially as a stripping column since expander
discharge vapors are not subject to rectification. As such, a significant quantity of heavy
components remains in the gas stream. These components could be further recovered if subjected
to rectification.
Figure (3-3) illustrates a typical block diagram of the LNG facility. Gas compnsmg
predominantly methane enters the LNG facility at elevated pressures and is pretreated to produce
a feedstock suitable for liquefaction at cryogenic temperatures. Pretreatment typically includes
the removal of acid gases (hydrogen sulfide and carbon dioxide), mercaptans, water, mercury,
and other contaminants. The treated gas is then subjected to a plurality of cooling stages by
indirect heat exchange with one or more refrigerants, whereby the gas is progressively reduced in
LNG CAIN 20
temperature until complete liquefaction The pressurized LNG is further expanded and sub-
cooled in one or more stages to facilitate storage at slightly above atmospheric pressure. Flashed
vapors and boil off gas are recycled within the process.
FeedGas H2S/C02Removal ---to Dehydration •.••.•- •••(Olltional)
Heavy. LNGComponent •.•••- •••.•LiquefactionRemoval
1H20 Higb freezing
)JointNGLLNG
Figure (3-3)-Block diagram for typical LNG plant
3.1.3 Process Description of an Integrated NGL and LNG plant:
A block diagram for an integrated LNG and NGL process is presented in Figure (3-4). For the
purposes of this paper. Treated natural gas is first cooled by utilizing refrigeration from within
the liquefaction process in one or more stages and then introduced into a distillation column, or
Heavies Removal Column. Figure (3-4) represents the simplest embodiment ofNGL integration,
where the Heavies Removal Column is not refluxed other than with condensed liquids contained
within the column feed. Once the feed has entered the column, it is separated or in this case
stripped. A bottoms stream, primarily comprised of NGL components, and a methane rich
overhead stream are formed. The methane rich overhead stream is chilled, condensed, and in
most cases sub-cooled within the liquefaction process. Once liquefied and sub-cooled, the stream
is subsequently flashed to near atmospheric pressure in one or more steps in preparation for LNG
storage. Flashed vapor is used as methane recycle refrigerant with a portion heated and
compressed for fuel. The liquid stream from the Heavies Removal Column is introduced to a
second distillation column in one or more feed trays, depicted in Figure (3-4) as a Deethanizer.
In the second column, the liquid stream is separated into a bottoms stream and a vapor overhead
stream, primarily comprised of ethane and lighter components.
LNG CAIN 21
The second column acts primarily as a deethanizer or partial deethanizer or in some cases a
depropanizer or partial depropanizer, depending on the desired BTU level of the LNG product
and desired level of propane and/or
ethane recovery. The second column bottoms stream may be routed to further fractionation in
order to separate the NGL and/or LPG liquids into the desired product slate.
Feed Gas
r----------------~I Refrigerant: SystemI II II II II II II II
".jIIIII
NGL
H2S!C02Removal
LNGLiquefaction
---- Natural GasLNG
--------. Refrigerant
* Reflux stream for lean methane confignratien..NGL
fC2+ or C3+)
Figure (3-4)-Block diagram showing the integrated NGL and LNG process
NGL recovery integration not only reduces capital investment through reutilizing essentially all
equipment in the NGL facility for LNG production, but also improves overall thermodynamic
efficiency. There are significant advantages in the following aspects:
• The overall integrated process reduces combined capital and operating costs.
• The integrated process reduces combined C02 and NOX emissions by improving the
thermodynamic efficiency of the overall process.
• Higher recovery of propane (and ethane) is achievable.
• Most NGL process equipment is already utilized in LNG liquefaction plants.
LNGCAIN22
In the integrated process for cryogenically recovering ethane, propane, and heavier components,
the Heavies Removal Column in the LNG facility replaces the NGL recovery column in the
NGL plant.
Since integration of NGL recovery into the natural gas liquefaction process allows for higher
recovery of heavier hydrocarbon components, the removal of liquefaction contaminants such as
cyclohexane and benzene are also improved. This is important since these particular components,
even at relatively low concentrations, may create freezing problems in the colder sections of the
LNG process. Thus higher NGL recovery and less operational concerns are achieved at the same
time that the front-end NGL plant is eliminated .
.-Case 1No-reflux case:
The simplest embodiment of integrated NGL recovery utilizes a heavies removal Column with
the only reflux essentially from liquids contained within the column feed.
Case 2 Lean Methane Reflux Scheme:
A lean methane stream is condensed within the liquefaction process and introduced as reflux to
the Heavies Removal Column. In the CoP LNG Process, there are multiple sources that may be
used for lean methane reflux, each containing extremely low concentrations of heavy
components. Lean methane used as reflux enhances NGL recovery efficiency within the column,
subsequently reducing NGL components in the overhead stream to a minimum. Thus, a higher
NGL recovery is achieved even at relatively high operating pressures, in the range of 600 psig.
Of course, lean methane reflux is more advantageous for ethane recovery operations.
Case 3Deethanizer overhead reflux scheme:
In this configuration, Heavies Removal Column reflux is generated from the deethanizer
overhead. Refer to Figure(3-4). The deethanizer overhead is partially condensed with the liquids
or a portion of the liquids introduced to the top of the deethanizer as normal reflux. The vapor or
a portion of the vapor is compressed, partially condensed and introduced to the Heavies Removal
Column as reflux. This reflux stream is rich in ethane, which provides an excellent choice for
propane recovery.
LNG CAIN 23
It is possible to operate the deethanizer as a demethanizer, providing a methane rich reflux to the
Heavies Removal Column. Thus, operation may be easily switched between propane and ethane
recovery simply by adjusting operating parameters.
3.2 NATURAL GAS LIQUIFACTION
3.2.1 Introduction
Once natural gas has been cleaned and scrubbed, it is transported to its final destination.
Depending on where the gas is being transported to, it needs to be liquefied, or cooled to a liquid.
The liquefaction of natural gas involves cooling the natural gas to -260 F (-162°c), at which point
the gas has become a liquid. After liquefaction, the volume of the gas is reduced by a factor of
600. Reducing the volume allows for more of the gas to be transported with less equipment,
especially when being transported overseas. There are hundreds of processes for liquefying
natural gas, but very few are actually in use. Most of the processes in use are not patented, with
mostly new processes being patented. The most used processes for liquefaction are processes
developed by Air Products and Chemical Inc., ConocoPhillips, and Linde, each of which has a
capacity between two and eight MTPA. Depending on the process, different refrigerants are used
to cool the natural gas but with the use of similar equipment. The factor that differs between
processes is the setup and design.
The primary equipment used are plate fin heat exchangers, spiral wound heat exchangers, shell
and tube heat exchangers, compressors, expanders, and valves. Most of the work required to cool
the natural gas takes place in the plate fin or spiral wound heat exchangers.
LNG CAIN 24
(PFHE) (SWHE)
FIGURE (3-5) TYPES OF HEAT EXCHANGERS
A basic refrigeration cycle consists of two heat exchangers, a valve, and a compressor. The
refrigerant flows through the evaporator where it is heated. The evaporator represents the cooling
that a gas or liquid would receive from the refrigerant. From the evaporator, the refrigerant flows
through a compressor to get the stream back to the design pressure. It also converts the stream
from two phases to one phase. After the evaporator the refrigerant might be at or past its boiling
point. After the compressor, the refrigerant flows through a condenser to get it to its bubble
point. The refrigerant then flows through an expansion valve, after which it is cool enough to
absorb the heat that is transferred in the evaporator.
LNG CAIN 25
.,-3 Condenser
Expansion CompressorValve
E\ "Iiorat or 1
4
Figure (3-6) a basic refrigeration cycle
PureRefrigerant
Natural gas cooling
MixedRefriqerant
HeatFigure (3-7) pure& mixed cooling curve
LNG CAIN 26
Above is an example of what a typical temperature-heat diagram or cooling curve, for the
cooling of natural gas using both pure and mixed refrigerants would look like. During cooling, it
is desired to have an efficient process. One method of determining the efficiency of a cycle is to
review the cooling curve. The closer the line depicting the refrigerants is to the curve of the
natural gas, the more efficient is the cycle. Increasing the efficiency of the process reduces the
amount of work done by the heat exchanger. The amount of work done by the heat exchanger is
indicated by the space between the curves.
