FLNG Training Module 1.1 Introduction to FLNG Rev 1

7/26/2019 FLNG Training Module 1.1 Introduction to FLNG Rev 1

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FLNG FundamentalsModule 1.1: Introduction to FLNG

LNG industry overview

Development and history

LNG properties and specifications

Opportunities and advantages of FLNG

Offshore considerations and challenges

12/07/2015 1FLNG Essentials


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Most gas is transported by pipeline - Why LNG?

Volume advantage for storage and transportation Transport over wide and deep oceans

Economic advantage of LNG vs. pipeline gas dependent on distance

World Bank estimates 140 billion standard cubic metres of gas was

flared in 2011 (about 40% of the LNG traded), producing 360 million

tonnes of CO2without any beneficial heat or power production

Disadvantages of natural gas liquefaction:

Energy intensive

Capital intensive Requires specialised terminals and carriers

Purity Requirements

Cryogenic handling (materials, safety)



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Most gas is liquefied onshore -Why FLNG?

FLNG is predicted to become an important sector of the LNG

industry:

While most of the easy onshore gas fields have been tapped, there areconsiderable stranded gas reserves offshore

There is growing opposition to locating LNG plants onshore (e.g. JamesPrice Point in Australias Kimberley Region) for environmental or landuse zoning factors. Floating LNG import terminals are already gainingpopularity for this reason

Environmental impacts may be reducedone example is reduction ofdredging in harbours for laying gas pipelines and for entry of LNGcarriers

Possible cost and schedule advantages, though FLNG operatingexpense may be high

As with any novel application of technology, some risk is associated withinitial application of FLNG. Teething problems can be expected withthe first FLNG applications, but subsequent FLNG projects can beexpected to become more straightforward

Experience gained by first FLNG operators will provide a competitiveadvantage



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The cryogenic industry developed in the second half of the nineteenth

century. Among others, Dr Carl von Linde developed and patented air and

gas separation technologies in Munich, Germany. The LNG industry startedits early development in the USA by using LNG technology for natural gas

peak shaving.

1964: First base load LNG export plant begins operation in Arzew, Algeria

using a cascade process designed and constructed by Technip/Air Liquid.

Exports were initially to Canvey Island, UK and Le Havre, France.

The first LNG cargo from Arzew was transported to Canvey Island on theRiver Thames in England on board the first purpose-built LNG carrier

Methane Princess, which had a capacity of 27,000 m3.

1968: The mixed refrigerant concept was presented in a paper at the LNG-1

conference in Chicago

1969: Kenai LNG plant comes on stream in Alaska USA, designed and

constructed by Phillips Petroleum and Bechtel, exporting to Japan. The

Kenai plant was mothballed for a while in 2012 but is currently back in

production with licence to export until 2015

1970: An LNG plant using an SMR process by APCI started up in Marsa El

Brega, Libya, exporting to Italy and Spain

Development History



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Development History

Air Products developed the SMR process into the C3/MR process which

was first applied in Brunei, starting up in 1972

The C3/MR process enjoyed unprecedented success between 1972 and1999, with train sizes increasing from 1.4 MTPA (Brunei) to 3.2 MTPA

(QatarGas). The only other technology built during this 27 year period

was the Prico SMR process in Skikda Algeria by Pritchard-Rhodes (now

Black & Veatch)

In 1999, the first Optimised Cascade train (3 MTPA) started up in PortFontin Trinidad designed by ConocoPhillips and Engineered by Bechtel

The Trinidad plant reintroduced competition into the industry and

though APCI continued to dominate, both C3/MR and Optimised

Cascade technologies were successfully developed reaching train sizes

of 5 MTPA around 2005. In this period, there was a boom in

construction of LNG plants and costs began to escalate significantly

In 2004, Shell began to license its own version of the C3/MR process (a

long-held ambition) starting with the Australian North West Shelf Train 4

at 4.2 MTPA



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Development History

Linde developed the Multifluid Cascade process which was implemented in

the Norwegian Snohvit LNG plant, starting up in 2007 with a train size of

4.3 MTPA. Initially, the Snohvit plant exhibited poor availability and wasfrequently shut down for cleaning, repair or modification

Meanwhile Shell developed the Dual Mixed Refrigerant process and

successfully applied it on Sakhalin Island in Russia with train sizes of 4.8

MTPA, starting up in 2008

At Gastech in 2002, APCI rolled out its large train APX process. After

much development, the first 7.8 MTPA APX train was started up in Qatar in

2009. Six APX trains were built in total, all in Qatar, for RasGas and

QatarGas. The last, QatarGas IV, started up in 2011

Other licensors, including ConocoPhillips and Shell, have designed large

scale process, but at present there appear to be no plans to build any new

trains of significantly larger capacity than 5 MTPA Construction of new liquefaction capacity slowed, with Pluto being the only

new train added in 2012. Angola LNG joined the ranks of LNG exporters

in 2013. PNG LNG started up in 2014, along with an Algerian expansion

train and the first train using Queensland coal seam gas (QCLNG).



