Boil-Off in Large and Small Scale LNG Chains

Faculty of Engineering Science and Technology Department of Petroleum Engineering and Applied Geophysics

BOIL-OFF IN LARGE LARGE - AND SMALL-SCALE SMALL-SCALE LNG CHAINS

Diploma Thesis

Rafa Sedlaczek

Trondheim May 2008

BOIL-OFF BOIL-OFF IN LARGE- AND LARGE- AND SMALL-SCALE LNG CHAINS

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Abstract One of the challenges in transporting and storing LNG is the generation of methane through the boil-off. Boil-off is caused by the heat added into the LNG during the storage and loading/unloading operations. In this thesis work, as a backgroun b ackground, d, the world-trade in LNG is reviewed in overall o verall numbers. The analysis of LNG shipping technologies is presented. The current current technologies used to store LNG are reviewed. reviewed. The different types types of tanks are describe d escribed, d, and their advantages and disadvantages discussed. New, types of LNG storage tanks (C/C LNG tank and ACLNG) are also described, with their potential p otential advantages and disadvantages. The sources of boil-off gas for fo r large-scale LNG receiving terminal are described, discussed and illustrate for a specific set of assumptions. Because of the larger relative value of o f methane evaporating during the storage, the boil-off consideration can be even more important in small-scale than in large-scale LNG chain. chain. As a typical small-scale LNG facility the L-CNG refuelling station is considered. Heat leak into the LNG storage tank is calculated. The effect o f a number of buses, fuelled each day on the possible total fuel loss rate is analyzed. a nalyzed. It is found that b y increasing increasing the number of buses, fuelled each each day, the total fuel loss rate can be reduced significantly. significantly. To prevent prevent boil-off of natural natural gas emissions, usually usually it is re-circulated. Some typical typical approaches for the use of boil-off gas are presented, for both large- and small-scale LNG chains.


ii

Abstract One of the challenges in transporting and storing LNG is the generation of methane through the boil-off. Boil-off is caused by the heat added into the LNG during the storage and loading/unloading operations. In this thesis work, as a backgroun b ackground, d, the world-trade in LNG is reviewed in overall o verall numbers. The analysis of LNG shipping technologies is presented. The current current technologies used to store LNG are reviewed. reviewed. The different types types of tanks are describe d escribed, d, and their advantages and disadvantages discussed. New, types of LNG storage tanks (C/C LNG tank and ACLNG) are also described, with their potential p otential advantages and disadvantages. The sources of boil-off gas for fo r large-scale LNG receiving terminal are described, discussed and illustrate for a specific set of assumptions. Because of the larger relative value of o f methane evaporating during the storage, the boil-off consideration can be even more important in small-scale than in large-scale LNG chain. chain. As a typical small-scale LNG facility the L-CNG refuelling station is considered. Heat leak into the LNG storage tank is calculated. The effect o f a number of buses, fuelled each day on the possible total fuel loss rate is analyzed. a nalyzed. It is found that b y increasing increasing the number of buses, fuelled each each day, the total fuel loss rate can be reduced significantly. significantly. To prevent prevent boil-off of natural natural gas emissions, usually usually it is re-circulated. Some typical typical approaches for the use of boil-off gas are presented, for both large- and small-scale LNG chains.


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Acknowledgements There are many people who contributed to my m y thesis and many events that influenced my work during the last few months. I would like at least to mention them here. First of all, I would like to express my sincere appreciation to the person without whom this thesis would never come to life, my supervisor Professor Jon Steinar Gudmundsson. I am deeply grateful for the advice, support, useful and helpful assistance, patience and enthusiasm. I wish wish to thank thank Dr Hab. In In . Stanis Stanis aw Nagy, my supervisor from AGH University of Science and Technology in Cracow, thanks to whom my Erasmus Link Scholarship was possible. I am also also grateful for his support, support, and patience patience during our cooperation. Special thanks to Mr Otto Skovholt from StatoilHydro for his generous suggestions and commitment. Special thanks to Professor Jan Falkus Falkus form AGH University Uni versity of Science and Technology in Cracow, Poland for making my Erasmus Link Scholarship possible. I am grateful to all my teachers who, giving me a small part of their wide knowledge, got me to the stage when I am writing writ ing this thesis.


