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PETRONETPETRONET LNG LTD
A Project Report Submitted in Partial Fulfilment of the
Requirements for the Degree of
BACHELOR OF ENGINEERING
IN
CHEMICAL ENGINEERING
By:
Jalaj Sharma Drigansh Kumar
Pranshu Singhal Akshit Bedi
University Institute of Chemical Engineering & Technology
Panjab University, Chandigarh
4th June, 2012 - 13th July, 2012
MASS BALANCE AND ENERGY BALANCE CALCULATIONS
ACROSS THE 10 MMTPA LNG TERMINAL.
&
PRESSURE DROP AND PUMP HEAD CALCULATIONS FOR
THE 10 MMTPA LNG TERMINAL.
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ACKNOWLEDGEMENT
Apart from ones own effort, the success of any project dependslargely on the encouragement and guidance of many others. We
take this opportunity to express our heartfelt gratitude to the
people who have been instrumental in the working and successful
completion of this project.
We would like to show our greatest appreciation to our mentors
Mr. Shailesh K. Patel and Miss Geetanjali Tomar, for their
tremendous support and help. Without their encouragement and
guidance this project would not have materialized.
We would also like to thank Mr. Sanjay Kumar, Mr. Jeegnesh
Balsara, Mr. Rajat Kumar Sen, Mr Avinash, Mr. Arjun Rathi, Mr.
Bhola Nath, Mr. Aditya Mahajan, Mr. Hardeep Singh Rekhi for
sharing their expertise in their field and enlightening us with their
vast knowledge.
It was a privilege to understand the operations at the company
and we express our gratitude towards PETRONET LNG LTD for
providing us with an opportunity to undergo this training.
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CONTENTS
S.NO. TOPIC PAGE NO.
1. About LNG 5
2. Properties of LNG 7
3. About Petronet LNG 10
4. About LNG Terminal at Dahej 13
5. Global and Indian Energy Scenario: At aGlance.
And Recent Gas Scenario in the World
15
6. Natural Gas Scenario in India 22
7. Process Flow Diagram 49
8. Process Description
a)Main Facilities
b)LNG Unloading System
c)LNG Storage System
d)LNG Send Out System
51
9. Process and Instrumentation Diagram 50
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10. Key Systems of the Plant 51
11. General Safety Practices
a)Personnel Safety
b)Safety Practices
c)Detector Systems
d)Emergency Shutdown System
58
12. Mass and Heat Balance
a)Introduction
b)Calculations
61
13. Pressure Drop Calculations 79
14. Bibliography 110
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ABOUT : LNG (LIQUEIFIED NATURAL GAS )
Liquefied Natural Gas (LNG) is made up, for the most part, of methane (CH4),
which accounts for 75 per cent to 95 per cent of its volume. Natural gas is
colourless at ambient temperature and it is also odourless and nontoxic. The
extremely low temperatures of LNG make it a cryogenic liquid. Generally
substances which are at -100 0C or lower are termed as cryogenics.
Natural gas can be obtained from three different sources:
On and off shore reservoirs, which are mainly gas bearing (non
associated gas);
Condensate reservoirs, and
Large oil fields (associated gas).
Natural gas contains smaller quantities of heavier hydrocarbons, in addition
to varying amounts of water (H2O), carbon dioxide (CO2), hydrogen sulfide
(H2S), nitrogen (N2) and other non-hydrocarbon substances. Gas composition
will vary depending on its geographical origin.
Table.1 below provides an example of how gas composition can vary.
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Typically, most gas today considered for liquefaction has less than 100ppm
H2S, 5% CO2 and 5%N2. Before liquefaction can occur H2S and CO2 must be
removed. This process is generally referred to as gas sweetening. In
addition, depending the commerciality of this gas, natural gas liquids(ethane + hydrocarbon components C2+) are extracted to desired level. This
level can range from 75% to 94% C2+ recovery.
After natural gas has been prepared for liquefaction, it is liquefied for
shipping at a temperature of approximately -160C. By liquefying the gas its
volume is reduced by a factor of 600, which means that LNG at -160C uses
1/600 of the space required for the same weight of gas at ambient
temperature. Figure 1 briefly describes the sequence of operation in LNG
liquefaction plant.
LNG is a clear liquid, much lighter than water, with density between 430
520kg/m3.A mixture of 5% to 14% of methane gas in air can ignite when in
contact with a spark or naked flame.
When the liquid is loaded onto a ship, it immediately starts to boil, or return
to vapor form as it warms up by cooling the ships containment system and
form heat leakages through the tank insulation. The lighter components,
having lower boiling point, vaporize first. Nitrogen, although having a higher
molecular wt. than methane has a lower boiling point and forms a large part
of the initial boil-off gas.
The vapor phase of a tank can include up to 50% or more nitrogen in the
initial hours after loading, depending on the composition of LNG. This is
important because, on the LNG tankers, boil-off vapor is used as fuel in the
ships boiler. In this case the usable combustible gas is reduced by nitrogen
content and the combustion control systems must be designed to take this in
account. Evaporation at different rates means that the gas delivered at the
end of the voyage has a slightly lower proportion of nitrogen and methane
than when loaded and a higher proportion of ethane, propane and butane.
When LNG is exposed to ambient temperature, as in the case of a leak, it
vaporizes quickly. At liquid temperature the gas is 1.4 times heavier than air,
but, as it becomes warmer, its density decreases, reaches .55 times that of
air at ambient temperature.
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PROPERTIES OF LNG:
LNG is a cryogenic liquid. Cryogenic liquids are those at temperatures
colder than -73C at atmospheric pressure, LNG boils at approximately
-162C. Other common cryogenic liquids are hydrogen, oxygen, helium and
nitrogen.
LNG is composed primarily of methane; thus, its physical chemical
properties are similar to methane. LNGs properties vary slightly as theamounts and types of non methane compounds in it vary. Properties of LNG
that have safety implications include auto ignition temperature and ignition
energy, heat of vaporization, boiling point, flammability limits, heat transfer
rate of boiling liquid and density and specific gravity. Each of these
properties of methane and LNG is discussed below along with the relation of
property to safety and fuel use.
LNG may weather (become enriched with heavier hydrocarbons) as the LNG
in storage boils off. The boil off is virtually methane and nitrogen, leaving
behind the heavier hydrocarbons. Although weathering can lead to
significant increases in the proportion of heavier hydrocarbons in LNG, it is
important to note that the enriched liquid remains fully mixed, that is a layer
of heavier hydrocarbons doesnt form at the bottom of the tank.
In addition to the amount of LNG vapor removed, other factors that affect the
significance of weathering include the percentage of heavier hydrocarbons in
the initial LNG. LNG with very low amounts of heavier hydrocarbons (i.e. less
than 1%) should require a greater percentage of vapor removal to undergo a
significant weathering. Weathering is also not an issue when pure liquid
methane is considered.
Auto Ignition Temperature
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Auto Ignition temperature is the lowest temperature at which the gas
should ignite without a spark. The auto ignition temperature of LNG varies
with composition.
As the composition of heavier hydrocarbons in LNG is increased, the auto
ignition temperature is lowered. The average auto ignition temperature forpure methane at atmospheric pressure is 537C.
Boiling Point
At sea level atmospheric pressure, LNG boils at -161C. An increase in
storage pressure raises the boiling point.
Flammability Limits
Burning of fuel requires an ignition source and proper concentration of
fuel and oxygen. When the fuel concentration exceeds its upper flammability
(UFL), it cannot burn because insufficient oxygen. When the fuel
concentration is below its lower flammability limit (LFL) it cannot burn
because insufficient fuel.
Flammability limits of fuel is based on the percentage of oxygen in air (21%
oxygen). The lower and upper flammability limit of methane in air is 5% and
15% by volume respectively. In a closed tank, the percentage of methane is
100% thus, it cannot ignite. Methane leaking from a tank ventilated area is
likely to rapidly dissipate to less than 5%. Because of this rapid dissipation,
only a small area near the leak would have the proper concentration for
ignition. In a closed, purely ventilated the chance of collection enough fuel in
air for ignition increases significantly.
The heavier hydrocarbons have lower flammability limits than methane
causing the lower flammability limit of LNG to decrease with increased
concentration of heavier hydrocarbons.
LFL UFL
15%5% LNG concentration in Air ( v/v
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Density and Specific Gravity
Density is a measurement of mass per unit of volume and is an
absolute quantity. Because LNG is not a pure substance the density of LNG
varies slightly with its actual composition. The density of LNG falls between
430 kg/m3 and 470 kg/m3.