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Development History (FLNG)

After years of research and development of several prototype FLNG

facilities, Shell announced FID for a floating LNG facility, Prelude, offshore

northwest Australia in 2011. Prelude will use the Shell DMR process for asingle train of 3.6 MTPA capacity. The FLNG facility is now under

construction at Samsung shipyards in Korea and will be the largest

floating structure ever constructed

In 2013, Petronas achieved FID for its PFLNG1 floating LNG project.

PFLNG1 will use a nitrogen expander process with a capacity of 1.2

MTPA and will be positioned off Sarawak Also in 2013, Exmar and Pacific Rubiales announced that construction

had started on an FLNG project for Columbia, consisting of a barge

mounted liquefaction facility in near-shore, benign waters. Capacity is 0.5

MTPA using an SMR process, but project was deferred in 2015

In 2014, Petronas announced that FID had been reached for its PFLNG2

facility to be positioned offshore Sabah with a capacity of 1.5 MTPA

Golar also announced start on conversion of an LNG carrier for FLNG in

2014. A number of other FLNG facilities are in FEED stage or undergoing

concept development or preFEED



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Refrigerant

Import


Components of an LNG Plant


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Components Comments related to FLNG

Gas Receiving, liquids

separation and stabilisation

Onshore LNG plants often have slug catchers

with a large footprint. For FLNG, reducing deck

space is paramount

Gas TreatingRemoval of

acid gases, water and mercury

All required for FLNG. High sulphur

concentrations present a problem for floating

facilities

Heavy hydrocarbon removal

and fractionation

Dependent on feed gas composition. For

FLNG, less is better

Liquefaction SMR and expander cycle plants are simpler

with less equipment than larger plants with

multiple refrigerant cycles, but train size islimited. They may be utilised in FLNG

Hydrocarbon refrigerant cycles MRsame requirements as large scale LNG.

N2Expander cyclesadvantage of no

hydrocarbon refrigerants




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Components Comments related to FLNG

LNG Storage and

Loading

For FLNG, LNG storage will be below deck

Utilities FLNG needs to be self-contained for utility

requirements

Power Generation Power requirements need to be generated onboard for FLNG

Gas and liquid

disposal

Same requirements as for large scale LNG plants.

Location of flares on FLNG is a challenge

Other infrastructure:

buildings, drainage,

security, emergency

response, fire and gas

systems

Drainage and buildings require specific design to

suit the FLNG structure. Fire & gas and

emergency response systems require attention

due to FLNG being more congested than onshore

plants




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Equipment required for pre-treatment of feed gas is common to all

LNG process technologies (depending on feed gas composition)

Acid Gas RemovalPrevent freezing of CO2during liquefaction

Typically amine processes are used

DehydrationPrevent freezing of water during liquefactionTypically molecular sieve is used

Mercury Removalprevent Aluminium corrosion

A number of adsorbents are available

Heavy Hydrocarbon removalPrevent freezing during liquefaction

Typically distillation is used


Gas Pre-Treatment


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LiquefactionQ: How is natural gas liquefied?

A: By using refrigeration

Q: How does refrigeration work?

A: Carnot proposes the theory



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Carnot Cycle

The Carnot cycle was proposed by Nicolas Carnot in 1823

The Carnot cycle is a theoretical thermodynamic cycle to create a temperature

difference (i.e. heat pump or, in reverse, refrigeration) by inputting work

1. Reversible isothermal expansion

2. Isentropic (reversible adiabatic) expansion

3. Reversible isothermal compression

4. Isentropic compression

A real engine (left) compared to the Carnot cycle (right). The entropy of a real material changes

with temperature.


