3. 266
.
Many sources of natural gas are shut-in and
abandoned because the economics simply do not
justify their development. In some cases, access to
public transmission lines may be limited by distance
or local geography. In other cases, the need for
additional processing to bring the gas up to pipeline
quality standards may be a factor. While many
industrial applications can utilize gas that does not
meet these strict standards, the distance to the
nearest such industrial consumer may not justify the
cost of laying a direct pipeline. In such cases,
transporting the gas by truck may provide a solution.
Contents
1- INTRODUCTION
2- LNG pipelines
3- Transmission Pipelines
component
4- Re –liquefaction cycle of
BOG in ship
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1. INTRODUCTION
Many sources of natural gas are shut-in and abandoned because the
economics simply do not justify their development. In some cases, access to
public transmission lines may be limited by distance or local geography. In
other cases, the need for additional processing to bring the gas up to pipeline
quality standards may be a factor. While many industrial applications can
utilize gas that does not meet these strict standards, the distance to the
nearest such industrial consumer may not justify the cost of laying a direct
pipeline. In such cases, transporting the gas by truck may provide a solution.
Three options are possible for transporting LNG:
Truck transport
LNG pipelines
Marine carriers
2. Natural Gas Trucking
Natural gas in volumes as low as 500,000 cubic feet per day can be moved
economically by truck within a 60-mile radius of the source. The typical
system built by Tucker Gas Processing Equipment, Inc. is designed to handle
twice that much. (Depending on a number of variables, the transport of two to
three million cubic feet per day is possible).
In our system, the gas first passes through a compression and dehydration
station. After odorization, the gas is metered and loaded under pressure onto
tube trailers. When the trailers arrive at the customer site the gas is unloaded
through a delivery terminal (provided by TGPE) where the pressure is reduced
and controlled to meet the customer's requirements Trucking natural gas can
offer several benefits. Gas reserves that once lay stranded or undeveloped
begin to generate a revenue stream. Since the gas does not enter the public
transmission lines, processing costs may be reduced.
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Depending on the actual gas analysis and customer requirements,
additional processing may not even be necessary. Because the gas is being
sold directly for industrial use, attractive pricing packages can be offered to
prospective buyers.
FIGURE 1 LNG TRUCING
Size and volume
Tank trucks are described by their size or volume capacity. Large trucks
typically have capacities ranging from 5,500 to 9,000 US gallons (21,000 to
34,000 L; 4,600 to 7,500 imp gal).
A tank truck is distinguished by its shape, usually a cylindrical tank upon the
vehicle lying horizontally. Some less visible distinctions amongst tank trucks
have to do with their intended use: compliance with human food regulations,
refrigeration capability, acid resistance, pressurization capability, and
others.
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3. LNG pipelines
Pipelines are an efficient means of transporting crude oil, hydrocarbon
products, CO2, natural gas, liquid petroleum gas and other important fossil
fuels – as well as raw materials and products – speedily, safely and
smoothly. This calls for comprehensive solutions for gas turbines,
compression and pumping, plus flexible drive systems. Other vital elements
of a reliable oil and gas infrastructure are SCADA, systems for pipeline
monitoring, management information and telecommunications.
Pipelines need to be constantly and reliably operated and monitored in order
to ensure maximum operating efficiency, safe transportation, and minimal
downtimes and to maintain environmental and quality standards. Being able
to offer technically proven, standardized solutions from a single source
enables to help customers reduce risk and increase delivery reliability. As an
experienced supplier for the oil gas industry.
FIGURE 2 PIPE LINE
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3.1 Transmission Pipelines component.
Transmission pipelines are made of steel and generally operate at
pressures ranging from 500 to 1,400 pounds per square inch gauge (psig).