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List of Contents Contents Abstract.......................... Abstract......................................... ............................. ............................... ................................ ................................ ............................... ................... ..... ii Acknowled Acknowledgemen gements ts ............................... .............................................. ............................. ............................... ................................ ........................... ............ iii List List of Contents................... Contents.................................. ............................. ............................... ................................ ............................... ............................... ...............iv iv List List of Tables................... Tables.................................... ................................ ............................. ............................... ................................ ............................. ..................vi ....vi List List of Figures Figures ............................... ............................................. ............................... ................................ ............................. ............................... .................... ... vii Abbreviatio Abbreviations. ns.............. ........................... ............................... ................................ ............................... ............................... ................................ ...................... ..... ix 1

Introduct Introduction.... ion.................. ............................... ................................ ............................. ............................... ................................ ............................ ............. 1

2

What is Liquefied Liquefied Natural Gas? ............................... .............................................. ............................... ............................... ............... 3

3

LNG market market ............................. ............................................ ............................. ............................... ................................ ............................. .................. .... 5

3.1 3.2 3.3 3.4 3.5 3.6 4

LNG storage storage tanks tanks ............................. ............................................ ............................... ............................... ................................ ......................18 .....18

4.1 4.2 4.3 4.4 4.5 4.6 5

Evolution of LNG fleet.......... fleet. ....................... .............. ...................... ......... ............. ....................... ......... .............. ................32 ......... .......32 Kvaerner Kvaerner - Moss spherical tanks ................... .......... ...................... ............. ....................... ......... .............. ................34 ......... .......34 Membrane Membrane tanks.......... tanks ............................ ................................ ............................... ................................ ................................. .....................36 ...36 Prismatic Prismatic tanks tanks ......................... ....................................... ............................ ................................ .................................... ..........................38 ........38

Large-scal Large-scalee LNG chain chain ................................ .............................................. ............................... ................................ ...........................40 ............40

6.1 6.2 6.3 6.4 6.5 7

Backgro Background und ...................... ........................................ .................................... .................................... .................................... ..........................18 ........18 Single containment tanks (SCT) ................... .......... ...................... ............. ....................... ......... .............. ................19 ......... .......19 Double containment tanks (DCT) ............ .............. ....................... ......... .............. .................... ......... ...........21 21 Full containment tanks (FCT) .............. ...................... ......... ............. ....................... ......... .............. ................23 ......... .......23 Membrane Membrane tanks.......... tanks ............................ ................................ ............................... ................................ ................................. .....................25 ...25 New LNG storage technologies .................... ........... ..................... ....................... ........................ ............. ................27 ......... .......27

LNG vessel vessel types types ............................ ............................................. ................................ ............................. ............................... ..........................32 .........32

5.1 5.2 5.3 5.4 6

Abundant world natural gas reserves and LNG potential................... potential..... .............. ................. ......... ........ 5 LNG market market structure.................... structure..................................... ............................... ............................. ................................ ...................... ..... 7 LNG exporters... exporters................. ................................ ................................ ............................ ............................... ................................ ................... .... 9 LNG importers importers ......................... ....................................... ............................ ................................ .................................... ..........................12 ........12 Growing world LNG trade................... trade..... .............. ...................... ......... ............. ....................... .......... ............. ................14 ......... .......14 Small-sc Small-scale ale LNG trend ........................... ......................................... ................................ .................................... ..........................16 ........16