When using pure refrigerants, such as propane or nitrogen, the curve of the refrigerant is
typically a stair step curve against the natural gas as indicated by the beginning of the diagram. A
mixed refrigerant curve is typically smoother, allowing it to come closer to the curve of the
natural gas, as shown at the end of the diagram. This implies that the use of a mixed refrigerant,
typically including methane, ethane, propane, and butane, is a better choice for refrigerants. The
composition of the mixed refrigerant is also a factor in how close the refrigerant curve is to the
natural gas curve.
LNG CAIN 27
3.2.2LNG Liquefaction Techniques
1- Prico Process
This process is considered as one of the simplest and most basic processes currently in
operation in the industry. It is considered a very basic setup with one large heat
exchanger network and a single mixed refrigerant refrigeration cycle. Though the simple
setup limits the capacity 1.2MTPA per train, it reduces capital costs significantly.
Condenser Compressor
Figure (3-8) Prico ProcessThe mixed refrigerant used in this process is methane, ethane, propane, pentane and nitrogen.
Inlet Gas
Cold Box
LNG CAIN 28
The 'cold box' in the setup is a collection of highly efficient plate fin heat exchangers that help
in the heat exchange process between the compressed refrigerant and the raw natural gas. This
heat exchange enables the cooling of natural gas to about a- 260 F(-162°c) through forced
convection due to the turbulent nature of its flow. There is a considerable amount of refrigerant
used in the process to facilitate the cooling of the natural gas which leads to a lot of compression
work needed.
Figure 3-4 shows a simplified flow sheet of the PRICO process. Natural gas is fed to the main
heat exchanger (NG HX) after some pretreatment. In heat exchanger NG HX, the natural gas is
cooled, liquefied and sub-cooled by heat exchange with cold refrigerant. The refrigerant is
partially condensed in the sea water (SW) cooler (condenser) and is fed to the NG HX and is
cooled together with the natural gas stream. The refrigerant is a sub-cooled liquid at the outlet of
NG HX and is expanded to the low pressure (PI). The resulting two-phase mixture provides the
cooling in NG HX by vaporization. The outlet from the heat exchanger (NG HX) is slightly
super-heated, partly to avoid damage to the compressor.
7. ConocoPhillips Simple Cascade
The ConocoPhillips Optimized Cascade LNG process has emerged as an economical, proven
alternative for the liquefaction of natural gas. In addition to the original Cascade plant in Kenai,
Alaska, built in 1969, eight plants have been constructed in the last ten years: four in Trinidad
and Tobago, two in Egypt, one each in Australia and Equatorial Guinea.
LNG CAIN 29
Residue Gas
Inlet
LNG
Figure (3-9) ConocoPhillips Simple Cascade
The natural gas is cooled, condensed, sub-cooled in heat exchange with propane, ethylene.i or
ethane) and finally methane in three discrete stages. The three refrigerant circuits generally have
multistage refrigerant expansion and compression, each typically operating at three evaporation
temperature levels. After compression, propane is condensed with cooling water or air, ethylene
is condensed with evaporating propane and methane is condensed with evaporating ethylene. All
the stages in this process use pure refrigerant.
LNG CAIN 30
InletRaw Gas
Transfer Pump
Tank Vapor Blower
•• __ ::. __ To Ship LoadingFacilities
Figure (3-10) ConocoPhillips Simple Cascade
The cascade cycle requires the least amount of power of all the liquefaction process, mainly
because the flow of refrigerant is lower. It is also flexible in operation, since each refrigerant
circuit can be controlled separately. Composite warming and cooling curves for the cascade
cycle are given in the next figure.
The major disadvantage of the cascade cycle is the relatively high capital cost due to the number
of refrigeration compression circuits, each requiring its own compressor and refrigerant storage.
Maintenance and spare equipment costs tend to be comparatively high due to the large numberof machines. The cascade cycle has relatively low power and low surface area, but increased
complexity in machinery configuration.
LNG CAIN 31
Economies of scale show that the cascade cycle is most suited to large train size, since the low
heat exchanger area and low power requirement offset the cost of having multiple machines. By
optimizing machinery selection, the cascade cycle can be competitive with the pre-cooled mixed
refrigerant cycle, which has been dominate cycle in base-load mixed refrigeran
3. Dual Mixed Refrigerants
This process consists of 2 refrigeration cycles. Pre-cooling and the liquefaction cycles the
refrigerant used in the first cycle is a mixture of ethane and propane. The refrigerant used in the
second cycle is a mixture of nitrogen, methane, ethane, propane and butane.
IPrecool MR
MR ITreatedGas NG I
Precooling Liquefaction
Figure (3-11) Dual Mixed Refrigerants
LNG CAIN 32
In the pre-cooling cycle the treated natural gas and mixed refrigerant (MR) of the mam
liquefaction cycle are cooled to a temperature of about -SODC.The pre-cool refrigerant is
primarily a mixture of ethane and propane. The pre-cooling cycle is two-stage and uses spool
wound heat exchangers, since the liquid pre-cool MR evaporates over a temperature range rather
than at one temperature, as is the case with propane. This lineup is simpler than the traditional
propane cycle and uses fewer heat exchangers.
In the mam cryogemc heat exchanger in the liquefaction cycle pre-cooled natural gas is
condensed to LNG against the mixed refrigerant, which consists mainly of methane and ethane,
with some propane and nitrogen.
To push the capacity of LNG trains even further, Shell company has developed the three-driver
Parallel Mixed Refrigerant (PMR) process, which is the basis for the Nigeria LNG. With a
single pre-cooling cycle and two parallel mixed refrigerant cycles, the capacity can be boosted
above 10 Mtpa, depending on the driver size. The process can use either propane or a mixed
refrigerant in pre-cooling. The schematic diagram of the PMR process is shown in next Figure.
After cooling the NG in the pre-cooling cycle, its flow is split over two MR spool wound
exchangers, where liquefaction takes place against mixed refrigerant. Each MR loop is provided
with its own compressors and driver. The MR streams are cooled in separate tube bundles or a
separate set of propane heat exchangers in the pre-cooling cycle. Each MR string has its own MR
separator.
LNG CAIN 33
~ •.•.•..P~r..•.ec.•o_ol•••il_1g-"",
Liquefaction
LNG
Figure (3-12) Parallel Mixed Refrigerant (PMR) process
4. Mixed Fluid Cascade Process (LINDE)
This process involves three distinct stages: Pre-cooling, Liquefaction and Sub-cooling. Each
stage is controlled by three separate mixed refrigerant cycles. The mixed refrigerants are
composed of methane, ethane, propane and nitrogen at different compositions. This process is set
exactly like a classical simple cascade except with one major difference, the mixed refrigerant.
The mixed refrigerant improves flexibility and thermodynamic efficiency.
LNG CAIN 34
Pre-coolingSection(PFHE)
LiquefactionSection(S\VHE)
Sub cooling--.'Section(S\VHE)
G
LNG
Figure (3-13) Mixed Fluid Cascade Process (LINDE)
I,
The natural gas (red stream) comes in from the top and goes through three mixed refrigerant
cycles. The pre-cooling cycle (green cycle) cools natural gas through two Plate-Fin Heat
Exchangers (PFHE) while the liquefaction (purple cycle) and sub-cooling (blue cycle) cycle cool
via Spiral Wound Heat Exchangers SWHEs. SWHE may also be used for the pre-cooling stage.
The only possible reason PFHE is used is because it is less expensive than SWHE. The
refrigerants are made mainly of methane, ethane, propane, and nitrogen but the composition ratio
of the refrigerants would differ among the three stages.