Pipelines can measure anywhere from 6 to 48 inches in diameter, although
certain component pipe sections can consist of small-diameter pipe that is
as small as 0.5 inch in diameter. However, this small-diameter pipe is
usually used only in gathering and distribution systems, although some is
used for control-line or gauge-line purposes. Mainline pipes, the principal
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 engineered to meet standards set by the American Petroleum
Institute (API), American Society of Testing and Materials (ASTM), and
American National Standards Institute (ANSI)
3.2 Pipe-Coating Materials.
Coating mills apply pipe coatings to ensure that the pipe does not corrode
once placed in the ground. Often, the coating mill is located adjacent to the
pipe mill, so line pipe moves directly from the pipe manufacturer to the
coating facility. The purpose of the coating is to protect the pipe from
moisture, corrosive soils, and construction-induced defects, which cause
corrosion and rusting. There are a number of different coating techniques.
In the past, pipelines were coated with a specialized coal tar enamel.
Today, pipes are often protected with a fusion bond epoxy or extruded
polyethylene, both of which give the pipes a noticeable light yellow color. In
addition, catholic protection is often used, which is a technique that involves
inducing an electric current through the pipe to ward off corrosion and
rusting (AGA 2004).
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3.3 Compressor Stations
Natural gas is highly pressurized as it travels through an interstate pipeline to
expedite the flow of gas. To ensure that the natural gas flowing through any
one pipeline remains pressurized, compression of the natural gas occurs
periodically along the pipe. This is accomplished by compressor stations,
which are 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.
Figure 3 Pipe-Coating Materials
FIGURE 4 COMPRESSOR STATIONS
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3.4 Metering Stations
Metering stations are placed periodically along interstate natural gas
pipelines. These stations allow pipeline and local distribution companies to
monitor, manage, and account for the natural gas in their pipes. Essentially,
these metering stations measure the flow of gas along the pipeline, allowing
pipeline companies to track natural gas as it flows along the pipeline.
3.5 City Gate Stations
The natural gas for most distribution systems is received from transmission
pipelines and fed through one or more city gate stations, sometimes called
town border or tap stations. The basic function of these stations is to meter
the gas and reduce its pressure from that of the pipeline to that of the
distribution system. The latter operates at a much lower pressure (reduced
from approximately 500–1,400 psig to about 0.25–300 psig). Figure 1.2-5
shows a city gate station that would typically be covered with a fiberglass
enclosure or metal building to protect it from the weather.
FIGURE 5 METERING STATIONS
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3.6 Valves
Interstate 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, but they can be used to stop gas flow along a certain section of
pipe. There are many reasons why pipeline may need to restrict gas flow in
certain areas, including for emergency shutdown and maintenance. 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
FIGURE 6 VALVES
3.7 Pig Launching/Receiving Facilities
Pigging facilities consist of pig launching or receiving equipment and allow
the pipeline to accommodate a high-resolution internal inspection tool. Pigs
are devices that are placed into a pipeline to perform certain functions.
Some are used to clean the inside of the pipeline or to monitor its internal
and external condition. Launchers and receivers are facilities that enable
pigs to be inserted into or removed from the pipeline.
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3.8 Control system
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. To manage the natural gas that enters the pipeline and 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 a potentially very lengthy pipeline network. To
accomplish the task of monitoring and controlling the natural gas that is
traveling through the pipeline, centralized gas control stations collect,
assimilate, and manage the data received from monitoring city gate stations
and compressor stations all along
the pipeline. Most of the data that is received by a control station is provided
by supervisory control and data acquisition (SCADA) systems Type of LNG
Carriers Spherical type of LNG Carrier
4. MARINE TRANSPORT
The first ship, Methane Pioneer, sailed from Lake Charles, Louisiana, to the
United Kingdom with 32,000 barrels (5,088 m3) of LNG on January 28, 1959.
Figure shows that by the end of 2006 the LNG fleet will have 206 carriers
FIGURE 7SHOWS THAT BY THE END OF 2006 THE LNG flEET WILL HAVE 206 CARRIERS
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4.1 Basic design criteria:
1. The low density of LNG and the requirement for separate water ballast
containment require a large hull, with low draft and high freeboard
2. The low temperature of LNG requires the use of special and expensive
alloys in tank construction. For free-standing tanks, only aluminum or
9% nickel steel are suitable, whereas for membrane tanks, stainless-
steel or Invar is used.