LNG value value chain ........................... ......................................... ............................... ................................... ................................. ..................40 ...40 Thermal analysis of boil-off of LNG for the unloading mode............ ................42 ......... .......42 Thermal analysis of boil-off of LNG for the holding mode .................... ........... .................... ...........47 47 Thermal analysis of the LNG storage tank ............. ................... ......... ....................... ............. ...........50 ........... 50 BOR in large-scale LNG chain ............ .................... ......... ...................... ......................... .............. ................59 ......... .......59

Small-scale LNG chain...........................................................................................64

7.1 7.2 7.3

Backgro Background und ...................... ........................................ .................................... .................................... .................................... ..........................64 ........64 Thermal analysis of boil-off of LNG in cryogenic tanks ................... .......... .................. ................66 .......66 Dynamic process during storage and fueling.............. fueling. ............. ....................... ......... .............. ................72 ......... .......72

BOIL-OFF BOIL-OFF IN LARGE- AND LARGE- AND SMALL-SCALE LNG CHAINS 8

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Use of boil-off gas ............... ............... ............................. ............................................ ............................. ............................... ..........................78 .........78

8.1 8.2 8.3

Use of BOG at ships..... ships ............. ...................... ................................ .................................... .................................... ..........................78 ........78 Use of BOG at receiving terminals ........................ .......... .............. ....................... ......... .............. .................... ......... ...........80 80 Use of BOG in small-scale LNG chain ...................... ......... ............. ....................... ......... .............. ................82 ......... .......82

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Discuss Discussion ion .......................... ........................................... ................................ ............................... ............................... ................................ ......................84 .....84

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Conclu Conclusions...... sions....................... ............................... ............................... ................................ ............................. ............................... ..........................87 .........87

Reference Referencess ................................ .............................................. ............................... ................................ ............................. ............................... ..........................88 .........88 Appendix A. Composition of Natural Gas and LNG....................................................91 Appendix Appendix B. Major trade movements movements  Natural Natural Gas Gas and LNG (2006) (2006) ..................... .......... ........... ..93 Appendix C. Major trade movements  LNG (2006) ............................. .............................................. ......................94 .....94 Appendix D. Maps of LNG facilities worldwide...........................................................95

Caribbean, South & Central America .............. ...................... ......... ............. ....................... ......... .............. ................95 ......... .......95 Asia Pacific Countries - Map A....................................................................................96 Asia Pacific Countries - Map B....................................................................................97 Africa Africa .................................... .................................................. ............................ ............................ ................................ .................................... ..........................98 ........98 Western Europe Map A............................... A................................................. .................................... ................................ ..........................99 ............99 Western Europe Map B .......................... ........................................ ............................... ................................ ................................. ...................100 .100 Mexico............. Mexico........................... ............................... ................................ ................................. .................................... .................................... ........................101 ......101 Middle Middle East Countries............. Countries............................... ................................ ............................... ................................... ................................. ................102 .102 Northeastern Europe Europe ..................... ........... ................... ...................... ............. .............. ...................... ......... ............. ................... .......... .........103 103 Southwest Southwest Pacific Pacific Rim Countries Countries ........................... ............................................ ............................ ............................. ........................104 ......104 United States of America West Coast Map A ......................... .......................................... ................................ ................105 .105 United States of America Gulf Coast Co ast Map B ......................... ........................................ ................................. ...................106 .106 United States of America East Coast Map C....................... C.......... ............. ....................... ......... .............. ..............107 ......... .....107 Canada. Canada......... ......................... ............................... ................................ ................................ ............................ ............................ ................................ ...................108 .108 Appendix Appendix E. Convers Conversion ion tables tables ................................ ................................................ ............................... ................................ ....................109 ...109 Appendix Appendix F. Methane density density at liquid liquid and gaseous gaseous states ...................... ........... ........... .................. ......... ......... 110