LNG CAIN 35
Propane (%) Ethane (%) Methane (%) Nitrogen (%)Pre-cooling --·60 ~<28 ~10 ~~2(Green Cycle)Liquefaction ., ~12 N80 ·~5'~J
(Purple Cycle)Sub-cooling ~7 -10 -80 .,
~J
(Blue Cycle)
5. APe1
The APCI (Air Products and Chemicals Inc.) process, also called Propane Pre-cooled Mixed
Refrigerant Process (PPMR) currently holds 88% of the liquefaction plants on the market. They
currently produce 107.5 mtpa of LNG with 53 trains in operation. Their technology uses a three
stage refrigerant cooling powered by two 85 MW compressors. The first stage is a pre- propane
cooling stage that cools the mixed refrigerant and inlet treated gas to around - 35 F. The next
two cooling stages, held in a heat exchanger tower, use mixed refrigerants
(MR) of about 27% methane, 50% ethane, 20% propane, 2% Butane ,and 1% nitrogen to cool
and condense the natural gas. The flow sheet is shown in the next figure:
LNG CAIN 36
Mixed Retngerant.~ 1% N2~ 27·30% Methane~ 50% Ethane-, 18·20% Propane- 1·2% Butane
PretreatedNatural GasFeed
Propane Chillen:
Propane Chillers
ScrubTower
SeawaterCooler
1~Stage !vIRCompressor
l(tStage !vIRCompressor
Figure (3-14) Air Products and Chemicals Inc
Propane chills the gas during pre-treatment. A flash tank is used to separate the mixed refrigerant
to a heavy coolant (bottom/red stream) and a lighter coolant (top/green stream). The heavy
coolant (propane, butane, and some ethane) takes care of the cooling in the warm bundle (bottom
part) of the heat exchanger tower which cools down the natural gas stream (blue stream) to about
-50°C and then the light coolant is sprayed back on the streams of the warm bundle via valves to
insure that the refrigerant cooled the natural gal) stream to the maximum point possible for this
mix. The light coolant (methane, ethane and nitrogen) cools down the natural gas stream to -160
°C in the cold bundle and this temperature is the point where natural gas is converted to LNG.
Similarly to the warm bundle, the light coolant is then sprayed on the streams in the cold bundle
of the heat exchanger tower and then mixed with the sprayed heavy coolant in the warm bundle
and then compressed; that is the end of the cooling cycle. The liquid coming out of the top of the
heat exchanger tower is then separated via flash tank to LNG (bottom stream) and light fuel (top
stream) which is later sent for fractionation in another sector.
LNG CAIN 37
APCI has also invented their X technology. APCI-X uses nitrogen for the third refrigerant loopinstead of MR to cool down the natural gas. The addition of nitrogen to the loop takes some ofthe compression work off of the propane pre-cooling compressor allowing for increasedproduction.
LNG CAIN 38
t
t
4.1 TRANSPORTING BY PIPELINS
Interstate pipelines are the 'highways' of natural gas transmission. Natural gas that is transported
through interstate pipelines travels at high pressure in the pipeline, at pressures anywhere from
200 to 1500 pounds per square inch (psi). This reduces the volume of the natural gas being
transported (by up to 600 times), as well as providing propellant force to move the natural gas
through the pipeline.
We will cover the components of the interstate pipeline system, the construction of pipelines, and
pipeline inspection and safety.
4.1.1 Pipeline Components
Interstate pipelines consist of a number of components which ensure the efficiency and reliability
that is needed from a system that delivers such an important energy source year round, twenty
four hours a day, and consist of a number of different components.
I=Pipes
Pipelines can measure anywhere from 6 to 48 inches in diameter, although certain component
pipe sections can consist of small diameter pipe, as small as 0.5 inches in diameter. However,
this small diameter pipe is usually used only in gathering and distribution systems. Mainline
pipes, the principle pipeline in a given system, are usually between 16 and 48 inches in diameter.
Lateral pipelines, which deliver natural gas to or from the mainline, are typically between 6 and
16 inches in diameter. Most major interstate pipelines are between 24 and 36 inches in diameter.
The actual pipeline itself, commonly called 'line pipe', consists of a strong carbon steel material.
Line pipe is also covered with a specialized coating to ensure that it does not corrode once placed
in the ground.
2- Compressor Stations
As mentioned, natural gas is highly pressurized as it travels through an interstate pipeline. To
ensure that the natural gas flowing through anyone pipeline remains pressurized, compression of
this natural gas is required periodically along the pipe. This is accomplished by compressor
LNG CAIN 39
stations, usually placed at 40 to 100 mile intervals along the pipeline. The natural gas enters the
compressor station, where it is compressed by a turbine, motor, or engine.
3- Metering Stations
In addition to compressing natural gas to reduce its volume and push it through the pipe,
metering stations are placed periodically along interstate natural gas pipelines. These stations
allow pipeline companies to monitor and manage the natural gas in their pipes. Essentially, these
metering stations measure the flow of gas along the pipeline, and allow pipeline companies to
'track' natural gas as it flows along the pipeline. These metering stations employ specialized
meters to measure the natural gas as it flows through the pipeline, without impeding its
movement.
4- Valves
Pipelines include a great number of valves along their entire length. These valves work like
gateways; they are usually open and allow natural gas to flow freely, or they can be used to stop
gas flow along a certain section of pipe. There are many reasons why a pipeline may need to
restrict gas flow in certain areas. For example, if a section of pipe requires replacement or
maintenance, valves on either end of that section of pipe can be closed to allow engineers and
work crews safe access. These large valves can be placed every 5 to 20 miles along the pipeline,
and are subject to regulation by safety codes.
5~Control Stations and SCADA Systems
Natural gas pipeline companies have customers on both ends of the pipeline - the producers and
processors that input gas into the pipeline, and the consumers and local distribution companies
that take gas out of the pipeline. In order to manage the natural gas that enters the pipeline, and
to ensure that all customers receive timely delivery of their portion of this gas, sophisticated
control systems are required to monitor the gas as it travels through all sections of what could be
a very lengthy pipeline network. To accomplish this task of monitoring and controlling the
natural gas that is traveling through the pipeline, centralized gas control stations that collect,
LNG CAIN 40
assimilate, and manage data received from monitoring and compressor stations all along the
pipe.
6 Pipeline Inspections and Safety
In order to ensure the efficient and safe operation of the extensive network of natural gas
pipelines, pipeline companies routinely inspect their pipelines for corrosion and defects. This is
done through the use of sophisticated pieces of equipment known as pigs. Pigs are intelligent
robotic devices that are propelled down pipelines to evaluate the interior of the pipe. Pigs can test
pipe thickness, and roundness, check for signs of corrosion, detect minute leaks, and any other
defect along the interior of the pipeline that may either impede the flow of gas, or pose a
potential safety risk for the operation of the pipeline. Sending a pig down a pipeline is fittingly
known as 'pigging' the pipeline.
In addition to inspection with pigs, there are a number of safety precautions and procedures in
place to minimize the risk of accidents. In fact, the transportation of natural gas is one of the
safest ways of transporting energy, mostly due to the fact that the infrastructure is fixed, and
buried underground.
LNG CAIN 41
4.2 LNG Carriers
Introduction
LNG ships, or carriers, provide the link in the LNG Chain between where the natural gas is
liquefied and where it can be regasified. LNG ships enable large amounts of clean natural gas
energy to be transported to the consumer over large distances from the LNG Liquefaction Plant.
The LNG is delivered to marine import terminals where the LNG is warmed
and converted back into a gas, through a regasification process, before being delivered into the
gas pipeline network. LNG can also be distributed to consumers in road tank trucks.
Over 1,500 liquefied gas ships operate around the world, most of which transport liquefied
petroleum gas (LPG). There are approximately 320 LNG ships currently involved in worldwide
trade. In comparison, there are approximately 12,000 oil tankers; of those approximately 800 are
very large crude carriers (VLCC's).
The LNG shipping industry has an excellent safety record. Since the first cargoes of LNG were
shipped on a regular commercial basis in 1964, over 45,000 shipments have been made without a
single incident of LNG being lost through a breach or failure of the ship's tanks .•..
A typical modem LNG ship is approximately 300 meters (m) long, 43m wide and has a draft of
about 12 m. LNG ships vary in cargo capacity, from 1,000 cubic meters to 267,000 cubic meters,
but the majority of modem vessels are between 125,000 cubic meters and 150,000 cubic meters
capacity. Smaller LNG ships (1,000 - 25,000 cubic meter capacity) also operate in some areas,
such as Norway and Japan. LNG carriers are capable of speeds up to 21 knots (oil tankers
operate at 15-20 knots) in open waters. Approximately 300 LNG carriers are in service in 2009,
with over 50 on order.
LNG CAIN 42
Figure (4-2) historical LNG fleet growth
The majority of LNG ships sailing today have been designed to carry LNG either in spherical
tanks (Moss sphere design) or in geometric membrane tanks (membrane design)
Figure (4-3) Moss sphere design
LNG CAIN 43
Figure (4-4) Membrane design
All LNG ships have double hulls. The cargo is carried near atmospheric pressure in specially
insulated tanks, referred to as the cargo containment system, inside the inner hull.
