training project 2012

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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

training project 2012

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