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List of Tables Table 5.1 Features of LNG membrane cargo containment systems...................................37 Table 6.1 Dimensions of the LNG tank............................................................................55 Table 6.2 Concrete properties at normal temperature........................................................55 Table 6.3 Insula Insulation tion layers layers of wall wall ......................... ....................................... ................................ .................................... ..........................56 ........56 Table 6.4 Bottom Bottom slab configurat configuration. ion. ......................... .......................................... ............................ ............................. ..........................57 ........57 Table 6.5 BOG and BOR for numerical example..............................................................58 Table 6.6 Boil-off gas sources, an example study.............................................................59 Table 6.7 Average emissions intensity of various life-cycle stages of LNG imported by Japan ........................ .......................................... .................................... ................................ ............................... ................................ ................................. .....................62 ...62 Table A.1 Examples of Gas compositions compositions .................... ........... ..................... ....................... ........................ ............. ................91 ......... .......91 Table A.2 Examples of LNG compositions compositions ............. .............. ...................... ......... ............. ..................... ......... ............92 92 Table A.3 Frequently used conversions..........................................................................109 Table A.4 Typical liquid-vapour conversions.................................................................109 Table A.5 Methane Methane pressure and density at at liquid and gaseous gaseous states .................... ........... .................. .........110 110

BOIL-OFF IN LARGE- AND SMALL-SCALE LNG CHAINS

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List of Figures Figure 3.1 Proved world natural gas reserves, January 1, 2007.......................................... 5 Figure 3.2 World LNG exporters, January 1, 2007 ...........................................................11 Figure 3.3 World LNG importers, January1, 2007............................................................11 Figure 4.1 Various types of LNG tanks [15].....................................................................18 Figure 4.2 Features of a typical single containment LNG tank..........................................19 Figure 4.3 Features of a typical double containment LNG tank. .......................................21 Figure 4.4 Features of a typical full containment LNG tank..............................................23 Figure 4.5 Membrane LNG storage tank multiples structure.............................................25 Figure 4.6 ACLNG tank details........................................................................................28 Figure 4.7 A CryoTank design .........................................................................................31 Figure 5.1 Changes of LNG cargo tanks types..................................................................32 Figure 5.2 Age of LNG fleet ...........................................................................................33 Figure 5.3 LNG carrier equipped with Moss tanks. ..........................................................34 Figure 5.4 Inside view of SPB tank..................................................................................38 Figure 6.1 The LNG chain-from production to user..........................................................40 Figure 6.2 Boil-off gas generated by insulated pipeline heat gain. ....................................44 Figure 6.3 An LNG storage tank with the liquid stratified ................................................48 Figure 6.4 Heat flow rates through the roof ......................................................................50 Figure 6.5 Configuration of the LNG tank wall................................................................52 Figure 6.6 Configuration of the LNG tank wall using equivalent concrete........................53 Figure 7.1 Conceptual sketch of small-scale LNG chain...................................................64 Figure 7.2 Boil-off rate as a function of thickness of superinsulation................................68 Figure 7.3 Thermal conductance as a function of thickness of insulation..........................69 Figure 7.4 The vapour pressure curve for methane ...........................................................70 Figure 7.5 Percentage of LNG to be boiled to reduce saturated vapour pressure...............71 Figure 7.6 Predicted saturated pressure for 50 m 3 tank with an initial fill of 25 m3 LNG. .74 Figure 7.7 Average fuel consumption...............................................................................75 Figure 7.8 Total fuel loss with number of buses. ..............................................................76 Figure 7.9 Boil-off rate as a percentage of daily consumption of the LNG for the LNG tank..................................................................................................................................77 Figure 8.1 Process flow-scheme of boil-off re-liquefaction unit. ......................................79


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Figure 8.2 LNG storage tank with module of electric generator or liquefier......................83


Abbreviations LNG

Liquefied Natural Gas

LPG

Liquefied Petroleum Gas

CNG

Compressed Natural Gas

NG

Natural Gas

BOG

Boil-Off Gas

BOR

Boil-Off Rate

OECD

Organisation for Economic Co-Operation and Development

IEA

International Energy Agency

SCT

Single Containment Tank

DCT

Double Containment Tank

FCT

Full Containment Tank

ACLNG

All-Concrete LNG Tank

C/C

Concrete/Concrete Tank (Cryo Tank)