10090-8070605040302010o
No of vessels
CJ existing• neNV build 07
Figure (4-5) types & number of carriers
LNG CAIN 44
4.3 LNG Tank types and their classification
4.3.1 Membrane Tanks
Membrane tanks are non-self-supporting tanks consisting of a thin layer (membrane) supported
through its insulation by adjacent hull structure. The membrane is so designed that thermal and
other expansion or contraction is compensated by the membrane as a whole without undue
stressing of any part of it. This type of containment system requires a complete secondary
barrier, able to contain cargo for at least 15 days without endangering the ship if the primary
membrane should leak. The secondary barrier is typically designed as an integral part of the
insulation system, and consists of a thin metallic or non-metallic membrane.
Membrane tanks are normally not designed for an internal pressure exceeding 25kPa but this
pressure may be increased to maximum of 70kPa provided the hull scantlings are increased
accordingly. Two different membrane systems are offered: Technigaz and Gaz Transport.
4- NO 96Membrane System
Is a cryogenic liner directly supported by the ship's inner hull.
This liner includes two identical metallic membranes and two independent insulation layers
The primary and secondary membranes are made of Invar, a 36% nickel-steel alloy, 0,7 mrn
thick. The primary membrane contains the LNG cargo, while the secondary membrane, identical
to the primary, ensures a 100 % redundancy in case of leakage. Each of the 500 mrn wide invar
strakes is continuously spread along the tank walls and is evenly supported by the primary and
the secondary insulation layers.
The primary and secondary insulation layers consist III a load bearing system made of
prefabricated plywood boxes filled with expanded perlite. The standard size of the boxes is 1m x
l.2m. The thickness of the primary layer is adjustable from 170mm to 250mrn the typical
thickness of the secondary layer is 300 mrn. The primary layer is secured by means of the
primary couplers, themselves fixed to the secondary coupler assembly. The secondary
LNG CAIN 45
layer is laid and evenly supported by the inner hull through load-bearing resin ropes, and
fixed by means of the secondary couplers anchored to the inner hull.
Figure (4-6) NO 96 Membrane System
5- MARK III Membrane System
Is a cryogenic liner directly supported by the ship's inner hull.
This liner is composed of a primary metallic membrane positioned on top of a prefabricated
insulation panel including a complete secondary membrane:
The primary membrane is made of corrugated stainless steel 1.2 mm thick. It contains the LNG
cargo and is directly supported by and fixed to the insulation system. Standard size of the
corrugated sheets is 3 m x 1m.
LNG CAIN 46
The secondary membrane is made of a composite laminated material: a thin sheet of aluminum
between two layers of glass cloth and resin. It is positioned inside the prefabricated insulation
panels between the two insulation layers.
The insulation consists of a load-bearing system made of prefabricated panels in reinforced
polyurethane foam including both primary and secondary insulation layers and the secondary
membrane. The standard size of the panels is 3 m x 1 m. The thickness of the insulation is
adjustable from 250 mm to 350 mm .The panels are bonded to the inner hull by means of resin
ropes which serve a double purpose: anchoring the insulation and spreading evenly the loads.
Primary slalOler.ssteel membrane
Top bridge pad
Flenbletripl~x Joint
Flat JOlflt
Plugs
Secondary tnplexmembrane ReSin ropes
Figure (4-7) MARK IIIMembrane SystemLNG CAIN 47
6- CSI Membrane System for LNG Integrated Tanks
CS 1 Membrane system is a cryogenic liner directly supported by the ship's inner hull. This liner
is composed of a prefabricated insulation panel including a complete secondary membrane:
The primary membrane is made of lnvar, a 36% nickel-steel alloy, 0.7 mm thick. The primary
membrane contains the LNG cargo. Each of the 500 mm wide invar stakes is continuously
spread along the tank walls and is evenly supported by and fixed to the insulation. Standard size
of the corrugated sheets is 3 m x 1m.
The secondary membrane is made of a composite laminated material: a thin sheet of aluminum
between two layers of glass cloth and resin. It is positioned inside the prefabricated insulation
panels between the two insulation layers.
The insulation consists of a load-bearing system made of prefabricated panels in reinforced
polyurethane foam including both primary and secondary insulation layers as well as the
secondary membrane. The standard size of the panels is 3 m x 1 m. The thickness of the
insulation is adjustable from 250 mm to 350 mm. The panels are bonded to the inner hull by
means of resin ropes which serve a double purpose: anchoring the insulation and spreading
evenly the loads.
LNG CAIN 48
Promary InvDr
Flo'ible triple.lOin'
51 ds
Figure (4-8) CS 1 Membrane System for LNG Integrated Tanks
Independent Tanks, Type B
They are defined as tanks designed using model tests, refined analytical tools and analysis
methods to determine the stress levels and crack 'propagation rates. Such tanks may be either of
prismatic shape or bodies of revolution, and only a partial secondary barrier may be required.
LNG CAIN 49
4.3.2 Spherical Tanks
The Moss type is the design emblematic of the LNG ship in that the tops of the spheres protrude
above the hull making the ships instantly recognizable. Pioneered by Norway's Moss Rosenberg
in the 1970's, the design is now owned by Moss Maritime Lysaker, Norway, a unit ofItaly's ENI
SAIPEM.
Characteristics
• Low pressure whether flat sided or spherical tank
• Since it is designed and built not to leak no secondary barrier is required
• Spherical tanks do have a partial secondary barrier in the form of a drip tray
• Since no leakage is anticipated from the space the hold space can be kept under dry air,
provided there is the means to inert the space quickly should there be a leak
• Means must be provided to drain the hold space of water usually an eductor
Spherical tanks are generally produced in aluminum or 9% nickel steel. The sphere is welded to
a steel skirt that is connected to the hull of the ship and is then free to expand and contract as
necessary.
LNG CAIN 50
T~",k~o¥crof steel~IlS"fation -.--~----~~.- ..•F-..-..-...::'Aluminium tanksheU ,.,..,.-.•••.....~~...;.;,;c..;
'iP~ to:werj domeaiod foundation
.'fuetural transition( AltTf, Nit 55 )
"'Mal brak~'of~~f~t~$S steel
$-~t~ ('~ubl~il~J lid .=---~--,-~_$'~~J~it~.
Figure (4-9) spherical tank
Insulation is fitted to the outside shell of the sphere but no secondary barrier is regarded as
necessary across the upper part of the sphere. However, below the sphere, an aluminum drip tray,
together with splash plates, provides secondary protection for the hull.
LNG CAIN 51
•.-01-
Introduction
The cargo tank, although adequately insulated, but small amount of heat in-leak to the tank
cannot be avoided. The LNG boils-off when the heat in-leak is more than latent heat of the LNG,
because the LNG is not super-cooled but it is transported in the boiling condition.
Most of cargo tanks are designed to operate at atmospheric pressure, therefore, must be taken off
from the tank, and be treated in both safe and economical manner. The boil-off rate is in order of
0.25% of the shipload per day. At this rate, a LNG tanker loses about 90% of one load per year!
For a 125000m3 LNG tanker this is a loss of more than 5million Dollar per year.
The presence of the BOG and the BOG treatment are one of the key factors of the design.
Following formula may be used to calculate boil-off rate at Ambient air 450C and sea water
320C:
LNG CAIN 52
5.1 Following kinds of the BOG treatment are so far developed or
recommended
The main requirement is to avoid release of boil-off to the atmosphere. Flaring evaporated gas is
uneconomical and might be dangerous.
Three possibilities can be considered:
1- Avoid boil-off
2- Re-liquefaction of evaporated gas
3- Combustion in propulsion plant
Dual Fuel Diesels
DualFuelPropulsionS~ Steam Turbine
Gas Turbine
BOGTreatment
Combined SystemsCombined Systems
Figure (5-1) BOG Treatment
LNG CAIN 53
5.1.1 Avoid boil-off
To avoid boil-off, very low heat transfer coefficients should be achieved for insulation a residual
boil-off should be blocked with resulting pressure build-up in the tanks after several days sailing.
Boil-off levels proposed today, i.e. about 0.10 to 0.15% per day, are about half of what used to
be standard on the first generation of LNG carriers.
To further decrease this level would not be economically justified, since it would require an
increase of insulation thickness with two major consequences:
a- Volume and cost increase of insulation itself,
b- b- Loss of cargo-carrying capacity given the ship's dimensions.