Specific gravity is a relative quantity. Specific gravity of a gas is the ratio of
the density of that gas to the density of air at 15.60C. Any gas with the
specific gravity less than 1 is lighter than air(buoyant) and on the other hand
any gas with a specific gravity greater than 1 is heavier than air (negativelybuoyant).
The specific gravity of methane at ambient temperature is 0.554, therefore it
is lighter than air and buoyant.
Under ambient conditions LNG will become a vapour. As it vaporizes, the cold
vapours will condense the moisture in air often causing the formation of a
white vapour cloud until the gas warms, dilutes and disperses.
Flame Temperature
LNG has a very high flame temperature. Simply stated it burns quickly and ia
a better heat source than gasoline. The methane in LNG has a flame
temperature of about 1,330oC, in comparison to gasoline which has a flame
temperature of 1,027oC.
The physical properties of various cryogenics have been tabulated as under:
Table 2. Physical Properties of Common Cryogens*Components Boiling
Point (K)
Liquid-
to-gas
Expans
ion
Ratio
Gas
Specif
ic
Densi
ty
Critical
Temper
ature
(K)
Critic
al
Press
ure
(atm)
Liquid
Densi
ty
(g/l)
Explosi
ve/ fire
danger
Air -- -- 1.00 -- -- -- No
Argon 87.3 860 1.39 150.9 48.3 1402 No
CO 2 194.7 790 1.70 304.2 72.8 1560 No
He 4.2 780 0.14 5.2 2.2 125 No
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H 2 20.3 865 0.07 33.0 12.8 71 Yes
N 2 77.3 710 0.97 126.3 33.5 808 No
O 2 90.2 875 1.11 154.8 50.1 1410 Yes
LNG 111 600 0.6 154.5 49.7 430-
470
Yes
ABOUT : PETRONET LNG LTD
The government has chosen Petronet LNG Limited (PLL) with Gaz de France
as an equity holder, to set up LNG receiving terminals in India .Petronet LNG
is at the forefront of India's all-out national drive to ensure the country's
energy security in the years to come.
Formed as a Joint Venture by the Government of India to import LNG and set
up LNG terminals in the country, it involves India's leading oil and natural
gas industry players. Our promoters are GAIL (India) Limited (GAIL), Oil &
Natural Gas Corporation Limited (ONGC), Indian Oil Corporation Limited(IOCL) and Bharat Petroleum Corporation
Limited (BPCL).
The authorized capital is Rs. 1,200 crore
($240 million). The break up of the
shareholding of the company is as follows:
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PLL shall, after importing the natural gas in liquid form, regasify it in its own
terminal and supply to the off takers, at which point, GAIL has the obligation
of a 60 % off take followed by IOC (30%) and BPCL (10%).
Petronet LNG Limited, one of the fastest growing world-class companies inthe Indian energy sector, has set up the country's first LNG receiving and
regasification terminal at Dahej, Gujarat, and is in the process of building
another terminal at Kochi, Kerala. While the Dahej terminal has a nominal
capacity of 10 MMTPA [equivalent to 40 MMSCMD of natural gas], the Kochi
terminal will have a capacity of 5 MMTPA [equivalent to 20 MMSCMD of
natural gas.
The regasified LNG from Dahej LNG terminal will replace a large volume of
liquid fuels. It is supplementing one third of existing indigenous gas supply in
order to meet the deficit of natural gas for the core sectors of economy likepower, fertilizer and other industries.
Setting up of Petronet LNG was the first step in liberalizing and
commercializing the LNG segment of the Indian gas industry, and
encouraging the use of a clean, environmentally friendly fuel. PLL has
demonstrated that the successful importation of LNG at competitive prices is
possible, thereby supporting the liberalization of the gas sector and
enhancing the level of private sector participation in the energy sector. PLL
has demonstrated the high standards of performance that can be achieved
by a modern, well-run public-private partnership managed on a commercialbasis. PLLs business success has been excellent due to lower-than-expected
operating expenses and interest costs. Further, PLL has demonstrated that
the use of LNG technology is feasible in India. Petronet LNG is in the process
of commissioning its second LNG regassification Terminal at Kochi.
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ABOUT :LNG TERMINAL AT
DAHEJ (GUJARAT), INDIA
LNG TERMINAL,DAHEJ under construction
Petronet LNG Ltd. set up Indias first LNG Receiving and Regassification
Terminal at Dahej, in the Gulf of Cambay, Bharuch District, in the state ofGujarat on the west cost of India which is also the first LNG terminal in South
Asia. PLL is in the process of commissioning another terminal at Kochi in
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Kerala with the capacity of2.5 MMTPA by December 2012.
LNG Terminal, Dahej
MajorLNG import terminals in India
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Including the Petronet-promoted Dahej project, in Gujarat, the west coast ishome to eight of the 12 importprojects under consideration (see Table 1).The western region is home to about 60% of the countrys chemicalsandfertiliser plants and a significant number of gas-fired power plants are underconsideration in the western states.Gujarat could be home to not only four of
the eight terminals, but has also made significant advances in developingalocal gas pipeline network.
The Dahej LNG Terminal, which occupies 55 Hectares (Ha) of land, was
initially commissioned to handle a nominal capacity of 5 MMTPA initially,
which is equivalent to 20 MMSCMD of natural gas, with a provision for
expansion up to 10 MMTPA. The expansion of the terminal took place in 2009
and now operates at a capacity of 10MMTPA which is equivalent to 40
MMSCMD of natural gas.
Natural Gas from this terminal is being distributed to consumers through a
pipeline from Dahej to the Vijaipur, which runs parallel to the existing HBJ
Pipeline from Vemar (84 KM from Dahej). The terminal is currently supplying
Regasified LNG, which is being marketed in the States of Gujarat,
Maharashtra, Madhya Pradesh, Rajasthan, Uttar Pradesh, Delhi, Haryana and
Punjab through the HBJ Pipeline network. The marine facilities for Dahej
Terminal includes a 2.4km long all weather Jetty. The receiving, storage and
regassification facilities include unloading arms, four tanks of 148,000m3
capacity each, vaporization system and utilities and off-site facilities. A
second jetty is to be constructed at the terminal whose commissioning shallbegin in August 2010.
PLL has signed LNG Sale and Purchase Agreement (SPA) i.e., take-or-pay
agreement for 25 years with RasLaffan Liquefied Natural Gas Company Ltd.
(Ras Gas) Qatar, a joint venture between Exxon Mobil and Qatar Petroleum,
for the supply of LNG to India on FOB Basis. The first cargo of LNG from
RasGas was received at Dahej LNG Terminal on January 30, 2004. Dahej
Terminal commenced gas supplies to its off takers (GAIL, IOC and BPCL)
on 29th Feb 2004 and after the commissioning of the gas pipeline,
commenced commercial operations from 1 st April, 2004.
GAIL (India) Limited, one of the Promoters-cum-Off takers shall be the
sole transporter of the entire quantity of Regasified-LNG available. The
other off takers of regasified LNG viz. IOCL and BPCL will use the
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pipeline of GAIL (India) Limited by executing Gas Transmission
Agreements.
PLL signed Time Charter Agreements with the Consortium (Ship owners) ledby M/s Mitsui OSK Lines Limited of Japan, two LNG Tankers of 138,000 cu.m
capacity each, and one LNG Tanker of 155,000 cu.m capacity for
transportation of 7.5 MMTPA LNG from RasGas, Qatar to LNG Terminal at
Dahej, Gujarat for a period ending 30th April 2028.. The other members of
the consortium are NYK Line & K line of Japan, The Shipping Corporation of
India Limited and Qatar Shipping Company.
The first LNG Tanker - DISHA (138,000 cu.m) has been delivered on 9th
January, 2004 followed by second LNG Tanker - RAAHI (138,000cu.m) on
16th December 2004 and the Third LNG tanker Aseem (155,000 cu.m) on16th November 2009.The tankers have been constructed by Daewoo
Shipbuilding and Marine Engineering Company (DSME), South Korea. The
engineering procurement and construction (EPC) contract has been awarded
to The IHI (Ishikawajima Harima Heavy Industries) Consortium, consisting of
IHI, Toyo Engineering India Ltd (TEIL) and BallestNedam International (BNI).
PLL has selected M/s Foster Wheeler Energy Limited, UK as the Project
Management Consultant (PMC) who is responsible for regular review,
monitoring and assisting the Company and its project Management
Team in implementation of the project at the site.
THE GLOBAL AND INDIAN ENERGY
SCENARIO: At a Glance
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As of 2011, the demand for oil and conventional coal has increased
considerably since 2006, but demand for natural gas has grown by almost50%. Despite the scientific interest in fusion energy, including importantresearch by the Chinese, the process is still seen to be a very long way off.