EEMUA

Engineering Equipments and Materials Users Association

CO2

Carbon Dioxide

CO2e

Carbon Dioxide Equivalent

SOx

Sulphur Oxides

NOx

Nitrogen Oxides

CH4

Methane

L-CNG

Liquid to Compressed Natural Gas

NGV

Natural Gas Vehicles

GHG

Greenhouse Gases

IMO

International Maritime Organisation

MSCM

Thousand Standard Cubic Metres

BCM

Billion Cubic Metres (1,000,000,000 = 109)

BCF

Billion Cubic Feet (1,000,000,000 = 109)

TCM

Trillion Cubic Metres (1,000,000,000,000 = 1012)

BTU

British Thermal Unit

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1

1 Introduction Liquefied natural gas (LNG) is natural gas that has been cooled to the point that it condenses to a liquid, which occurs at a temperature of approximately -162°C and at atmospheric pressure. Liquefaction reduces the volume by approximately 600 times, making it more economical to transport between continents. LNG is transported by special made ships to terminals, and then stored at atmospheric pressure in super-insulated tanks. However the ship cargo tanks, storage tanks and almost all equipment used to pro cess LNG are well insulated, there is always some heat leak into the LNG. Heat entering the LNG, referred as heat inleak causes the LNG to warm up. To keep the pressure and the temperature constant heat adsorbed by the LNG has to be released b y boiling off some of the liquid to gas. This is known as auto-refrigeration. Methane, the primary constituent of boil-off gas is a potent greenhouse gas when released to the atmosphere. It is worthy to note that while the quantity of CH4 emissions does not appear significant compared to CO2, considering the global warming potential of CH4 (methane is about 21 times more greenhouse gas than carbon dioxide), these emissions are responsible for about 13% of total CO2e emissions. Flaring alone contributes to more than 1 percent to global emissions of CO 2 (IEA, 2008). Boil-off gas is essentially gasified LNG at atmospheric pressure and it has substantial fuel value. Excepting all negative impact that natural gas emissions exert on the environment it is not economically profitable to dispose boil-off gas by venting or flaring. That is w hy at both production and receiving sites the boil-off gas handling system is designed and installed. Of course handling of boil-off gas requires compression equipment that is costly to install and operate, so every possible effort is made to reduce the quantity of boil-off gas produced. However, currently LNG industry contributes only small part of global emissions of CH4 from the oil and gas sector, it can become a potent source of greenhouse gas emissions in the near future. According to the International Energy Agency (IEA), LNG will account even for 70% of the increase in gas trade by 2030. If this were to happen, LNG would make up 50% of internationally traded gas by 2030. It is clear that these large amounts of


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LNG would generate large quantities of boil-off gas, which would become a significant source of CH4 emissions. Due to increasing demand world wide, by the United Nations and other global organisations, to combat greenhouse gas emissions, it is evident how important boil-off gas generation will be. In this thesis work the sources of boil-off gas in large-scale receiving terminals will be discussed. As a result the boil-off from the storage volumes will be estimated for the specific set of assumptions. As a typical small-scale facility the L-CNG refuelling station will b e considered. Natural gas is being promoted as a transportation fuel for heavy vehicles such as tru cks and city buses, to lessen the dependency on oil and to reduce greenhouse gas emissions. However this solution has many advantages the disadvantage is that the bo il-off of LNG can cause excessive pressure build-up in LNG tanks, and therefore methods have to be found to reduce the pressure of the boil-off gas and to prevent venting of the boil-off natural gas in storage vessels and transportation tanks. In this thesis work the thermodynamic and heat transfer methods to analyse the pressure and temperatures changes in LNG tanks will be used. The effect of number of buses, fuelled each day on the total fuel loss due to boil-off will be also presented.