On the other\hand, pressure increase with blocked boil-off is not technically acceptable for any
containment design and should it be, such a solution would not be acceptable for the gas
terminals which would have to handle the extra boil-off contained in LNG since land-based tanks
are also under atmospheric pressure.
5.1.2 Re-liquefaction
Introduction
Such a solution may seem attractive. All the LNG cargo could be delivered and propulsion might
be based on efficient diesel engines burning only heavy fuel oil.
However, re-Iiquefaction plants are rather expensive. They require either to be redundant or to be
backed by additional equipments to bum the boil-off.
Re-liquefaction plants also require additional maintenance by qualified crew, consume a large
amount of electrical power. As a rough figure, one can say that the gas required to supply
necessary energy for reliquefaction represents about 20% to 30% of liquefied gas. Furthermore,
it would also be used to reliquefy
LNG CAIN 54
large amounts of nitrogen present in the boil-off. LNG can contain up to 1.2% of liquid nitrogen,
resulting in about 27% gaseous nitrogen in the boil-off gas.
Some manufactures still do not believe this solution would be economically justified with
present low boil-off rate.
The Re-liquefaction plant consists of boil off compressor, nitrogen compressor, expansion
turbine/booster compressor, heat exchanger and cold box.
Reliquefaction Process
BOG from cargo tanks is fed to the condenser in the cold box by a boil off compressor, where
the gas is condensed and sub-cooled. Reliquefied gas is returned by an LNG return pump to the
cargo tanks.
On laden voyage, reliquefied gas is led to any cargo tank sequentially and automatically where
remains a room to fill it up. While ballast voyage, it is returned to the heel holding tank.
5.1.2.1- Total Reliquefaction
For total reliquefaction system a simple closed loop expander cycle with nitrogen as refrigerant
is recommended. The centrifugal refrigeration compressor is driven by a steam turbine, which is
supplied with steam from the central boiler of the vessel, or an electric motor. One advantage of
this system is its flexibility: part load control down to less than 50% of full capacity with nearly
no loss in efficiency.
LNG CAIN 55
Heat Exchanger
Heat Exchanger
--+-------......--- Expander
----- ..•.---------Figure (5-2) Total Reliquefaction
5.1.2.2- Self-sustained Reliquefaction
This is very similar to the total reliquefaction system, the refrigeration loop being also a nitrogen
expander cycle. But the self-sustained plant is independent of steam supply. The refrigeration
compressor is driven by a gas turbine which is fired by part of the boil-off. The advantage of this
system is its independence and simplicity in design integration. This system may be added to an
existing vessel.
LNG CAIN 56
IIII
•IIt Heat Exchanger
I__+-_L --... _
Heat Exchanger
----- ..•.---------
Expander
Figure (5-3) Self-sustained Reliquefaction
5.1.2.3- Partial Reliquefaction
The partial reliquefaction system requires a low energy to reliquefy about 30% of the boil-off.
The refrigeration is provided by the warm-up of that part of boil-off which is not reliquefied.
This plant consists of a heat exchanger and a recirculation compressor.
LNG CAIN 57
Figure (5-4) Partial Reliquefaction
5.1.3 LNG Propulsion Systems
5.1.3.1 Steam Turbines
Summary
At the time of building the first LNG carriers for regular trade in the early 1960's the stearn
turbine was the dominant type of marine propulsion due to its proven reliability, low
maintenance costs, unlimited power output and the ability to utilise widely available lower grade
fuel with resultant lower bunker costs. The associated boiler plant also provided a simple but
effective means of dealing with the BOG from the liquid gas cargo.
By the time LNG carriers in the 125000 to 130000 cubic meter were introduced during the late
70's and early 80's, research was being undertaken into gas fuelled diesel engines, however a
conservative industry considered stearn turbines to be the only viable option for the required
service speed and for operation in.
LNG CAIN 58
An environment where reliability was paramount and immobilization for maintenance on an
LNG berth was, and still is unacceptable to port authorities and terminal operators.
The Gas Burning Steam Plant
When the early LNG carriers were introduced, steam turbine technology and that of associated
boilers and steam plant, was well understood by sea-going engineers. It was therefore reasonably
straightforward to adapt the existing plant to cope with the additional of gas burning. In order to
safely bum BOG in vessel's boilers the following must be accomplished:
Firstly the gas has to be collected from tanks via a common "Vapour Header", then compressed
to a pressure suitable for injection to the boiler. BOG temperature must be raised above OOC to
allow safe delivery to engine room.
The heated gas, now at about 50C is piped to the engine room via an automatic isolating valve
which will close and shut down automatically in the event of an abnormal situation, for example
boiler or engine trip, blackout etc. This valve is commonly referred to as "G" valve.
On leaving the open deck the gas piping is encased within the "Gas Duct" which is a
continuously ventilated trunking, the exhaust from which is continuously monitored for
Methane.
The gas pipe is led to the vicinity of the boiler where the gas pipe is divided and led to each
burner via individual shut off valves.
The short sections of pipe from the duct to the furnace front are double walled (jacketed) and the
intervening space is pressurized with Nitrogen.
Above each furnace front is another ventilated trunk known as the "Hood" or "Canopy" which is
also continuously ventilated and monitored for Methane.
The gas duct and the hood are each fitted with two extractor fans, one running and one on
standby. Gas burning is shut down if either the duct or the canopy fans are not operational and if
Methane detected in either trunk at or above 30% acceptable level.
LNG CAIN 59
An environment where reliability was paramount and immobilization for maintenance on an
LNG berth was, and still is unacceptable to port authorities and terminal operators.
The Gas Burning Steam Plant
When the early LNG carriers were introduced, steam turbine technology and that of associated
boilers and steam plant, was well understood by sea-going engineers. It was therefore reasonably
straightforward to adapt the existing plant to cope with the additional of gas burning. In order to
safely bum BOG in vessel's boilers the following must be accomplished:
Firstly the gas has to be collected from tanks via a common "Vapour Header", then compressed
to a pressure suitable for injection to the boiler. BOG temperature must be raised above OOC to
allow safe delivery to engine room.
The heated gas, now at about 50C is piped to the engine room via an automatic isolating valve
which will close and shut down automatically in the event of an abnormal situation, for example
boiler or engine trip, blackout etc. This valve is commonly referred to as "G" valve.
On leaving the open deck the gas piping is encased within the "Gas Duct" which is a
continuously ventilated trunking, the exhaust from which is continuously monitored for
Methane.
The gas pipe is led to the vicinity of the boiler where the gas pipe is divided and led to each
burner via individual shut off valves.
The short sections of pipe from the duct to the furnace front are double walled (jacketed) and the
intervening space is pressurized with Nitrogen.
Above each furnace front is another ventilated trunk known as the "Hood" or "Canopy" which is
also continuously ventilated and monitored for Methane.
The gas duct and the hood are each fitted with two extractor fans, one running and one on
standby. Gas burning is shut down if either the duct or the canopy fans are not operational and if
Methane detected in either trunk at or above 30% acceptable level.
LNG CAIN 59
The combustion of gas was carried out initially with a minimum fuel oil flow (Mini-fuel) as a
pilot burner.
This of course means that special provision must be made to ensure that there is continuity of
combustion in the event of a gas shut down. In dual fuel mode a modem LNG will utilize fuel oil
for a minimum 2% of fuel demand.
The overall steam plant is conventional apart from supplying steam to a steam dump, to deck for
gas and cofferdam heating, possibly compressor drive and if required to a forcing vaporizer. This
latter piece of equipment has been added OIL later vessels where BOG has been reduced by
improvements in insulations from approx. 0.25% per day to less than 0.1% and where natural
BOG is insufficient to meet the fuel gas demand for the boilers at full power.
5.1.3.2 Gas Turbines
Introduction
It is over 40 years since the world's first all gas turbine ship, HMS Grey Goose powered by two
Rolls-Royce RM60 gas turbines, was commissioned. Today gas turbines have displaced steam
machinery in new naval ship construction.
The initial reasons for using gas turbines were the saving in weight and space in high speed craft
and their ability to provide power at short notice in larger ships. Operating at short notice in ships
of all sizes soon demonstrated their superiority over both steam and diesel machinery in terms of
reduced maintenance requirements, leading to reductions in engine room complement and
increased ship availability. Experience also indicated that, far from being the delicate highly
stressed machinery it was at first considered, the modem gas turbine is well able to withstand
arduous naval operating conditions.