Overall, global energy use has grown by over 36% since 2005. Conventionaloil supply has grown at a much slower pace (17%), so it is losing its marketshare. However, note that oil from tar sands has grown rapidly and nowsupplies over 2% of the worlds total.
Conventional coal has also grown more slowly than the total (15%) andhence has lost share, although the new coal processes such as liquefaction
and gasification have grown rapidly and now make up about 3% of the total.Not only has natural gas grown greatly, but it is now contributing an amountof energy that is of the same magnitude as coal and oil.
Nuclear (fission) and hydro continue to supply significant amounts, about5% of the total. All of the other so-called promising renewables are stillwaiting in the wings. One spot that is a bit brighter than the rest is terrestrialsolar energy.
Although space solar projects have foundered, terrestrial solar energy hasgrown. The questions about space solar resulted from high anticipated costs,
uncertainty about the technology, and the unproven net energy balance ofthe scheme. (There is some suspicion that pro-oil interests have engaged inanti-space power lobbying.) Yet terrestrial solar (photovoltaics, solar thermal,and solar power towers) is now approaching a healthy 1% of the worldsenergy supply.
Ethanol is a particularly important fuel and fuel additive. Of course, it comesfrom many sources: waste, cellulose, corn, sugarcane, palm oil, sweet
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sorghum, saw grass, and so on, so agricultural polices throughout the worldwere adjusted to encourage this renewable supply. Genetic research intonew, higher-alcohol-producing varieties was encouraged. Engine designswere altered to accept fuel blends in which ethanol (and other alcohols)represented a higher and higher percentage. Brazil, which was a prodigious
producer of sugarcane-based ethanol, became a major exporter of the fuel,and by 2010 half of its exports were going to Japan. The parade of ethanolexporters grew and, to mention a few, included Argentina, Australia, Centraland South American countries (such as El Salvador), Malaysia, Mexico, SouthAfrica, and Poland. As early as 2004, India established programs toencourage ethanol production.
The EU, with its huge agricultural production of sugar and grain, converted amajor portion of its surplus into fuels (Germany and France led in theproduction of biofuels). And to boost the possibility of a European biofuelsindustry, the EU introduced protective tariffs on imported ethanol. The U.S.
and other countries cried protectionism and created ethanol reserves. Anti-genetic modification attitudes in Europe were deeply ingrained andcontinued, and production of the crops needed for this embryonic industrywere lower than they might have been. The European countries opposinggenetic modification included Austria, France, Portugal, Greece, Denmark,and Luxembourg. With the emphasis on ethanol, world food supply becameimbalanced and hunger increased. There were brave experiments thatattempted to use marginal lands and brackish water for the production ofalcohol crops, but these added only marginally to the acreage. It seemedthat the world could not have both adequate food and expanded productionof alcohol grains. It was indeed business as usual.
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Table 1. Evolution of the World Energy Mix (Business as UsualScenario)
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Till 2011, all of the net growth took place in emerging economies, withChina alone accounting for 71% of global energy consumption growth. OECDconsumption declined, led by a sharp decline in Japan in volumetric terms,the worlds largest decline. The data suggests that growth in global CO2
emissions from energy use continued in 2011, but at a slower rate than in2010.Energy price developments were mixed. Oil prices for the year exceeded$100 for the fi rst time ever (in money-of-the-day terms) and infl ation-adjusted prices were the second-highest on record, behind only 1864. Crudeoil prices peaked in April following the loss of Libyan supplies. The differentialbetween Brent and West Texas Intermediate (WTI) reached a recordpremium (in $/bbl) due to infrastructure bottlenecks driven by rapidly-risingUS and Canadianproduction. Natural gas prices in Europe and Asia including spot marketsand those indexed to oil increased broadly in line with oil prices, although
movements within the year varied widely. North American prices reachedrecord discounts to both crude oil and to international gas markets due tocontinued robust regional production growth. Coal prices increased in allregions.
World primary energy consumption grew by 2.5% in 2011, roughly inline with the 10-year average. Consumption in OECD countries fell by 0.8%,the third decline in the past four years. Non-OECD consumption grew by5.3%, in line with the 10-year average. Global consumption growthdecelerated in 2011 for all fuels, as did total energy consumption for all
regions. Oil remains the worlds leading fuel, at 33.1% of global energyconsumption, but oil continued to lose market share for the twelfthconsecutive year and its current market share is the lowest in since 1965.
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As regards energy consumption, 16% of the global population in the OECDcountries, would consume, by the year 2030, more than 40% of energy andthe balance about 84% of the global population in the non-OECD areas wouldconsume a little less than 60% of the total energy consumed in the world. Nodoubt, during the period 2005 to 2030, the rate of growth of energyconsumption in the non-OECD countries would be higher than in OECDcountries and would vary between 1.3% in the Russian-Caspian area to 3.2%in the Asia Pacific areas, as opposed to the rate of growth of energy
consumption during this period in the OECD countries being in the range of0.6% in North America to 0.9% in the Asia Pacific region. Still as mentionedearlier, by the year 2030, 16% of global population would consume as muchas 40% of the energy and the balance 84% of the global population wouldconsume less than 60% of energy. Providing access to adequate energy totheir people is really a challenge for developing countries.
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(As of 2007)
India is one of the countries where the present level of energy consumption,
by world standards, is very low. The estimate of annual energyconsumption
in India is about 330 Million Tones Oil Equivalent (MTOE) for theyear 2004.
Accordingly, the per capita consumption of energy is about 305Kilogram OilEquivalent (KGOE). In the profile of energy sources in India, coal has a
dominant position.Coal constitutes about 51% of Indias primary energy
resources followed by Oil(36%), Natural Gas (9%), Nuclear (2%) and Hydro
(2%).
Indias energy demand is one of the fastest growing in the world, and energy
management is one of the countrys prime concerns. Recognizing this trend,
Government of India decided to form a group named India Hydrocarbon
Vision 2025, whose mandate included promoting the development and
use of natural gas- including Liquefied Natural Gas (LNG) and other
alternative fuels. The panels analysis recommended that 20-30% of total
gas imports be in the form of LNG.
India targets 9 10% economic growth rate in a sustainable manner over next
10-15 years. Adequate availability of energy would be sinequanon for this
objective to materialize. There are shortages in all the energy segments.
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Substantial expansion of capacities in coal, petroleum, gas and electricity is,
therefore, the thrust of the Government policies and programmes. Ultimate goal
is to develop these markets and facilitate, through various policy initiatives,
their matured functioning in a competitive manner. Skillful development of road
maps to reach the goal is a challenge. During the period of transition, therefore,
regulatory interventions to harmonize the interests of investors, developers andconsumers, is an approach, which is being pursued by various energy groups. In
most cases, development of energy sector, in various segments, has happened
under government-controlled organizations. Over last 10-15 years, private
investments are being encouraged, particularly in petroleum, natural gas and
power. While India is fully committed to develop and expand its energy markets,
it is equally committed to ensure environmental safeguards. Using latest cost
effective technologies in all the energy segments forms an important part of
policy and strategy
Recent Gas scenario in the World
As of 2011, World natural gas consumption grew by 2.2%.Consumption growth was below average in all regions except North America,where low prices drove robust growth. Outside North America, the largestvolumetric gains in consumption were in China (+21.5%), Saudi Arabia(+13.2%) and Japan (+11.6%).
These increases were partly offset by the largest decline on record in EU gasconsumption (-9.9%), driven by a weak economy, high gas prices, warmweather and continued growth in renewable power generation.
Global natural gas production grew by 3.1%. The US (+7.7%) recordedthe largest volumetric increase despite lower gas prices, and remained theworlds largest producer. Output also grew rapidly in Qatar (+25.8%), Russia(+3.1%) and Turkmenistan (+40.6%), more than offsetting declines in Libya(-75.6%) and the UK (-20.8%).As was the case for consumption, the EU recorded the largest decline in gasproduction on record (-11.4%), due to a combination of mature fields,
maintenance, and weak regional consumption.
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Following the generalweakness of gasconsumption growth, global
natural gas trade increasedby a relatively modest 4% in2011. LNG shipments grewby 10.1%, with Qatar(+34.8%) accounting forvirtually all (87.7%) of theincrease. Among LNGimporters, the largestvolumetric growth was inJapan and the UK. LNG nowaccounts for 32.3% of global
gas trade. Pipeline shipmentsgrew by just 1.3%, withdeclines in imports byGermany, the UK, the US andItaly offsetting increases inChina (from Turkmenistan),Ukraine (from Russia), andTurkey (fromRussia and Iran).
.