Refrigeration


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Reverse Carnot Cycle


For liquefaction of natural gas, the

warm air in the diagram is replacedby warm natural gas which is cooled

and liquefied by the refrigerant

Refrigeration


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LNG Properties and Specifications


For large-scale projects, LNG is stored and transported at

pressure slightly higher than atmospheric (50 to 200 mbar gauge) At these pressures, LNG is stored at its bubble point, and heat

leakage into the storage container is balanced by boil-off

LNG bubble point at these pressures is typically in the range -1650C to -160 0C, depending on composition

Low pressure storage reduces cost of containment and reduces

probability and severity of leaks

Typical insulation specifications for boil-off are 0.05% per day for

onshore storage, and 0.15 to 0.25% per day for LNG carriers (% of

LNG boiled off per day, based on total storage volume) LNG boil-off may be compressed for use as fuel, or reliquefied

Pressurised LNG storage and transport can be economic for

smaller storage vessels and trucking operations


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LNG is :

colourless odourless,

non-corrosive,

less dense than water ~ 450kg/m3

non-toxic (may cause asphyxia by excluding oxygen)

LNG vapour typically appears as a visible white cloud since its coldtemperature causes moisture in the air to condense. LNG (the liquid

itself) is not flammable or explosive

The vapours formed at an LNG liquid pool surface are always fuel rich.

Because the LNG is boiling, the pool surface vapours contain near 100

% hydrocarbons consisting primarily of methane, especially early onduring the spill

The vapours need to mix with air in order to become flammable

LNG vapours will become flammable once mixed with enough air to a

concentration ranging from 5 to 15 % by volume



LNG Properties Video
http://www.youtube.com/watch?feature=player_detailpage&v=18jB74GtZwghttp://www.youtube.com/watch?feature=player_detailpage&v=18jB74GtZwg


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The ignition of LNG vapours, when in the flammable range, is relatively easy

The minimum ignition energy of LNG vapours is approximately 0.29 mJ If LNG is spilled on land or on water, some of the LNG vaporises immediately. If

ignition sources are present in locations where the vapour concentration is in the

flammable range, the most likely outcome will be an immediate ignition. The

resulting fire is sometimes termed a pool fire (even though it is the vapour which

burns, not the liquid)

LNG pool fire hazards are localized and as a result thermal radiation effects

(burns) are typically confined to within one or two pool diameters from the edge

of the flame

Thermal radiation is absorbed by water moisture and carbon dioxide present in

the air. In addition, thermal radiation intensity decays in proportion to the inverse

square of the distance from the radiation source (1/distance2)

Typically, a person exposed to a thermal radiation flux of 5 kW/m2will feel pain in

20 seconds. Second degree burns are possible. 5 kW/m2is often used as an

injury threshold




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If ignition is not immediate, the LNG vapours will continue to evolve and will

disperse in the prevailing direction of wind If the wind speed is low and the atmosphere is stable, the vapours, being cold

and heavy, will remain close to the spill surface, and will persist for some time

until dispersed by wind. As heat is absorbed from the environment, the vapour

warms and becomes lighter than air

Cold LNG vapours drift in the direction of wind and become diluted as they mix

with more air If the vapours continue to disperse without ignition, they will ultimately become

diluted to below the lower flammability limits of 5 % and will not burn or present a

hazard anymore

Typically, 2.5 % is used as a concentration threshold (1/2 the lower flammability

limit) when estimating flammable dispersion hazard zones in order to account for

the possibility of pocketing Dilution therefore is one of the main methods used to control spills resulting

from a loss of containment of LNG

Water curtains and jets can be used to draw in air and dilute the cloud that is

generated (putting water directly onto liquid pools should be avoided)




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LNG Vapour leak showing water condensation




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If the LNG vapours encounter an ignition source and ignition occurs

without the presence of confinement, a slow-burning flash fire will occur Thermal radiation hazards are confined to the boundaries of the

flammable cloud and no appreciable overpressure is generated

provided the vapour cloud is not in a confined or congested area.

The flash fire outcome can change drastically in the presence of

significant confinement (3 walls or more), or congestion (equipment andpipe work).

This is further exacerbated by flammable gas concentration close to

stoichiometry (~9.5% of methane in air) and the presence of higher

hydrocarbon in the LNG vapour (e.g. ethane and propane).