3. The large thermal cycling possible in the storage tanks demands
special supporting arrangements for free standing tanks and membrane
flexibility in membrane designs.
4. The hull of the vessel is carbon steel, so good thermal insulation is
required between the tanks and the hull. In addition, for membrane
tanks, the insulation must be capable of supporting the full weight of the
cargo.
5. The cargo handling equipment must be carefully designed to account
for thermal expansion and contraction.
Application of these principles in the design of LNG carriers resulted in a
number of different LNG containment concepts, but today only three systems
are in general use, and they may be grouped into two designs, independent
tanks and membrane tanks, which use different membrane configurations
FIGURE 8 : DIFFERENT LNG CARRIER TYPES
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4.1.1 Independent Tanks
Independent tanks are self-supporting, do not form part of the ship’s hull, and
are not essential to the hull strength (Marshall, 2002). The principal system in
use today is the Moss system, originally designed by Moss Rosenberg Verft
This system uses placed in the ship’s hull and a view of the vessel with three
of the four tanks installed. Kato et al. (1995) describe a typical design for
vessels and tanks used on two ships for the Indonesia−Japan route. The four
aluminum-alloy tanks on each vessel are of the Moss-4 spherical design and
can hold a total of 125,000m3 (0.8 MMBbl) of LNG, filled to 98.5% of
capacity. The tanks are insulated on the external surface by insulation
composed of phenol resin and polyurethane foam and are designed for a
boil-off rate 0.15% per day.
Prismatic Containment design spherical Containment design
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4.1.2 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.
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
Typically Sizes:- 125-145,000m3 .
No. of Crew: About 30 per Ship
Life Span: About 40 years or more
Construction period: About 2 to 2 ½ years from signing of contractor
Long experience in LNG transportation
Excellent track record
No internal stiffness
Aluminum Alloy (25 mm to 100 mm)
Smaller Loading Capacity
Longer time in dry dock Higher construction cost
Figure 10 Spherical tanks
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4.1.3 Membrane Tanks
Membrane tanks are non-self-supporting and consist of a thin metal
membrane, stainless steel or Invar (35% nickel steel), supported by the
ship’s hull through the thermal insulation. Presently, the Invar membrane
(Gaz Transport) is more popular than the stainless steel (Technigaz)
membrane; 24 of the 40 membrane ships on order will use the Gaz
Transport design (Harper, 2002). Invar owes its popularity to the fact that
it has a very small coefficient of thermal expansion in the operating
ranges of the tanks, which are approximately −260 to +180°F
FIGURE 11 MEMBRANE CARRIER
4.2Internal Hazards of LNG Storage Tanks
4.2.1 Overfilling
The nominal capacity (i.e. usable capacity) of the tank is 180,000 m3
.
The design unloading rate is 14,000 m3
/hr. and the unloading time is
about 18 hours.
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Overfilling of the inner tank may lead to overflow into the annular space
between the inner tank and the outer tank. The bottom of the annular
space is provided with 9% Ni steel up to 5m height. Furthermore leak
detectors are provided to detect any LNG leak in the annular space
bottom. Therefore, any overfilling event, if it ever occurs, can be detected
and shutdown initiated. Also, the secondary containment provided by the
outer concrete wall lined with steel will be able to contain this liquid.