NATURAL GAS
SCENARIO IN
INDIA
Natural gas constitutes about 9% in the Indias energy profile, as comparedto about 25% world average
India had 38 trillion cubic feet (Tcf) of proven natural gas reserves as of
January 2007.The total gas production in India was about 31,400 mcm in
2002-03 compared with 2,358 mcm in 1980-81. At this production level,
India's reserves are likely to last for around 29 years; that is significantly
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longer than the 19 years estimated for oil reserves. Almost 70% of Indias
natural gas reserves are found in the Bombay High basin and in Gujarat.
Offshore gas reserves are also located in Andhra Pradesh coast (Krishna
Godavari Basin) and Tamil Nadu coast (Cauvery Basin). Onshore reserves are
located in Gujarat and the North Eastern states (Assam and Tripura)
In 2002, the supply of Natural Gas was 72 MMSCMD and demand, 151
MMSCMD, whereas this gap is projected to get widened, as the supply will
remain constant and demand is expected to increase further.
The share of natural gas in electricity generation in India, at 8% (see Figure
2), is significantly lower than in Europe (25%). Of the 41 gigawatts (GW) of
new generating capacity expected to come on line by 2005 about 20-22 GW
is likely to be combined-cycle gas turbine (CCGT) a considerable proportion
is either under construction or close to financial closure. In the longer term
(2005-2010), however, the contribution from independent power producers(IPPs) is likely to be overshadowed by state and central sector plans. Most of
the central sector plans are for non-gas-fired capacity, particularly ministry
of power plans to install 50 GW of hydro-electric capacity by 2015. Coal is
still a dominant part of the generation mix.
Power generation is expected to be the dominant driver of gas demand,
followed by the fertiliser sector. Industrial demand is expected to
demonstrate a more modest growth rate of about 3-4% a year, whileresidential and commercial consumption, predominantly in cities, could
begin provided the pipeline developments under way are sustained . In the
fertiliser sector gas already forms the bulk of the feedstock for urea
production. LNG would compete with naphtha, which is significantly more
expensive in India than gas, but still constitutes more than a quarter of the
feedstock mix. Fertiliser prices are subsidised and controlled by the
government and the industry claims that unless a delivered gas price of
$3/m Btu is achieved it does not make the switch from naphtha economic.
The removal of fertiliser subsidies, as with electricity subsidies to the
agricultural sector, is a delicate political issue and no dramatic changes are
expected.
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LNGs contribution to supplying the growing demand in the industriallyadvanced states of Gujarat, Maharashtra and Karnataka is expected to besignificant and gas grid development in these states may provide furtheropportunities. Additionally, all the major Indian private-sector partners inthese projects (Tata, Reliance and Essar) not only have significant
engineering capabilities and expertise in executing large infrastructureprojects, but are also potential buyers of the landed natural gas.
INDIA: GAS Consumption
About 45% of natural gas is consumed by power sector and about 40% by
the fertilizer sector. The balance 15% goes for various other consumption. At
present about 65 million cubic meters of gas per day is being consumed and
it has the potential for increase.
Both the Power Sector and Fertilizer Sector have been planning for largerconsumption of gas and increased capacities so as to produce more powerthrough this environment friendly fuel. However, the recent trends in gasprices globally has created a dampening impact on the power plant plannersboth from the point of view of lack of predictability about availability of this
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fuel and more so on account of lack of predictability of its price behavior. Inthe power sector, about 12,500 MW of capacity out of the 1,25,000 MW oftotal capacity is gas based combined cycle power plants. Because of lack ofavailability of gas, almost 35% of the capacity remains unutilized and theseplants then need to resort to naptha as a substitute fuel which is excessively
costly. Some of the power plants, which were planned and are in the processof being commissioned face the problem of non-availability of gas. There arecouples of LNG terminals in the country each with a capacity of 5 milliontones. Their capacities of processing LNG are not fully used in view of therecent excessive rise in the price of LNG, which has made it unaffordable forthe power producers to access LNG and use it in their power plants.
Some of the issues in the area of gas are as follows:
Power and Fertilizers sectors have been provided gas under theAdministered Price Mechanism in last over 20 years. Gas producers and
supplier desire market determined prices, which could be much higher.Consumers have been saying that when shortages are so acute andproducers and suppliers are few, there is practically no competition and,therefore, no market. In such a situation, till market develops to areasonable level, regulatory intervention could be essential. Obviously,there are differing schools of thought on this issue.
Huge resources of gas which have been discovered by Reliance Industry,ONGC, Gujarat Gas, Cairn Energy and others, when produced andsupplied, there will be greater clarity on adequacy of supply andpredictability of price. Till then power developers have adopted a dualapproach
for existing capacities of power plants where assets face asituation of idleness, a higher price for gas/LNG is accepted toutilize the existing capacities.
For new plants, they have decided to wait and watch to bebetter aware of the ground reality, may be in next 2 years orso.
Gas discoveries in KG Basin and in some of the Western Coast areas havecreated a positive impact. It is expected that these discoveries whenexploited - and it is targeted that some time in the year 2008, asubstantial amount of production would flow from the KG basin, powerplant developers and those in the Fertilizer Sector and other areas couldexpect to get larger amount of natural gas. If there is predictability aboutits price, it would be possible to enhance the present projection of gasbased power capacity to a higher level.
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Domestic reserves will obviously not be sufficient. Gas supply will need tobe supplemented through LNG import with appropriate enhancement ofLNG Re-gasification facilities.
It will require creativity on the part of all stakeholders to build a vibrant gas
market in India. The global gas majors can help by transferring best practice.Similarly, the traditional Indian energy PSUs may have to demonstrate moreflexibility. But success at Dahej shows the Indian oil and gas industries canwork together, with multinational energy companies and with the regulatoryand administrative bodies. The development of the pipeline grid in Gujaratstate should provide the impetus for similar structures to evolve, particularlyin the states with significant industrial infrastructure.Indias political and administrative system has played an important, andsupportive, role, but more must happen and faster. If it does, the next fewyears could see the establishment of a strong and vibrant gas market.
LNG STORAGE AND
REGASSIFICATION TERMINAL
(PROCESS DESCRIPTION)
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LNG Regassification system can be broadly classified in three main areas-
LNG unloading system
LNG storage system
Natural gas send out system
The terminal is designed to handle 5 MMTPA LNG in phase I and 10 MMTPA
LNG in phase II. The facilities for phase I and II broadly consist of following:
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Process Flow Diagram
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LNG UNLOADING SYSTEM
The LNG Regassification terminal is connected to the jetty through a 2.433
Km long trestle which consist of pipe racks & vehicle transport facilities.
There is a Jetty control room for monitoring the jetty area operations. The
main parts of the Jetty are
LNG unloading arms
NG loading arms
Desuperheater
LNG Drain drum
Ship Mooring facilities (Dolphin And Fenders)
LNG unloading and BOG loading Operations
For LNG unloading from the ship, there are three identical 16
unloading arms [L-101A/B/C] are provided in the jetty area. One 16 NG
loading arm [L-102 A] also provided for return gas to ship. Arms L-101 A/C
are dedicated to liquid service, L-102 A for vapour service and L-101 B arm
to liquid or vapour service. So accordingly, three unloading arms in the
terminal unload the LNG and feed to the storage tanks by top and bottom
filling (depending on LNG density) into the tanks. During ship unloading, the
desuperheated natural gas of approximately -90C is supplied via ship return
gas desuperheated to compensate for displacement in the cargo tanks
through Natural gas loading arm. The draining liquid from unloading arm is
also collected. The desuperheated gas passes into drain drum for knocking of
the entrained liquid from which it flows to natural gas loading arm. Thedraining liquid from unloading arms are collected in drum is pressured to
unloading lines after the ship is fully unloaded.
After unloading is completed the safety measures have to be taken for ship
departure and unloading arms are disconnected from ship manifold. After
unloading is completed the recirculation operation must be carried out to
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keep the unloading lines in cold conditions. The circulation is carried out by
in tank pumps and LNG circulated is preferably send out to return line so that
any heat that has been picked up can be exported or otherwise it is returned
to the storage tanks and the heat gain produces additional BOG.
During unloading recirculation must be cut off. When LNG cargo transfer hasbeen completed, LNG unloading arms will be drained to LNG arms drain
drum V-101.N2 is purged to the apex of the arms which will assist in
evacuating the liquid from the unloading arm. LNG drained from unloading
drum is collected and pressurized by N2 to evacuate the LNG to unloading
lines. Upon completion of this LNG circulation throughout the unloading
headers will be established.
Parameters to be monitored during unloading operations are:
1. Tank Pressure
2. Unloading arm pressure and temperature
3. Quantity of LNG discharged in send out system
4. Pressure in loading line to the ship
5. BOG compressor pressure and temperature.
If shipside request for cooling of gas, Desuperheater has to be used.