Though it is possible to have a transition from a deflagration to adetonation, this has not been observed in practice in industrial

accidents and in experiments that simulate explosions in industrial

environment




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During actual spills of LNG on water, a phenomenon that is

observed early on during liquid pool development is a Rapid PhaseTransition (RPT)

A rapid phase transition is the very rapid (near spontaneous)

formation of vapours as the cold LNG is vaporized from heat gained

from the underlying spill surface

Because the vapour is evolved very rapidly, localized overpressureis created. This is also sometimes described as a physical explosion

The hazard potential of rapid phase transitions can be severe, but is

highly localized within the spill area

In one large scale field trial, a rapid phase transition may have

ignited the evolved vapours


An Example of Rapid Phase Transition
http://www.youtube.com/watch?v=h-EY82cVKuAhttp://www.youtube.com/watch?v=h-EY82cVKuA


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Loss of containment leading to the formation of LNG liquid pools can also be

caused by a phenomenon called rollover

LNG rollover refers to the rapid release of LNG vapours from a storage tankcaused by stratification. The potential for rollover arises when two separate

layers of different densities (due to different LNG compositions) exist in a tank

In the top layer, the liquid becomes warmer due to heat leaking into the tank and

rises up to the surface, where it evaporates

Lighter gases are preferentially evaporated and the liquid in the upper layer

becomes denser. In the bottom layer, the warmed liquid rises towards theinterface by free convection but does not evaporate due to the hydrostatic head

exerted by the top layer

The lower layer becomes warmer and less dense

As the densities of two layers approach each other, the two layers mix rapidly,

and the lower layer which has been superheated gives off large amounts of

vapour as it rises to the surface of the tank Rollover is thought to be more likely if LNG nitrogen content is high

For FLNG, rollover is unlikely to present a problem since sloshing due to sea

state motions ensures mixing of tank contents



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LNG Tank Rollover




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The main hazard arising out of a rollover accident is the rapidrelease of large amounts of vapour leading to potentially hazardous

situations. It is also possible that the tank pressure relief system is

not able to handle the rapid boil off rates, and as a result the storage

tank will fail and lead to the rapid release of large amounts of liquid

LNG forming a liquid pool.

LNG operators avoid rollover by carefully monitoring the

compositions, temperatures and densities and by keeping tank

contents well-mixed using mechanical means such as pumps to

circulate the liquid




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LNG specifications are applied for different reasons:

Many of the specifications applied to LNG are relevant for the

liquefaction/transportation/regasification processes and are commonthroughout the industry. Examples are specifications for mercury, nitrogen,

water, CO2, C5+, aromatics

Other specifications are concerned with the end use of regasified LNG and are

related to pipeline specifications or the design of gas burners in the receiving

country. Examples are heating value, wobbe number, NGL/LPG content,

sulphur/H2S Receiving terminals may import LNG outside of the normal specifications (such

as heating value) but then must modify the properties in the receiving terminal

so that the gas will be suitable for in-country use. For instance to reduce

heating value, LPG components may be extracted (before regasification) or

nitrogen may be added (after regasification). To increase heating value, a

terminal may be equipped to spike the LNG with LPG in order to raise heatingvalue

Other specifications common for pipeline gas such as dewpoint are not of

concern since the liquefaction process requirements are far more stringent

than pipeline specifications



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LNG Specification for facility design:

An LNG specification is provided for design of the facilities, usually

in the Basis of Design. The design contractor must guarantee that

facilities, when built, can meet the specification

The gas treating facilities must be designed to meet the

specification for contaminants such as CO2, sulphur compounds,

water and mercury, taking account of the feed gas composition

envelope

The process design for the liquefaction facilities must ensure that

LNG can be produced to meet the specifications for properties

such as heating value and compositions of hydrocarbon

components and nitrogen

The heat and material balances and high level process design tomeet the liquefaction process requirements are usually carried out

by the liquefaction process licensor such as APCI or

ConocoPhillips


LNG P i d S ifi i


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LNG Specifications for Sales Contracts:

LNG specifications are also provided in LNG sales contracts,

usually referred to as SPAs. These specifications are contractually

binding and failure to meet them may result in refusal to accept an

LNG cargo, or may incur a financial penalty.

The LNG export facility may have separate SPAs with a number of

different customers, so it is important that the specifications in

each of these agreements should be compatible with thespecification provided for design of the plant.

Since the marketing department of a company is often separate

from the project design department, this is not always

straightforward.