LNG CAIN 60
Installation Requirements
This follows fairly closely the well-established requirements for a warship installation except
relaxation of some specific naval requirements, such as high shock resistance and equipment
duplication for battle damage contingencies. In general more space will be available in an LNG
carrier than in a warship.
To achieve long engine life, it is necessary to reduce the sodium chloride in the ingested air to
below 0.01 ppm by weight under all conditions which can be achieved by using a three stage
filtration. The first stage removes water droplets; the second provides coalescing plus filtration to
remove dry salt particles. The third stage protects against any carry-over of water droplets from
the rear face of coalescer stage particularly at high humidity conditions and salt concentrations.
Silencing of both intake and exhaust may be required. Exhaust systems can follow conventional
practice except for the addition of a small waste heat boiler to provide steam for hotel services
and cargo handling if required.
Boil-off Disposal
In port, boil-off disposal means operating the machinery at about half power and dumping the
resultant energy.
For an electric propulsion system this may be fairly readily achieved by the use of electrical load
banks which dissipate the energy at fairly low temperature to either water or air. The latter is
expensive and space consuming unless forced draft cooling is used.
An alternative scheme which at first looks attractive in simply to bypass the power turbine and
pass the gas generator output directly to exhaust. This is impractical because of the difficulty of
designing a reliable long life, variable hot duct and valve combined with the problems associated
with exposing the exhaust silencing media to the hot, fast efflux of the gas generator. Installation
of water brakes to absorb the energy results in a complicated gearbox with multiple clutches and
difficult control arrangements.
LNG CAIN 61
5.1.3.3 Dual Fuel Diesel Engines
Figure (5-5) dual engine system
Introduction
Should the operators of LNG carriers consider the new dual-fuel diesel engine as propulsion
plant? One of the reasons is the superior economy of operation, the amount of liquid heavy fuel
which must be provided for a dual-fuel engine in addition to the gaseous fuel already available
by natural evaporation, may only 1/8 as much as is needed by a steam plant of equal output. This
is closely followed by its reliability and safety, a factor which counts extremely heavy with this
type of vessel. As an additional advantage of IC engines, we might mention the particular ease
by which diesel engine have been converted into remote control and no-man engine rooms.
LNG CAIN 62
Input Mullifuel engine Oulptl
Diesel oil
i'\mur:d gas
IICll'rl fuel
Crude oil
Figure (5-6) Multifuel Engine
Main Differences
Basically the dual fuel engine is a modified Diesel engine, modified in the sense that it is capable
to burn not only liquid, but liquid together with gaseous fuel. Differences may be classified as:
1- Working process
Fuel gas is introduced into the cylinder through a gas valve provided on the cylinder head during
the suction stroke. The gas and air are mixed with each other and the mixture is compressed in
the next compression stroke. On the final stage of the next compression stroke, a small quantity
of pilot fuel oil is injected to ignite the mixture gas. Other processes of the dual fuel engine are
the same as a normal diesel engine.
2- Air/Fuel ratio
The diesel engine is operated within a wide range of air/fuel ratios. A dual fuel engine, however,
is operated at an almost constant air/fuel ratio according to gas composition by controlling the
bypass flow of charge air. Temperature and oxygen ratio in the exhaust gas are also controlled by
this flow control of charge air.
LNG CAIN 63
3- Pilot fuel oil
The firing of the mixture in the cylinder can be achieved by a small quantity of injected fuel oil
which corresponds to the spark plug of a gas engine. The minimum quantity of pilot fuel is about
10% of the maximum fuel oil flow in diesel mode.
4- Gas valve
The dual fuel engine has a gas valve as well as a fuel injection valve on the cylinder head, by
which gas flow into the cylinder is controlled.
5- Dual fuel engine control In the case of the dual fuel engme, the following systems are
additionally fitted:
a- Control system of gas feed,
b~ Control system of air flow,
c- Changeover system between dual mode and diesel mode.
LNGCAIN64
Operating Principle and FeaturesFtre1'Y Mil UI' a \1'1 G'J~ Ini()ction
~'&'Qj
--., eomo.~«IO" "'"OI'~ X+ """1.
Figure (5-7) comparison between dual & diesel engines
-
[(~ -~- ""¥L-. tv-.n ••.•' _
_-1 .••.
LNG CAIN 65
Comparison
1- The compression ratio of the dual fuel diesel engine is restricted to a level which is generally
less than of the oil fuel diesel engine to avoid knocking action. So the dimensions and weight of
the dual fuel engine may be larger than those of an oil fuel engine of the same horsepower range.
2- Fuel supply control in any proportion of oil and gas fuel is made by changeover from fuel oil
mode to dual fuel mode and vice versa, which can be done automatically after initial setting of
the burning conditions.
So the operation of the dual fuel engine is nearly the same, without any complicated operation, as
that of the oil fuel diesel engine.
3- Combustion in dual fuel mode is cleaner than that with fuel oil only mode due to less
impurities of the fuel. Since cylinder head, liner and piston are kept clean , the maintenance
interval of these parts of the dual fuel engine can be prolonged.
__1-rl. ~:---
F.-""'''.'''>~
l§§~ -~.-.~1~1
;;;:~ctH~rr~·.:Jlitt~>,,(~t -i::~tc.('~rUf-~!'H'nnO:::F.'.'ffH!r'H;!'~ '~O:Ho l~.!" ··Pue' P.tHJHH:~< l.;.:->'"i-"H_:"'{·~~·::::.n·~l.:Jnk(~~·~·
Figure (5-8) Schematic layout of control arrangement for Dual-fuel engines
LNG CAIN 66
Safety Systems
The design and installation of the LNG boil-off gas system from the high-pressure compressor
right to the engine cylinder head valves must ensure that breakdowns cannot occur when
specified requirements are met.
Monitoring of the following has a high level of importance:
1- If gas pressure should fall 15% below the nominal value an automatic valve cuts off the gas
flow to the engine and at the same time drains the gas receiver on the engine towards the
atmosphere.
The same happens if the pressure in the supply line to the fuel injection pump falls below a
predetermined value or the over-speed governor shuts the engine down and also if the engine is
running below half load or in case it is being operated in reverse or maneuvered.
2- Least possible time delay in detecting natural gas leakage by controlled atmospheres, double-
walled pipe work and gas detectors.
3- Avoidance of explosive mixtures through scavenging with inert gas in due time if natural gas
concentration exceeds 50% lower explosive limit (LEL)
4- Shut down dual-fuel operation, with automatic relief of high gas supply pressure at
concentrations exceeding 50% LEL.
5- Strict isolation ofleakage source by sub-division of high pressure gas pipework.
6- Limitation of gas leakage quantity by safety block valves which automatically shut off the gas
supply in cases of excessive gas flow, such as pipe fracture.
7-Engine misfiring. If an oil injection pump should seize and prevent any pilot oil injection in to
that cylinder, the boil-off gas would self-ignite. The two most practical monitoring techniques
are:
LNG CAIN 67
• Analysis of torsional ibration in the crankshaft.
• Measurement of exhaust gas temperature at each cylinder.
LNG CAIN 68
••
6.1 Introduction
LNG (Liquefied Natural Gas) is a method for transporting methane gas over long distances. The
gas is liquefied prior to transport from the gas production location and is transported as a cooled
liquid in LNG carriers.
The tankers deliver the LNG to a LNG re-gasification terminal compnsmg LNG tanker
unloading facilities, LNG storage tanks, re-gasification units and gas export pipeline(s).
The LNG has to be re-gasified before it can be transmitted through a pipeline distribution
network. The re-gasification takes place in the re-gasification unit.
6.2 Best Available Commercial Technologies
The three sources of thermal energy typically used to warm LNG from a liquid to a gaseous state
are ambient air, natural gas (heat from combustion), and seawater.
The basic types of vaporization systems that utilize these sources of thermal energy include
LNG CAIN 69
VAPORIZATION SYSTEM DIRECTORINDIRECT HEAT
a.. C
< "'0C'O.-••• "t; a..e -::s !.! C'O.Q co.Q ::;E ~E "-0 coC'Ou GI< z_ ~
x x
Ambient Air Vaporizer (AAV) direct heatoor indirect heat
Intermediate Fluid Vaporizer (lFV)propane or refrigerant
Intermediate Fluid Vaporizer (lFV)water/glycol
indirect heate
indirect heat x x x
x
Open RackVaporizer (ORV) direct heat x
Shell and Tube Vaporizer (STV) direct heat x
Submerged Combustion Vaporizer (SCV) indirect heat
Figure (6-1) vaporization systems
x
Each system uses a vaporization process that passes the liquefied natural gas through pipes that
are surrounded by a heating medium to transfer heat into the LNG.