Discharge of the BOG to the unloading line is through a 10 pipeline. This gas
passes into V-101 for knocking off the entrained liquid from which it flows to
the Natural gas loading arm. During purging operation N2 will be put into ship
tanks. However the amount of N2 required for this purging operation is
approximated to 50 m3 and this is approximately 0.04% of the cargo volume.
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Schematic Diagram of an Unloading Arm
Ship Return Gas Desuperheater
A desuperheater[E-108] comprises of a parallel arrangement of 2
MOVPs each namely MOVP-1310,1320,1330,1340. Its function is to reduce
the return BOG temperature from around 0-20C to an outlet temperature of
-87.70C. This is done so as to prevent thermal shock in the ship. It would
happen because as the LNG is continuously pumped out from the ship itwould create a vacuum which would shrink and collapse the ship. So to
maintain a pressure balance and avoid any disaster, BOG from the
desuperheater is pumped in the ship simultaneously as the LNG is pumped
out.
Ship Mooring and Berthing Operations
The berthing system enables both the ship crew and the shore staff toclose the monitor in advance of the docking operation right from the starting
point until the vessel is safely moored alongside the pier. A mooring system
is a comprehensive warning system that monitors not only the drift but also
the strain on the mooring lines and environmental data.
The marine facilities include four breasting and five mooring dolphins for
berthing the tankers and other equipment required for safe and reliable
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berthing. It also has nine QRMH (fitted on the Breasting and Mooring
Dolphins), one elevator-type Shore Gangway and two Digital Display Units for
measuring lateral distance and speed of the ship. A dolphin is an isolated
marine structure for berthing and mooring of
vessels. It is not uncommon that the combination of dolphins with piers could
drastically reduce the size of piers.
Dolphins are generally divided into two types, namely breasting dolphins and
mooring dolphins. Breasting dolphins serves the following purposes:
(i) Assist in berthing of vessels by taking up some berthing loads.
(ii) Keep the vessel from pressing against the pier structure.
(iii) Serve as mooring points to restrict the longitudinal movement of the
berthing vessel.
Mooring dolphins, as the name implies, are used for mooring only and forsecuring the vessels by using ropes. They are also commonly used near pier
structures to control the transverse movement of berthing vessels.
.
In view of the significant inter-tidal variations at Dahej port, the jetty isunique in design. The unusual bathymetry (i.e. nearly flat surface for quite
some distance and then suddenly large slope) has resulted in this long jetty.
The first 1.6 km is almost flat surface and then it suddenly slopes down.
At the deep end of the jetty, there is an unloading platform. For flexibility
considerations, all the unloading arms are identical. These are the most
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modern unloading arms, fitted with modern protective facilities such as
Powered Emergency Release Coupling (which disconnects the arms
automatically in the event of excessive ship movement).
PLL has also provided Mooring Tension Monitoring System, which provides
information in the control room and ship with respect to tension in the
mooring ropes, which enables the operator to take advance action. Also
provided are Wave and Current data recorders for necessary information on
weather data. Four constant tension shore-based winches are also fitted on
the mooring dolphins to provide additional facilities to ensure safe berthing
of LNG tankers.
A port craft jetty is also provided to berth the tug boats, pilot launch and
mooring crafts when these are not in use (i.e. when the ship is not there). An
electrical sub-station and Port Control Room are also provided. The Port
Control Room houses all facilities required for safe operation of the port arealike radar system, berthing aid system, etc.
On the approach trestle, there are two 32-inch dia pipelines for bringing in
the LNG from the tankers to the storage tanks. One 10-inch dia pipeline is
provided for carrying the return vapours to the LNG tanker. The pipeline has
eleven expansion loops that have been provided to take care of stresses that
are developed during the cooling down of the LNG pipelines. Four passing
bays are also provided on the approach trestle.
PLL signed Port Operation Services Agreement with the consortium of PSA
Marine (Pte) Ltd., Singapore and Ocean Sparkle Ltd., India (Public Limited
Company titled as M/s. Sealion Sparkle Port and Terminal Services (Dahej)
Limited). The Port Operator owns and operates Tug Boats, Mooring Boat and
Pilot Boat and undertakes safe towing, mooring & pilotage of the LNG
Tankers and maintenance of jetty facilities at Dahej LNG terminal. The pilots
engaged by Port Operator have thorough local knowledge and have
undergone simulation training for smooth, safe and efficient berthing for
larger Q Flex vessels also.
LNG Recirculation Operation
To leave the LNG stagnant in the lines is not permitted. Heat leak into
the line would cause vaporization which could result in unstable two phase
vapor liquid flow and cause vibration of these tanks. Circulation is always
kept by means of LNG in tank pumps and LNG circulated is preferably
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returned to the send out line so that any heat that has been picked up can
be exported. When this is not possible LNG is returned to the storage tanks
and heat gained produces additional BOG. LNG tank filling risers are
maintained full of LNG by a small flow through the bypass line. The
recirculation is cut-off before ship unloading operation. Thus the pressure in
the unloading line drops to the LNG column pressure of tank filling riser.
Then the unloading lines are in a static condition. Recirculation operation is
controlled manually at 400 m3/hr.
LNG Drain Drums
LNG drain drum is installed in jetty platform and works:
To collect the LNG arm drain during draining operation after everyunloading operation
To collect the mist downstream of ship.
During LNG unloading operation the pressure is maintained at ships cargo
tank pressure through NG arm. After completion of unloading Nitrogen Gas is
pressurized and the drain is send to the unloading lines. The volume of drain
is approximately 17m3. Unloading arms is drained by gravity and Nitrogen
Gas injection from the apex of the arms.
If temperature in drain drum is not in cryogenic condition, the drain liquidentering to the drum should be controlled manually to avoid rapid cool down
of drain pump. It should be minimum 4hr cooling operation. Drain drum is
equipped with a pump which sends the drain to the tanks through drain
return line. The pressure in the drum is maintained at the same pressure of
LNG tanks by 6 equalizing line. Thereby BOG generated in the drum is
routed to the LNG tank vapour space through equalizing line. When
maintenance is required drain is pressurized by Nitrogen Gas and send to the
process area LNG drain drum V-902.
All LNG discharges from thermal relief valves and LNG disposal system
excluding ones insulated on the jetty platform and trestle are collected inV-
903 through the drain collecting header installed in the process area.
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LNG STORAGE SYSTEM
Another important area in the LNG value chain is LNG storage facilities. This
is important because this facility is required at both the locations, i.e., at the
LNG liquefaction plant as well as the re-gas plant. LNG storage typically
accounts for approximately up to 5 10% of the total plant cost depending
on the design both in liquefaction and re-gasification
There are broadly two basic types of LNG storage tanks, one being above
ground, the other being underground. Almost all LNG liquefaction plantshave above ground storage tanks. The underground LNG storage tanks have
been used in Japan and Korea specifically with a view to achieve a high
degree of safety in densely populated area where land is at high premium.
The design of the above ground LNG storage tank basically varies depending
on the type of insulation used and the degree of fail safe passive
components included in the tanks. Different types of tanks used are single
containment, double containment, full containment, membrane tank. Full
containment type of tank is basically used in Petronet LNG Limited (Dahej
Terminal)
Full Containment Tank:
This design is basically consist of two complete LNG storage tanks in
one. The primary inner tank is constructed of 9% nickel steel and is
surrounded by an outer concrete wall with a thin 9% nickel steel insulated
inner which connects as a vapour barrier. The annular space between the
two tanks is filled with perlite insulations. The roof of the outer tank is
constructed of pre-stress concrete and is fully insulated. In the event of
inner tank failure, the outer tank is capable of containing both liquid and
vapour along tank, operation to continue increase in boil-off. The outer wall
may be reinforced concrete surrounded by earthen embankment or pre-
stress concrete to better withstand dynamic liquid forces. There is virtually
no possibility of liquid LNG spillage with this type of tank.
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Full containment above ground LNG storage tank
Decision of Bottom or Top Filling
This is done according to the comparative density of LNG stored in
tanks to that of cargo. LNG is send from the bottom line to tanks if cargo islighter and from the top if cargo is heavier to ensure proper mixing.
Roll Over Phenomenon
When high density liquid (A) is filled to the bottom of tank and low density
liquid is present in the upper side, Liquid (A) is now being subjected to heat
ingress from bottom and sides of tanks. Also the liquid(B) experiences heat
from the sides of the tank but the lower lying liquid (A) has far greater
incoming heat from below too. Moreover, due to the above lying liquid it also
experiences an increase in pressure. The intense pressure increases theenthalpy of the low lying denser liquid (A). This pressurized and high
temperature liquid experiences increase in volume, decreasing its density.