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2 What is Liquefied Natural Gas? To answer the question what the liquefied natural gas is we have to define natural gas. Natural gas comes from reservoirs beneath the earth s surface. Sometimes it occurs naturally and is produced by itself (non-associated gas), sometimes it comes to the surface with crude oil (associated gas), and sometimes it is produced constantly such as in landfill gas. Natural gas is a fossil fuel, meaning that it is derived from organic material deposited and buried in the earth millions of years ago. Other fossil fuels are coal and crude oil. Together crude oil and gas constitute a t ype of fossil fuel known as hydrocarbons because the molecules in these fuels are combinations of hydrogen and carbon atoms. The main component of natural gas is methane. Methane is composed of o ne carbon and four hydrogen atoms (CH4). When natural gas is produced from the earth, it includes many other molecules, like ethane (used for manufacturing), propane (which we commonly use for barbeques), butane (used in lighters) and heavier hydrocarbons. Small quantities of nitrogen, oxygen, carbon dioxide, sulphur compounds, and water may also be found in natural gas. [1] According to the Department of Energy (DOE 2008), liquefied natural gas (LNG) is natural gas that has been cooled to the point that it condenses to a liqu id, which occurs at a temperature of approximately -161°C and at atmospheric pressure. Natural gas is turned into a liquid using a refrigeration process in a liquefaction plant. The unit where LNG is produced is called a train. Feed gas to the liquefaction plant comes from the production field. This gas must be clean and dry before liquefaction can take place. The gas is scrubbed of entrained hydrocarbon liquids and dirt and treated to remove trace amounts of two common natural gas contaminants: hydrogen sulphide and carbon dioxide. Next, the gas is cooled to allow water to condense and then further dehydrated to remove even small amounts of water vapour. The clean and dry gas may then be filtered before liquefaction begins. Liquefaction takes place through cooling of the gas using heat exchangers. In these vessels, gas circulating through aluminium tube coils is exposed to a compressed hydrocarbon-nitrogen refrigerant. Heat transfer is accomplished as the refrigerant vaporizes, cooling the gas in the tubes before it returns to the compressor. The liquefaction process can have variations. For example, the Phillips Cascade, which employs three heat exchangers with successively colder refrigerants (propane, ethane, methane) and


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independent compressors for each exchanger refrigerant combination. Together the series of exchangers comprise a single L NG train. [2] As a result of liquefaction process we get liquefied natural gas (LNG). Liquefying natural gas reduces its volume by a factor of 600, which means that LNG at -162°C uses 1/600th of the space required for a comparable amount of gas at room temperature and atmospheric pressure and reaches the density of 420 to 490 kilograms per cubic metre. Because the liquefaction process requires the removal of some of the non-methane components such as water and carbon dioxide from the production gas, LNG is typically made up mostly of methane plus a few percent of ethane, even less propane and butane, and trace amounts of nitrogen. And, like methane, the main component of LNG, is odourless, colourless, noncorrosive, and non-toxic. [1] Liquefied natural gas is very save. As a liquid, LNG cannot explode or burn. The lighter than air property of methane actually makes it less hazardous than some other fuels, such as propane or butane whose gases are heavier than air and tend to settle closer to the ground. In gaseous form, LNG vapour can burn if it is within 5-15% natural gas in the air. If it is less than 5% natural gas in the air, the gas is too diluted to burn. If it is more than 15% natural gas in the air, there is not enough oxygen for it to burn. When spilled on water or land, LNG will not mix with the water or soil or leave a residue, but evaporates and dissipates into the air. [3]


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3 LNG market 3.1 Abundant world natural gas reserves and LNG potential