In addition to specifying the allowable ranges for LNGcompositions and properties, the SPA will typically also specify

calculation methods or international standards to determine exactly

how the properties will be calculated


LNG P ti d S ifi ti


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Sample LNG specification for a typical liquefaction plant

High Heating Value (ideal) 1050 - 1150 BTU/ Scf

Composition

Nitrogen 1.0 % mol maximum

Methane 85.0 % mol minimumButanes and heavier 2.0 % mol maximum

Pentanes and heavier 0.1 % mol maximum

Impurities

Hydrogen Sulphide 5.0 mg/Nm3 maximum

Total Sulphur 30 mg/Nm3 maximum



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Examples of LNG Characteristics (from GIIGNL)



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Opportunities / Advantages of FLNG

World Energy Outlook (International Energy Agency)

The share of natural gas in the global energy mix increases from 21% to 25%

in 2035, pushing the share of coal into decline and overtaking it by 2030

Trade between the main world regions more than doubles, with the increase of

around 629 bcm split evenly between pipeline gas and Liquefied Natural Gas

An increase in production equal to about 3 times the current production of

Russia will be required simply to meet the growth in gas demand by 2035

All predictions are for natural gas usage and LNG trade to grow substantiallyover the coming decades. With recent developments, it seems increasingly

likely that FLNG will become a major contributor to the predicted increases in

LNG trade and production



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Drivers for FLNG

Proven technology is available (although building an LNG plant on a floating

platform still involves novelties and challenges)

A floating LNG vessel is potentially re-deployable (although modifications

may be required when feed gas composition varies significantly - a fully

flexible design to accommodate all feed gas compositions is not practical)and therefore may be viable for smaller gas reserves

Cost effective way of monetising smaller and more remote gas reserves

Cost savings can be realised e.g. by eliminating long subsea pipelines,

offshore processing and compression

Potential to avoid problems with land-based LNG plants such as land

access, delays in obtaining permits, eliminating need for new infrastructure

and influx of construction workers when the LNG plant is in a remote

location



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Some of the factors likely to be critical for success of the first FLNGventures are:

Combination of LNG knowhow, FPSO experience and LNG shipbuilding

expertise e.g. Shell/Technip/Samsung or Linde/SBM/Daewoo

Recognition of novel aspects (risks); willingness, methodology and

knowhow to address them

Research and design development to address novel aspects such as

effect of motion on LNG equipment, LNG offloading at sea

Financefinancial backers are harder to find until the technology

application is regarded as proven



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Offshore Considerations and Challenges

LNG plants are relatively complex to operate and maintain, and doing this

in a marine environment with less available space adds additional

complexity Motion of the FLNG carrier due to sea state makes operation and

maintenance operations more difficult, e.g. working on rotating equipment

and other machinery with precise tolerances

Emergency operations such as fire fighting become more difficult in a

floating environment

A marine atmosphere can be more corrosive for equipment and pipework

(including stress corrosion cracking), though this is already well-known

since many LNG plants are located in tropical coastal environments

Compared with onshore LNG plants, staff live and work in a relatively

confined space

Escape and evacuation procedures and drills are more complex and

assume more importance compared with onshore plants

Major turnaround maintenance may require additional accommodation for

maintenance personnel e.g. separate floating accommodation vessels


Off h C id ti d Ch ll


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Offshore Considerations and Challenges

(according to TOTAL)

The challenges of floating LNG (FLNG) derive mainly from the need to fit process

operations that typically have a very extensive onshore footprint into a small space

offshore. This raises numerous issues, especially with regard to:

The size of the FPSO,which must have room to accommodate the gas production,

processing and liquefaction facilities as well as living quarters for a crew of 200 to 300

people. However, due to economic considerations as well as construction constraints,

its dimensions must be as compact as possible

Integration, because the space limitations of a floating plant dictate a specific process

layout that requires some stacking of equipment. Installing the production facilities on

deck and the LNG storage in the hull of the vessel creates some architectural

challenges as well

Marinisation of equipment,because process installations must be designed to

withstand wave action. This is especially important to ensure proper processing of the

gas prior to liquefaction, as the feed gas for the liquefaction process must comply with

stringent specifications

Safety, because the close proximity of process units - and above all the living quarters

just adjacent to them - make safety issues even more acute than for an onshore plant.

Safety is also a central focus when it comes to offloading the LNG onto methane

carriers, and innovative transfer systems are being developed for this context


FLNG Training Module 1.1 Introduction to FLNG Rev 1

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