Simultaneously, the lighter liquid (B) is vaporizing from the surface to form
boil off gas because of heat from the sides of the tank. This happens because
the more volatile components i.e. nitrogen, methane etc escape above the
surface of liquid(B). This decrease in volume is causing its density to
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Liquid (B)
Liquid (A)
increase. This goes on for some time after which the lower lying liquids
density becomes just a little less than the above liquid. Immediately, the
liquid (B) rolls over to the bottom of the tank while liquid(A) surfaces up. But
the liquid (B) still has high enthalpy and instantly releases large amount of
BOG in the tank. It releases BOG about 90 t/hr, whereas the compressor
design load is 12 t/hr. This excess load will cause damage to the tank and is
therefore an undesirable phenomenon.
Counter Measure for Roll Over:
Tank recirculation with in tank pumps via the pump kick back line shall be
initiated if the maximum temperature difference exceeds 2C or if the
maximum density difference exceeds 1 kg/m3 to prevent roll over in tank.
BOIL-OFF GAS SYSTEM:
BOG Desuperheater
The vapor from LNG Storage tanks (T-101/-102/ [-103]/ [-104])
increases its temperature due to the heat leak into the tank roof and BOG
piping to BOG compressors. The temperature at E-102 inlet is estimated to
be approx. -148C during unloading operation and -138C during no
unloading. Therefore the desuperheating in E-102 is not foreseen during
normal operations. However if the tank pressure control (PIC1401) requires
Vaporization from the surface makes the
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the load selection below 25% load, in order to keep the continuous BOG flow
to the Recondenser, the compressor is required to operate with 25% load
and to circulate small amount of BOG. In this case, the Desuperheater (E-
102) needs to be operated.
In addition to the above, the vapor requires desuperheating prior to beingcompressed during the startup recirculation of the compressor for the
following purpose.
The discharge temperature is to be limited not to exceed the compressor
mechanical design temperature (approx. 150C) during startup. The
discharge temperature continues to be high until the compressor itself
becomes cold. Approx. 10min. recirculation is required with maintaining the
suction gas temperature cold.
The required desuperheating is achieved in the BOG Desuperheater E-102 byinjecting LNG from LNG In Tank Pump discharge.
Primary protection against the high outlet temperature is provided by
TIC1401 as an alarm from DCS(set at -80C).
BOG compressor suction drum
Suction knock out drum is provided downstream of the Desuperheater
to trap small droplet of liquid that may be carried from Desuperheater. It also
provides protection against accidental dumping of liquid in the compressor.
Bog Drain Pot
Regarding to liquid, operator manually drain BOG drain pot and is
pressurized by nitrogen gas to send the liquid into LNG tank through LNG
drain return header.
BOG compressor
There is large variation in the flow rate of BOG depending upon the
operation of terminal, with or without ship unloading. During no ship loading
2 to 4 t/hr and one compressor with 25% or 50% will be working. During ship
unloading operation, all three compressors at approx 31 to 35 t/ht will be
working. BOG compressor is operated with 25% and full bypass. BOG
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compressor cannot run with 0% load over 10 min for mechanical reason.
BOG compressor is shifted to 25% and bypass is done through the kick back
line. When BOG compressors are operated at less than 25% load, then
Suction line and cylinders of the compressor should be cooled down before
starting its normal discharge operation within ten minutes. The cool down
operation is carried out on 25% load to return discharge gas through
compressor kickback line to upstream of BOG Desuperheater. BOG, after
passing through the drain pot, reaches the low pressure side of the
compressor.The whole crank-piston-shaft apparatus is controlled by
compressor oil conducted in the central cylinder. After successively reaching
the lower cylinder, it enters the high pressure side at the same compressor
load. The cooled and compressed BOG is sent through the following three
ways:
1. The major portion is sent to the recondenser. From this, another by pass
line goes to the ship as return gas.
2. Sent as a kickback line back to the compressor so as to provide initial
startup momentum.
3. The excess BOG generated is rejected and sent to flare.
The diagram shows a double acting TWO STAGE AIR COMPRESSOR.
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BOG Compressor Loader Diagram
LNG SEND OUT SYSTEM:
LNG In Tank Pumps
LNG In Tank Pumps are vertical centrifugal pumps submerged in the
tanks. There are three per tank plus one pump well as a spare. A flow control
valve at the discharge end limits the maximum flow rate through each pump.
The protection against reduced flow is provided by automatic flow controlled
minimum flow bypass.
LNG in the tanks is pressurized by LNG In Tank Pumps up to the necessary
pressure to transfer the liquid to BOG Recondenser V-104 with operating
pressure of 7barg.
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LNG in the tanks is routed to V-104 to condense boil off gas. LNG In Tank
Pump discharging pressure is therefore floating, which could vary along the
pump performance curve.
LNG pumps shall not be started more than 2 times with a minimum of
5seconds delay between each attempt. After two attempts, a minimum 15minutes should be kept before next starting.
BOG Recondenser
The objective of the BOG recondenser is to condense the BOG from
LNG tanks. Recondenser is located between the LNG in tank pumps and LNG
HP pumps. The compressed BOG from BOG compressors and LNG from LNG
in tank pumps to condense the boil off gas and is routed to the condenser. Inthe tanks LNG is at its bubble point of approx: 140 to 240 mbarg. After
pumping up by LNG in tank pumps LNG is subcooled with respect to the
pressure of LP send out circuit. It is therefore capable of absorbing the heat
required for the condenser of the BOG upto the quantity when it reaches the
bubble point.
BOG gas is compressed by BOG compressors upto the operating pressure of
the recondenser. In the column filled by packing of the recondenser it is in
contact with LNG and is recondensed. LNG flow rate required to absorb BOG
is taken from the LP send out circuit. The bubble point pressure of themixture is below pressure in the column.
BOG recondenser also serves as a suction drum for HP pumps.
Normal operating pressure: 7barg
During unloading operation: 8 barg
If sufficient LNG flow to recondenser is not available, this result in increasing
of LNG tank pressure and flaring from LNG tanks through tank pressure relief
valve.
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LNG HP Pumps
LNG HP Pumps are required to pressurize LNG up to the pressure of the
send out pipe line network of the terminal (88.5barg (max.)). Regarding the
design pressure of the piping of HP LNG circuit from LNG HP Pump discharge
to the STV LNG Inlet flow control valves FV1610 to 1670, and the SCV LNGinlet flow control valves FV1700/1710, it is designed at 130barg for higher
pressure protection, which is higher than the shut off pressure of LNG HP
Pump (120barg). In the same way the tube side and NG outlet piping up to
isolation valve of STV and SCV is designed at 130barg for higher-pressure
protection.
Five LNG HP Pumps (out of which one spare installed) are provided to handle
the total send out flow set for Phase I and Phase II respectively. These are
vertical pumps mounted in a suction barrel. A throttle valve at the discharge
end limits the maximum flow rate through each pump. The protection
against reduced flow is provided by automatic flow controlled minimum flow
bypass.
The flow instrument FIC1510 (set at 160m3/h) in LNG discharge line
measures the flow rate of LNG HP PumpP-104A , and the kick back control
valve FV1510 is provided to maintain the required minimum flow for P-104A.
Thee primary protection against the excessive flow rate is provided by
discharge valve FV1511, which limits the maximum flow rate of the pump
(400m3/h : 120% of nominal flow rate) during the pump running.
The ultimate protection against thelower and higher flow rate is provided by
IAHH1510, IALL1510 ,which trips the pump. In the event of accidental
tripping of the pump the check valves SPV1510/SPV1511 in both the
discharging line and the kick back line are provided to prevent back flow to
the pump.When the pump is idle, discharge valve FV1511 is closed and LNG
is supplied from the suction piping for cooling. The vapor from the pump pot
is vented back to BOG Recondenser through the dedicated venting line. The
low liquid level in the pot is detected by LSL1510, which stops or prohibits
the pump.
Shell and tube vaporizer (STV)
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Vaporizers operating pressure is floating with the delivery gas pipeline
network which could vary between 70 to 88.5 barg. Heating medium for the
vaporizer is 36% glycol-water mixture. Glycol water is supplied to shell side
at top and bottom.
General Diagram for a Shell and Tube Vaporizer
The reason to provide the Glycol Water to top and bottom of the
exchanger shell in roughly equal amount and withdraw through a common
line in middle of unit is:
- To limit the ice formation on bottom side tube by supplying high
temperature fluid.
- To heat the NG as possible by low temperature heating fluid.
In this system, ambient air is used for heating medium, therefore the
supplied fluid temperature of heating medium is close to the outlet NG
temperature so counter current system cannot be applied for the system.