Historically, world natural gas reserves have, for the most part, trended upward. As of January 1, 2007, proved world natural gas reserves (proved reserves are those that could be economically produced with the current technology), as reported by BP Statistical Review of Energy were estimated at 181.46 trillion cubic metres (TCM) 1.39 TCM (about 1 percent) higher than the estimate for 2006. Much of this gas is considered stranded because it is located in regions distant from consuming markets. [4] The largest revisions to natural gas reserve estimates were reported for Kazakhstan, Turkmenistan, and China. Kazakhstan added an estimated 0 .99 TCM (a 54-percent increase over 2006 proved reserves), Turkmenistan 0.82 TCM (41 percent), and China 0.77 TCM (50 percent). Declines in natural gas reserves were reported for the Netherlands (a decrease of 0.34 TCM), Trinidad and Tobago (0.2 TCM), Argentina (0.085 TCM), Nigeria (0.085 TCM), and Italy, Norway, the United Kingdom, and Saudi Arabia (about 0.057 TCM each). [4]

Figure 3.1 Proved world natural gas reserves, January 1, 2007.

Almost three-quarters of the world s natural gas reserves are located in the Middle East and Eurasia (Figure 3.1). Russia, Iran, and Qatar combined accounted for about 58 percent


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of the world s natural gas reserves as of January 1, 2007. Reserves in the rest of the world are fairly evenly distributed on a regional basis. [4] Natural gas, in the form of liquefied natural gas or LNG, has the potential to be exported from countries with large, proven natural gas reserves and relatively high reserves-to production ratios. Some countries meeting this criterion include the Republic of Peru, Republic of Venezuela, Azerbaijan Republic, Republic of Kazakhstan, Islamic Republic of Iran, Republic of Iraq, State of Kuwait, State of Qatar, United Arab Emirates (also known as Al Imarat al-Arabiyah al-Muttahidah), Republic of Yemen, Federal Republic of Nigeria, and Independent State of Papua New Guinea. However, not all of these countries are exporters of natural gas as LNG due to domestic need, inaccessibility to international natural gas trade and infrastructure, geopolitics, and lack of capital or technological investment. [5] The 15 countries (Algeria, Australia, Brunei (Darussalam), Equatorial Guinea, Egypt, Indonesia, Libya (also known as the Socialist People's Libyan Arab Jamahiriya), Malaysia (also known as Persekutuan Tanah Malaysia), Nigeria, Norway, Oman, (also known as Saltanat Uman), Qatar, (also known as Dawlat Qatar), Trinidad and Tobago, United Arab Emirates (also known as Al Imarat al-Arabiyah Al-Muttahidah), United States of America) that currently export LNG have approximately 34 percent of world natural gas reserves. [6] In addition to expansions by current LNG exporters, Russia with 26.3 percent of the world s reserves is poised to become LNG exporting country, as it is currently building its first liquefaction facilities. At least six additional countries (Angola, Bolivia, Iran, Peru, Venezuela, and Yemen) with 19 percent of the world s reserves are potential LNG exporters. [6] According to an industry LNG consultant Andy Flower the economic crossover - the point at which transporting LNG via tanker is cheaper than transporting natural gas via pipelines - occurs at a distance of around 2,000 kilometres (1,250 miles) for offshore pipelines and around 3,800 kilometres (2,375 miles) for onshore pipelines. [6]