"Direct heat" is when the heating medium directly warms the LNG.
"Indirect heat" is when the heating medium is used to warm an intermediate (or secondary)
medium that transfers the heat to the LNG.
Lastly, each vaporization system can be set up as an "open-loop" or "closed-loop" system. Using
seawater to heat the LNG is referred to as open-loop vaporization, while using natural gas
combustion is closed-loop vaporization.
LNG CAIN 70
6.4 VAPORIZATION SYSTEMS
6.3.1 Intermediate Fluid Vaporizers
An intermediate fluid vaporizer (IFV) uses an intermediate heat transfer fluid to revaporize LNG.
IFV technology can be configured to operate in a closed-loop, open-loop, or combination system.
The most common intermediate fluid vaporizers use propane, refrigerant, or a water/glycol
mixture as an intermediate fluid. Although propane and refrigerant have low flash points that
are ideal for heat transfer, the operational risks are much higher when handling these types of
fluids, and these fluids are very costly. The water/glycol mixture has a high flash point,
requiring a larger heat transfer area, which results in a larger system than the propane or
refrigerant systems.
However, the water/glycol fluid system is more cost effective and the associated operational
risks are relatively low.
LNG CAIN 71
Power Transmission lineDomestic use
LNG Vaporizer(IHM Condenser)
LNGStorageTank
PumpIHMCirculat nPump
NG TrimHeater
IHMVaporizer
NG (Vaporized LNGGas) put let
Seawater outlet
LNG Cold Utilizing Power Generation System by Rankine Cycle
Figure (6- 2) Intermediate Fluid Vaporizers
An IFV typically uses a "shell and tube" heat exchanger where LNG flows through the tubes
with the intermediate heating medium circulating inside the shell and around the
tubes. There are two stages to heating the LNG with an intermediate fluid vaporizer.
First the liquefied natural gas is heated by an intermediate fluid in a heat exchanger, in which the
LNG becomes a gas. The intermediate fluid flows through tubes in separate heating equipment to
absorb heat.
LNG CAIN 72
Then the vaporized natural gas is circulated through a second shell and tube heat exchanger, with
seawater as the heating medium used to bring the gas to the temperature required to send it out
through pipelines for use.
The open-loop IFV technology requires seawater intake. Therefore, environmental issues include
adverse effects (and assumed mortality) to marine life
If an intermediate fluid vaporizer
system operates v ith propane or refrigerant as
the intermediate fluid then these fluids add a potentially
hazardous material to the facility operations.
An IFV system that uses the water/glycol mixture is considered
a safer way to operate. Lastly, depending on the
combustion process used to heat the intermediate fluid, air emissions are also an environmental
concern, unless the system uses waste heat recovery.
Water/glycol Fluid: It's a fluid consists offrom 35% to 60% water plus glycol antifreeze such as
ethylene. diethylene. or propylene
LNG CAIN 73
6.3.2 Ambient Air Vaporizers
Ambient air vaporization (AAV) technology uses ambient air as the thermal energy source to
vaporize the liquefied natural gas. The LNG is distributed through a series of surface heat
exchangers where the air travels down and out the bottom of the vaporizer. The air flow is
controlled on the outside of the exchanger through natural buoyancy of the cooled, dense air, or
by installing forced-draft air fans.
This process can be set up as either a direct heat or indirect heat system. AAV technology is best
suited for areas with warmer ambient temperatures. In cooler climates,a supplemental heat
system would be necessary to maintain effective use during colder weather conditions.
Frost forming on the vaporizer is an issue because the LNG is vaporized directly against the air
(direct heat s stem) and the water vapor in the air condenses and freezes. Frost build-up reduces
performance and heat transfer. To maintain continual operation,
Additional units are typically installed to provide the required throughout. The ambient air
vaporization system requires a significant amount of space to prevent ambient air recirculation
and to maintain the aporizer capacity.
There is no seawater intake associated with this system. However, cooling ambient, moist air
(which condenses into fresh water) necessitates treatment to prevent biofouling in the freshwater
discharge piping. Discharging the treated fresh water back into the ocean could potentially have
an adverse impact on the sea water. Also, depending on geographical locations (such as areas
with high dew points) cooling the ambient air can generate a "fog bank."
LNG CAIN 74
Figure (6-3) TOW UNITS RUNNING ONE DEFROST
V\lsrrnA.-nbten't Aft'
:.--..----.----- ..~LNG
Na1uralGas
CoolAmbient A.ir
Figure (6-4) unit structure
LNG CAIN 75
6.3.3 Shell and Tube Vaporizers
STY and Intermediate Fluid STV type are generally smaller in SIze and cost competitive
compared to an ORV or SCV system.
Heat is usually supplied to the LNG vaporizer by a closed circuit or open circuit with a suitable
heat transfer medium. They are mainly used when a suitable heat source is available. Design of
these types of vaporizer systems requires a stable LNG flow at design and turndown conditions
with provisions to prevent the potential for freeze-up within the vaporizer.
Simple design uses seawater as the thermal energy source. In an open-loop STY system, LNG
enters the bottom of the STV, which is mounted vertically to optimize vaporization efficiency.
The liquefied natural gas passes through multiple tubes while seawater enters a shell surrounding
the tubes. (As in figure 6-5).
legend_LNG_ Natural Gas
Seawater Inlet
Natural Gas Outlet
- S-eawater InletBellowsExpansionJoint
Seawater Outlet
LNG Inlet
Figure (6-5) Shell and Tube Vaporizers
LNG CAIN 76
A closed-loop system uses an intermediate fluid (such as propane or a water/glycol mixture) to
transfer heat.
The intermediate fluid flows through tubes in separate heating equipment to absorb heat, then the
fluid passes through the STY unit to re-gasify the LNG. Since there are two heat exchangers,
this requires a large amount of space.
The new design is the design of Double Tube Bundle STY This design incorporates both a
lower and an upper set of tube bundles, and uses an intermediate heat transfer fluid (e.g. Propane,
Isobutene, Freon, Ammonia) between the LNG (upper tubes) and the seawater or glycol water
(lower tubes) inside a single shell.
Figure (6-6) Double Tube Bundle
LNG CAIN 77
6.3.4 Open Rack Vaporizers
ORVs use ambient seawater as their source of heat in an open, falling film type arrangement to
vaporize LNG passing through the tubes. ORVs are widely used in Japan, Korea and Europe, and
are well proven in base load LNG terminal service. In general, for using ORVs the preferred
seawater temperature is always above 8 "C.
General Description: The ORV is made of an aluminum alloy for good mechanical
characteristics at low temperatures, excellent workability, and high thermal conductivity.
Seawater is fed from an overhead distributor, flows downwards over the outer surface of long
finned tube heat exchanger panels, vaporizing the LNG flowing inside, and is collected in a
trough below where it is routed and discharged back to the sea. The panels are -coated externally
with zinc alloy, providing corrosion resistance against seawater. ORVs require regular (usually
annual) maintenance to keep the finned tube surface clean. The seawater is chlorinated to protect
the surface of the tube panel against bio- fouling and to prevent marine growth inside the piping.
Fluctuations in product gas demand, gas outlet temperature and seawater temperature will be
handled by turndown of the unit, which can be over 90%
LNG CAIN 78
••• ----r!"I"I"I"!"~..,..r
SeaWater
Bird's-eye view of t e ORV
Figure (6-7) Open Rack Vaporizers
Schematic Drawing ofOpen Rack VaporizerTroug11
-+NGOutaet
Appncatlon toLNG Rectevlng Terminal
Sea WatEH"Headef"~
• I :;: .$1 ·Supplyr-~-u-(mpJ·Wat ••• 1Ul'wi~,illi ~. .--'----~.~ -I
I'" Oraln Channef LNG L·SeraWater Pump TankIn e
Figure (6-8) schematic drawing of open rack vaporizer
Heattransfertube
LNG CAIN 79
Water Quality: Water quality is a critical requirement for successful operation of an ORV
system. Key requirements are:
II Significant amounts of water. This will lead to a requirement to carefully evaluate and assess
the amount of underwater fish and plant life that are ingested by the intake system. Often,
significant design requirements will be involved to minimize this.