Air Heaters
Dahej is the first base load LNG plant in the world that uses unique
ambient air heater for regasification. This is a cost-effective and eco-friendly
process compared to conventional Open Rack Vaporisers (ORV) which uses
sea water as a medium for regasification .
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Here, 16 fans are introduced on the top of each vaporiser that forces air
inwards in a forced draft fashion.The incoming glycol water(36% by
weight) is heated by utilizing the latent heat of vaporization present in the
water vapour (moisture droplets) in air. This is, hence, the reason why this
moisture condenses down at the bottom in the form of water droplets due to
removal of this heat.
Glycol water is recirculated in closed loop and the heat is absorbed from air
heaters. The air heater consist of
8 numbers of fixed fans (FP fans)
8 numbers of variable pitch fans (VP fans ) for each vaporizer
In FP fans, the blades are fixed and in VP fans the blades can be rotated from
0 to 45.Depending on the send out load, the guide message will display the number
of FP fans to be operated. The VP fans automatically change the blade
rotation from 0 t0 45 . Low temperature overrides on NG outlet side at 0C
and on the Glycol Water side at 8 C are provided for inlet flow control valve.
The ultimate protection against low temperature of NG outlet and hence the
freezing of Glycol Water mixture is provided on NG outlet side which closes
MOVP.
High pressure override is provided on downstream of gas metering station.
The primary protection against high pressure is given on the upstream of gas
metering station which will shut off the gas send out by stopping all the LNG
HP pumps. PSV (130barg) provides ultimate protection. The low pressure of
the gas send out line is detected by PAL (at 65barg) on the downstream of
gas metering station.The energy optimization is achieved by the no of
operating fans for air heaters. Rupture disks (10 barg) are for ultimate safety
for the shell side.
Submerged Combustion Vaporizer (SCV)
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Submerged Combustion Vaporizers burn natural gas produced by the
terminal andpass the hot gases into a water bath containing tubular heat
exchanger where LNG flows. The froth produced by the combustion gas
increases the efficiency of heat transfer between the water and the LNG and
prevents ice from forming on the tube bundle. SCVs burn 1.2-1.5% of the
natural gas processed.
There are following three modes on which an SCV generally operates:
Co-generation Mode:This mode utilizes the recovered waste heat
released from the flue gases escaping from the Gas Turbine
Generators (GTGs) present in the terminal.
Gas Turbine Generators: It is a type of internal combustion engine. It
has an upstream rotating compressor coupled to a downstream turbine and
a combustion chamber in between. Energy is added to the gas stream in the
combustor where fuel is mixed with air and ignited. Gases passing through
an ideal gas turbine undergoes three thermodynamic processes.
These are
Isentropic compression
Isobaric combustion
Isentropic expansion
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Together these make up the brayton cycle. It is depicted in the diagram
below
Brayton Cycle
Burner Mode:This mode makes use of the heat released from
combustion of fuel, which in this SCV is natural gas to perform its
necessary operation.
Combined Mode : This mode is a combination of the above mentioned
two modes. The necessary energy is obtained from both the abovementioned sources in the two different modes.
In the phase I, depending upon the load, the combined mode or the co-
generation mode is operated. In phase II, the burner mode is generally used.
SCV units are provided and each unit has two kinds of heat source which are
hot water to be supplied from Co-generation power units and burner
furnished to itself. The inlet hot water temperature for SCV must be 40 C to
55C and return water temperature is 20C. If heat capacity of water isinsufficient then the balance heat is supplied by burner ignition. During
change over of SCV operation to other, check other SCVs water level, must
be at least minimum (1800mm). Then first start the blower of the required
unit and open the hot water inlet valve to the SCVs. Also parallelly close the
inlet valve of other unit.
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During initial start up of blower approximately 11 m3 of water must be
displaced through overflow. So to avoid the wastage of water, water level
should be considered at minimum level at changing over. Hot water is
supplied from Co-generation system at the temperature of 40C andreturned to it at balance temperature.
Metering Station
The purpose of gas metering station is to measure the quantity of gas send
out from terminal. The metering station consists of 3 metering runs out of
which one run is standby.
Online gas chromatograph system is provided for analysis of the sampling
gas taken from the upstream line of station. The gas flow is measured by
turbine meters, depending on temp, pressure and gas density for
compensation to get corrected gas values. The gas is exported to the gas
pipeline network at the battery limit pressure of 89 barg max at nominal
send out capacity of terminal.
Flaring
Terminal is equipped with one 30 common flare header interconnecting
process equipment and flare stack. One 10 main drain header connects
process equipment, unloading line, LNG drain drum and process area LNG
drain drum. The flare and drainage system is provided to collect and safely
dispose off discharges from control valve and PSVs. During normal operation
terminal does not produce any excess vapor for discharge excluding a small
purge to prevent air ingress to system. The flare system is sized for disposal
of vapor resulting from abnormal operation and emergency but does not
consider the occurrence of coincident unrelated relief discharge.
In the event of total power failure, the terminal is shut down and if any
unloading operation is stopped and BOG from the tanks and piping is routed
to flare. In the event of partial power failure, affecting only the BOG
compression system, BOG is again routed to flare and any ship unloading
may have to be reduced in rate. Sealing system and continuous purging of
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flare stack with fuel gas is provided at the end of flare header to prevent air
ingress.
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KEY SYSTEMS OF THE PLANT
Utility system:
Utility system in the plant is necessary for manufacturing various
reagants and components, required in the plant from time to time, namely:
1) Industrial and potable water.
2) Plant Air and Instrument air.
3) Nitrogen generation and distribution.
4) Glycol water/Air heater system.
5) Hot water system.
6) Chilled water system.
7) Diesel Oil system.
8) Cooling water system.
9) Nitrogen system.
10) Flare system.
11) Fuel gas system.
12) Sanitary water system.
To produce plant air, the 3 reciprocating compressors and 2 screw
compressors extract air from the atmosphere which is then cooled and
compressed to a pressure of 8 bar. This cooled plant air is either stored in 2
header tanks (as a system backup) or for moisture removal to produce
instrument air used for further reactions.
Nitrogen is produced in cryogenic distillation tanks, where low temperaturedistillation of atmospheric air takes place. Nitrogen is withdrawn as a side-
stream and diverted further for plant operations.
Utility section also comprises of a waste water treatment plant, where the
industrial water is processed to produce potable water.
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Distributed Control System (DCS)
This is a type ofautomatedcontrol system that is distributed
throughout a machine to provideinstructions to different parts of the
machine. Instead of having a centrally located
devicecontrolling all machines, each section of a machine has
its owncomputer that controls the operation. For instance, there may be one
machine with a section that controls dry elements of cake frosting and
another section controlling the liquid elements, but each section is
individually managed by a DCS. A DCS is commonly used in
manufacturingequipment and utilizes input and outputprotocols to control
the machine.
A DCS typically uses custom designed processors as controllers and uses
both proprietary interconnections and communications protocol for
communication. Input and output modules form component parts of the DCS.
The processor receives information from input modules and sends
information to output modules. The input modules receive information from
input instruments in the process (a.k.a. field) and transmit instructions to the
output instruments in the field. Computer buses or electrical buses connect
the processor and modules through multiplexer or demultiplexers. Buses
also connect the distributed controllers with the central controller and finally
to the Human-Machine Interface (HMI) or control consoles.
Pressure or flow measurements are transmitted to the controller, usually
through the aid of a signal conditioning Input/Output (I/O) device. When the
measured variable reaches a certain point, the controller instructs a valve or
actuation device to open or close until the fluidic flow process reaches the
desired setpoint. Large oil refineries have many thousands of I/O points and
employ very large DCSs. In the Dahej plant, an I/P covertor is used whichtransmits current signals in range of 4-20mA to pressure difference at valves
in the plant. Processes are not limited to fluidic flow through pipes but to also
other purposes.
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GENERAL SAFETY PRACTICES
A. Personnel Safety
1. Face shields and goggles shall be worn during the transfer and
normal handling of cryogenic fluids.
2. Loose fitting, heavy leather, or other insulating protective gloves
shall be worn at all times when handling cryogenic fluids. Shirt sleeves willbe rolled down and buttoned over glove cuffs, or an equivalent protection
such as a lab coat will be worn in order to prevent liquid from spraying or
spilling inside gloves. Trousers without cuffs will be worn.
B. Safety Practices
1. Cryogenic fluids must be handled and stored only in containers and
systems specifically designed for these products and in accordance withapplicable standards, procedures, or proven safe practices.