There are several layers of safeguards to prevent overfilling:
a) The tank to which the cargo is to be unloaded is identified before the
arrival of the carrier, its level measured and the volume of cargo to be
unloaded is pre-determined and this information is provided to the
carrier. The total volume of cargo unloaded is also continuously
monitored during unloading (typically, the volume of available space
within the shore tanks is at least equal to the cargo volume to be
discharged from the carrier, i.e. ships would not normally be required
to unload cargo at multiple destinations);
b) Continuous level measurement on tank using four separate detection
systems with at least two different types of level measuring device;
pre-alarm at normal maximum level in tank, corresponding to the
usable capacity;
c) Level high alarm; this is set typically with 3 to 5 minutes holding
volume (between normal maximum level and high level) at design
unloading rate;
d) High high level initiates trip of shutdown valves in liquid inlet including
transfer piping from jetty and re-circulation lines (the trip is initiated by
a 2 out of 3 voting of separate level measuring devices of different
type). This will stop further inflow of liquid into the tank. High high level
trip is typically set with about 3 to 5 minutes holding volume (between
high level alarm and high high level trip). The safety integrity level
(SIL) of the high high level trip of liquid inlet will be determined during
detailed design; however, SIL 2 classification is typical for this
instrumented protective system which means that the probability of
failure on demand will be less than less than 0.01
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Based on the above, it can be seen that there is sufficient time (more than 10
minutes) for operator intervention in addition to the provision of high integrity
instrumented protective system (i.e. high high level trip).
4.2.2 Rollover
Stratification, i.e. formation of two distinct layers of different density may
occur in an LNG tank due to filling of cargo of different density than the
liquid already in the tank or due to preferential boil-off in the tank resulting in
a layer of more dense liquid at the top (due to evaporation of lighter
components) as compared to the lower layers (where the boil-off is
suppressed by the hydrostatic head but the liquid superheats due to heat
ingress and becomes warmer and less dense) [1]. Stratification may also
occur due to presence of sufficient nitrogen in LNG, typically more than 1%.
Preferential boil-off of N2 results in a layer of less dense liquid at the
surface.
The phenomenon of rollover occurs when the interface between the layers
becomes unstable, leading to rapid mixing of contents of the two layers. As
the superheated liquid from the lower layer rises to the surface, it gives off
large amounts of vapour leading to potential overpressure of the tank.
There are a number of safeguards to detect and prevent stratification.
These include:
a) Temperature and density gradient measurement along the tank liquid
column;
b) Provision for circulation of tank contents through the operation of in-
tank pump. Content from tank bottom is recirculated to the top, thus
releasing any superheat and promote mixing;
c) Provision for filling of tank from the top or from the bottom depending on
the relative density of cargo and the tank contents;
d) Regular sampling and analysis of boil-off gas including monitoring of
boil-off gas quantity.
The tank is also protected by relief valves in the event of de-stratification
leading to vapour generation. Relief valves are sized for rollover case as
per EN 1473 requirements.
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4.2.3 Inner Tank Leak
The main features of a full containment tank are that the liquid LNG is
fully contained within a self-supporting inner 9% Nickel steel, surrounded
by loose perlite insulation while the vapour is contained within a
surrounding concrete outer tank (which includes the slab, the wall and
the dome, all constructed of pre-stressed concrete). The concrete outer
tank serves as secondary containment and is also capable of containing
the liquid and of controlled venting of the vapour resulting from leakage
of the inner tank, should one occur.
A 9% Ni steel plate is provided as liner along the inner surface of the
outer shell at the bottom up to a height of typically 5m from the base.
This protects the lower wall section of the outer tank, mainly the wall to
base slab connection in the event of leakage.
A carbon steel plate lining is provided along the inner surface of the outer
shell and roof (above the bottom Ni plate liner) to act as vapour barrier
(i.e. to prevent vapour leakage through the concrete as well as to prevent
moisture ingress from the outside).
Re –liquefaction cycle of BOG in ship
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Tannehill, C.C., Budget Estimate Capital Cost Curves for
Gas Conditioning and Processing, Proceedings of the
Seventy-Ninth Annual Convention of the Gas Processors
Association, Tulsa, OK, 2000, 141.
Tannehill, C.C., Update if Budget Estimate Capital Cost
Curves for NGL Extraction with Cryogenic Expansion,
Proceedings of the Eighty-Second Annual Convention of
the Gas Processors Association, Tulsa, OK, 2003.
Tannehill, C.C., private communication, 2005.