Ll Chlorination for water treatment is desirable; however residual chlorine content can have a
negative impact on the marine environment by killing significant marine life. This can be
minimized by "shock" treatment of chlorine.
[J The water should not contain solids exceeding 2 mm in diameter in order to assure uniform
water flow without jamming of the solids between the water trough and the top of the tube panel.
[1Water containing heavy metal ions, Cu++, Hg++, must not be used in the water lines, as these
ions will shorten the lifetime of zinc-aluminum spray coating on the tubes. Cu++ < 10 ppb and
Hg++ < 2 ppb are required.
[ Sand and sludge deposits contained in sea or fresh water must be negligible. Suspended solids
shall not exceed 80 ppm
The pH of the seawater must be between 7.5 and 8.5.
6.3.5 Submerged Combustion Vaporizers
(SCV) The SCV vaporizes LNG contained inside stainless steel tubes in a submerged water bath
with a combustion burner. In the base load terminal SCV, the fuel gas is burned in a large single
burner rather than multiple smaller burners because it is more economical and it achieves low
NOx and CO levels. The hot flue gases are sparged into a bath of water where the LNG
vaporization coils are located. The SCVs are designed to utilize the low pressure fuel gas derived
from the boil-off gases of the facility and the let-down gas from the send-out gas. They may also
use an extracted heavier fuel gas (C2plus) from the LNG at the LNG terminal.
For the SCV operation, since the thermal capacity of the water bath is high, it is possible to
maintain a stable operation even for sudden start-ups/shutdowns and rapid load fluctuations.
LNG CAIN 80
Thus, they provide great flexibility for quick start-up after shutdowns and the ability to quickly
respond to changing demand requirements.
Due to the larger amount of flue gas, there is a concern for NOx and C02 emissions for the
operation, though a low NOx emission of less than 46 ppm is attainable. The NOx level may be
further reduced by using Selective Catalytic Reactor units (SCR) to 5 ppm, but it adds significant
cost to the SCV unit, almost doubling the cost of the system. The bath water becomes acidic as
the combustion products are absorbed in it. Alkaline chemicals (e.g. dilute caustic, sodium
carbonate and sodium bicarbonate) must be added to the bath water to control pH, and resulting
excess combustion water must be neutralized before discharge.
LNG CAIN 81
r+tStack
NG LNGoutlet inlet
r-- t !,-...
?)(
)(
, (~
,
)
-Y Y 'Y Y Y Y
Combustionair blower
Burner
(1) Submerged combustion vaporizer burns natural gas to heat water.(2) LNG is piped through the heated . l
water bath. H.•,
(3) Vaporized natural gas i piped to 011-
shore facility.
..
I.••I,
Figure (6-9) Submerged Combustion Vaporizers
LNG CAIN 82
6.3.6 Lower Emission LNG Vaporization Process
In Combined cycle power or industrial plants, cooling water is often used to reject heat from the
facilities. The heated water is then cooled down in a cooling tower.
A Lower Emission LNG Vaporization Process is described here which use the waste heat from
either a power plant or industrial facilities for LNG vaporization.
The process will eliminate fuel requirements, while reducing or eliminating arr or water
emissions and improving the thermal efficiency of the LNG terminal and plant facilities.
When an LNG Terminal operation is integrated with a Combined Cycle Power Generation Unit
by utilizing the cooling water used for condensing the power plant steam turbine exhaust steam
for LNG vaporization, the LNG vaporization process will achieve zero emissions.
POW<'Plont+ LNGRoceMng T.nninal
~ To PipelineReturn
Cond.n$&rr~~--~~~+Fn 10 .•.9FJI.-8T[)-2[3TM
Blow-DownConden~.ate 38 ·C
II!~I
1--D/iS"""!;""~--,=-~~~-'- - - - ICooling W~tef 'Sup.pl.,
W'JIt@f
CireulationPlIl'l'lj)$
Cooling WaterM:Jlre-up
Figure (6-10) Lower Emission LNG Vaporization Process
LNG CAIN 83
As an example (see Figure 6-9), about 157 MW cooling water duty at about 39°C steam
temperature level is required for Combined Cycle system with 390.8 MW power export. This
heat duty can be used to vaporize about 6.9 million tons per annum LNG. About 30,000
gallons/minute of cooling water is needed to pump around the system between the power plant
and the LNG terminal based on a 20°C water temperature drop utilized in the LNG vaporizers In
this no/lower emission process design, the power plant cooling tower duty is reduced and the
power plant efficiency is improved as the steam turbine exhaust steam is condensed at a lower
pressure because of using colder cooling water.
Various types of heat transfer equipment may be used for vaporizing the LNG by utilizing the
cooling water:
(I)The LNG vaporizers designed by Chicago Power & Process (CPP)
The CPP Vaporizer is a special, patented, shell and tube heat exchanger design, based on
established heat transfer theory, experience with low temperature liquids and proven, unique
flow path design. A warm fluid source, commonly water, water/glycol mix or sea water, is
required for the heat input and will provide natural gas vapor at common distribution
temperatures, with no liquid carry-over.
LNG CAIN 84
CC'l'<NE:,";TION:S:A. LNG INLET
O. HEAT1NIG FLUID OUTt.g;:T{PAFilA.LLEL FLOW}
O. HEATING FLUD INl...ET(Sf'UT FLOW)
£.. HC'AT!NlO< FLlJ1D OUTL£T{SPl-iT FLOW ONLY}
F. RuF'TUHE DiSC NoZ:ZI....E(01".,101'$", .•.)
J. SHELL C:'H'tAIN
Figure (6-11) the vertical design of vaporizer
(2) A modified SCV system similar to the Combined Heat and Power Unit Instead of using the
scrubbed warm water from the gas turbine exhaust gas stack, it would use the cooling water from
condensing the steam turbine exhaust steam as the heat medium.
The concept of Lower Emission LNG Vaporization Process can also be applied to ORV
operation. If the seawater temperature is lower and/or a higher gas send out temperature is
required, seawater could flow to the power plant unit first then to the ORVs to make the
operation practical and useful.
LNG CAIN 85
••
Conclusion
• Throughout this research we emphasized the importance of the energy resources in our
life.
• Natural gas one of the non renewable energy resources, is the most likely energy
resource as it is clear and considered to be the lowest polluted fuel.
• Nowadays natural gas is imported and exported by different countries all over the world.
This worldwide usage of the natural gas in returns leads to the growth of LNG
technology.
• Through this technology the volume of the natural gas is reduced 600 times from its
original volume by transforming it from the gaseous state into the liquid state. And also
we studied the different liquefaction technologies using in the LNG plants.
• Then we had an over view to the transferring LNG by using pipeline and the main
components of pipeline system. In additional to transferring LNG by pipeline we studied
the types of LNG carriers and transporting LNG over the seas.
• We also defined the boiling off and how to overcome this problem by re-liquefaction of
the waste gas or using this gas in dual engines.
• Finally we introduced to the methods ofre-gasification LNG to return it into its gaseous
status to make it suitable to use.
• So this is the way how the natural gas comes to our homes even if it came from other
countries.
LNG CAIN 86
References
1. http://www.marcellusfacts.com
2. http://geology. com! articles/marcellus-shale. shtml
3. http://shaleblog. com!category/marcellus-shale/
4. http://www.dec.ny.gov/energy/46288.html
5. http://blogs.cce.comell.edu/gasleasingl
6. http://www.recordonline.com!apps/pbcs.dll/ section ?Category= NEWS5 8
7. http://www.state.nj.us/drbc/naturalgas.htm Website:
8. http://www.srbc.net/programs/projreviewmarcellus.htm
9. http://www .ou.edu/class/chedesignlche548 007/Refrigeration%20Basics%20and%2010. http://www.lngpedia.com!wpcontent/uploads/Evaluation _oC LNG_Production _Technolo
gies vLlniv ofOklahoma.pdf
11. http://www .igu.orglknow ledge/publications/magi apr07/p 101-125.pdf
12. http://www.lngpedia.com!wpcontent/uploads/Evaluation_oC LNG_Production _Technologies_-_Univ_oCOklahoma.pdf
13. http://www.igu.orglknowledge/pub1ications/magiapr07 /p 101-125.pdf
14. www.uscg.mil/proceedings
15. www.cryostar.com
16. www.wowenergies.com
17. www.airproduct.com
LNG CHAIN 87