2. Transfer operations involving open cryogenic containers, such as
dewars, must be conducted slowly to minimize boiling and splashing of the
cryogenic fluid. Transfer of cryogenic fluids from open containers must occur
below chest level of the person pouring liquid.
3. Such operations shall be conducted only in well ventilated areas to
prevent the possible gas or vapor accumulation, which may produce an
oxygen-deficient atmosphere and lead to asphyxiation. The volumetricexpansion ratio between liquid and atmospheric nitrogen is approximately
700 to 1.
4. Equipment and systems designed for the storage, transfer, and
dispensing of cryogenic fluids shall be constructed of materials compatible
with the products being handled and the temperatures encountered. There is
no single source of information that will provide exact specifications and
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standards for cryogenic equipment. ASME Codes contains the majority of the
relevant information. The American Society of Testing Materials (ASTM)
handbook provides information concerning tensile strength of metals at
various temperatures and other relevant information. The Code of Federal
Regulations, provides some useful guidelines, although it only references
cryogenic vessels used in rail transportation. In each case, the design
specifications are left to the discretion of the designing engineer.
5. All cryogenic systems, including piping, must be equipped with
pressure-relief devices to prevent excessive pressure build-up. Pressure-
reliefs must be directed to a safe location. It should be noted that two closed
valves in a line form a closed system. The vacuum insulation jacket should
also be protected by an over-pressure device if the service is below 77
Kelvin. In the event a pressure-relief device fails, do not attempt to remove
the blockage; instead call EH&S immediately.
6. If liquid nitrogen or helium traps are used to remove condensable
gas impurities from a vacuum system that may be closed off by valves, the
condensed gases will be released when the trap warms up. Adequate means
for relieving the resultant build-up of pressure must be provided
C. Detector Systems:
LNG HANDLING IN PLANT
Primary Components:
Primary components include those whose failure would permit leakage of the
LNG being stored, those exposed to a temperature between (-510C) and (-
1680C) and those subject to thermal shock. Primary components include, but
are not limited to the following parts of a single-wall tank or of the inner tank
in a double-wall tank; shell plates, bottom plates, roof plates, knuckle plates,
compression rings, shell stiffeners, manways, and nozzles including
reinforcement, shell anchors, pipe tubing, forging, and bolting. These are theparts of LNG containers that are stressed to a significant level.
Secondary Components:
Secondary components include those which will not be stressed to a
significant level, those whose failure will not result in leakage of the LNG
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being stored or those exposed to the boil off gas and having a design metal
temperature of (-51C) or higher.
Safety required in plant against LNG
Jetty area
Transfer Area/ Transition Joint/ Pipes
Compressor
Storage Tank
Condenser
Hp pumps
Vaporizer
FGS SYSTEMComponents of Fire, Gas, Spill Detection & Prevention System are:
Fire , Gas , Spill detectors and Manual call points ( Break glass).
FGS PLC (ICS Triplex)
FGS HMI # 1,2& FGS printer.
Fire Prevention Mimic Panel.
Fire Detection Mimic Panel.
Inergen gas systems.
Building Fire detection system
FIRE GAS DETECTORS
The three prerequisites for fire to happen are ignition source, air (oxygen)
and a source of fuel. This is known as the fire triangle:
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Fire Triangle
The fire in the plant is extinguished by means of three processes which are:
Cooling
Smothering
Starvation
These are used to kill a fire by by attacking different points of the fire
triangle respectively. Cooling is used to cut off the ignition source, while
smothering means to cut off the oxygen supply to fire. Finally, starvation
removes the combustible matter that is causing the fire.
Namely, water type, foam type and DCP type fire extinguishers are used to
extinguish the fire.
The features of fire gas detectors are:
Two radiation sources necessary for alarm
Field of view of up to 120 degrees
Explosion-proof, Class I, Division 1 certified
Connect indoors and out, directly or up to 2000 feet away
Immune lightning, arc welding, sunlight and hot body radiation
Adjustable, no-tool swivel mount
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User programmable sensitivity and time delay settings
Multi-coloured, high intensity LEDs
Manual and automatic testing of optical surfaces
Watchdog timer monitors internal electronics
Multiple output configurations
FIRE WATER SYSTEM:
PRESSURE : 15 BARG
Jockey Pump: P1003A/B ( 2 nos. One is kept running and the other is
on auto)
Start : 13 barg ; Stop : 15 barg ; Flow rate: 125 M3 /HR
Diesel Driven Pump : ( 4 nos. )
P1002A : Start 11.76 barg ; Flow rate : 1050 M3 /HR ;Stop Manually
in the field
P1002B : Start 11.27 barg ; Flow rate : 1050 M3 /HR; Stop Manually
in the field
P1002C : Start 10.78 barg ; Flow rate : 1050 M3 /HR ;Stop Manually
in the field
P1002D : Start 10.28 barg ; Flow rate : 1050 M3 /HR ; Stop Manually
in the field
Electrical Driven Pump : (2 Nos.)
P1001A : Start 9.80 barg ; Flow rate : 1050 M3 /HR ; Stop Manually
in the field
P1001B : Start 9.80 barg ; Flow rate : 1050 M3 /HR ; Stop Manually
in the field
Total water for fire fighting is 18000 m3 available in two fire water
tanks of 9000 m3 each
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The minimum amount of water available for fire fighting is 17000 m3
which is sufficient to fight the worst case fire for up to 4 hours
Deluge Valve:
Deluge Valve is manufactured with Dry Trim (Pneumatic Actuated) andWet Trim (Hydraulically Actuated). All trims are factory piped on the Valve
itself. It also has Manual Station as Test Trim, Manual Override and Drain
Line. The valve opens on demand to provide water flow to the fire
protection sprinkler systems. Pilot system can be hydraulically,
pneumatically or manually operated. Opening of the Value is by electrical
signal to solenoid valve/loss of control pressure.
SPILL DETECTORS:
Spill detectors are the temperature sensors (RTDs- PT100
Resistance at 0 deg. C = 100 ohm).
These are installed where flange joints are in use in LNG service
and there is chance of a leakage.
Any LNG leak shall cause rapid fall in temperature of the
surrounding areas which the RTDs shall detect
Emergency Shutdown System
Need for Emergency Shutdown System
ESD system activates when any variable or situation reaches the
maximum limit (trip value uncontrolled danger point) and it is notpossible to bring it back to a state where it can be regulated.
All such variables/situations are logically programmed to generate ESD
activation.
During ESD:
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When the ESD occurs the final actuating elements ( MOVPs,
Dampers, Motors, Pumps) stop or close or open or maintain the last
position as per the process requirements.
The vent or drain valves are very important as malfunction of these
shall cause unsafe conditions.
In the terminal ESD is split into 3 main groups as below:-
- ESD # 1 Takes care of the Jetty Operations unloading & Receipt.
- ESD # 2 Takes care of the Send out operations
-ESD # 3 - Takes care of both the operations of jetty and send out i.e.
combination of ESD1&2 also gives permissive for complete
depressurizations of STV/SCV.
EMERGENCY SHUTDOWN LOGICS
- ESD logics for the terminal is in the form Cause & Effect Diagram in
DCS and an action can be monitored in DCS through redundant serial
communication link.
- C & E diagrams show Causes in the left side and the effects are in the
right side.
- In all the Field devices feedback is provided which is for the operator to
confirm the happenings and also for start permissive.
EMERGENCY SHUTDOWN - I
Excessive movement of LNG ship (PMS)
Electrical power failure ( Including loss of BOG compressors)
LNG tank emergencies ( HH Pr/Level)
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Instrument air failure.
LNG leakage / Gas leakage.
Fire.
LNG ship side emergency.
Earthquake.
ESD 1 activated by four different ways:
1. By ESD Pushbutton from Control room
2. By ESD Pushbutton from Jetty head
3. By FGS system
4. By ULA system
ESD # 1 has two step :
Step-1 : Stopping of unloading
Step-2 : Detaching of Unloading arm only through Unloading PLC.
EMERGENCY SHUTDOWN II
Emergency of the pipeline network.
LNG leakage / gas leakage.
Fire ( depressurization could be initiated)
Control system failure.
Send out equipment failure.
Electrical power failure ( including loss of HP pumps)
Instrument air failure.
Earthquake.
ESD-II operates by pushbutton from control room and field sensor like send
out pressure switches.
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EMERGENCY SHUTDOWN III
Earthquake.
Other fatal natural disaster.
Fatal situation after initiation of ESD-I, ESD-II
ESD # 3 is operated by pushbutton from Main control room OperatorConsole.
Activates ESD-I, step-I and ESD-II
Gives permissive for depressurization valves.
EMERGENCY SHUTDOWN PLC
PLCs has made the Trip logic implementation easier and the responsetime h