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3.2 LNG market structure

LNG is traded globally in two major markets - the Atlantic Basin and the Pacific Basin. The Atlantic Basin is usually defined as made up of all land masses (including islands) that lie adjacent to or within the Atlantic Ocean, so it will include all activity in Europe, Africa (including North and West Africa), and the Western Hemisphere (not including the Alaskan terminal on the Pacific Ocean). The term Pacific Basin will be used to describe LNG activity along the Pacific Rim (including Alaska) and in South Asia (including India). [7] The Atlantic Basin LNG market consist of current LNG producing countries Abu Dhabi, Algeria, Egypt, Equatorial Guinea, Libya, Nigeria, Norway Oman, Qatar, and Trinidad & Tobago, and LNG consuming countries Belgium, Dominican Republic, France, Greece, Italy, Mexico, Portugal, Spain, Turkey, the UK, and the US (including Puerto Rico), as well as future LNG producers Angola, Russia, Venezuela, and Yemen, and possible future LNG consumers Brazil, Canadian East Coast, Germany and the Netherlands. [7] The Pacific Basin LNG market consists of present LNG producers Abu Dhabi, Australia, Brunei, Indonesia, Malaysia, Oman, Qatar, and the US (Alaska), producing projects under construction in Peru, Russia (Sakhalin), and Yemen, and current LNG consumers China (including Taiwan), India, Japan, and South Korea, together with future Pacific Basin LNG producers Iran and Papua New Guinea, and future LNG importers Canadian West Coast, Mexico s West Coast, Indonesia, Pakistan, Singapore, Thailand, and the US West Coast. [7] Although the Atlantic and Pacific LNG markets are beginning to blend, significant differences between them continue to exist. LNG trade evolved differently in the Atlantic and Pacific basins, and this continues to affect import volume, pricing systems, and contract terms. Importing countries in the Pacific Basin are almost totally dep endent on LNG while countries in the Atlantic Basin use domestic supplies and p ipeline imports as well as LNG to meet natural gas demand. Because current LNG importers in the Pacific Basin did not have access to domestic or piped imported gas, LNG imports into the region


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increased rapidly in the 1980s and early 1990s as these countries sought alternatives to oil. Security of supply was a more important consideration in the Pacific Basin than price. [7] When comparing the two basins you can see that, the Pacific b asin is larger, but the Atlantic basin is growing now a bit faster. The Pacific basin is the largest LNG-producing region in the world, supplying nearly 60 % of all global exports in 2006. Indonesia alone supplied 14 percent. Countries in the Middle East, led b y Qatar, exported 15 percent, while countries in the Atlantic Basin, led b y Algeria, exported about 38 percent that year. Expansions in Nigeria, Trinidad and Tobago and Egypt, as well as new facilities in Norway and Equatorial Guinea, would increase annual Atlantic Basin liquefaction capacity significantly in the near future. [4] The LNG import in the Pacific basin is also larger. Three countries in the Pacific Basin (Japan, South Korea, and Taiwan) accounted for 60 percent of global LNG imports in 2006. Eight European countries (Belgium, France, Greece, Italy, Portugal, Spain, Turkey and the UK) received 27 percent of global LNG import, and the US accounted for almost 8 percent of global LNG import in the same year. Regasification capacity continues to grow as most Atlantic Basin importers are planning expansions. [4]


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3.3 LNG exporters

Worldwide, there are 26 existing export, or liquefaction, marine terminals, located on or off shore, in 15 countries. Countries that currently export LNG (start up date of earliest liquefaction terminal is in parentheses) are: [5]

· Algeria, Republic of (1971) · Australia, Commonwealth of (1989) · Brunei (Darussalam), State of (1972) · Equatorial Guinea, Republic of (2007) · Egypt, Arab Republic of (2004) · Indonesia, Republic of (1977) · Libya (also known as the Socialist People's Libyan Arab Jamahiriya) (1970) · Malaysia (also known as Persekutuan Tanah Malaysia) (1983) · Nigeria, Federal Republic of (1999) · Norway, Kingdom of (2007) · Oman, Sultanate of (also known as Saltanat Uman) (2000) · Qatar, State of (also known as Dawlat Qatar) (1997) · Trinidad and Tobago, Republic of (1999) · United Arab Emirates (also known as Al Imarat al-Arabiyah Al-Muttahidah) (1977) · United States of America (1969) Asia/Pacific Basin LNG producers accounted for nearly 60 percent of total world LNG exports in 2006. During 2006, industry reports suggest that Qatar surpassed Indonesia to become the world s largest LNG exporter, shipping about 15 percent of world s total LNG export. The majority of Qatar s LNG is imported by Japan, South Korea and India with smaller volumes going to Spain and Belgium. Indonesia was the second world s largest LNG producer and exporter in 2006, shipping about 14 percent of the world s total LNG exports. Most of Indonesia s LNG is imported by Japan with smaller volumes going to Taiwan and South Korea. Malaysia, the world s third-largest LNG exporter, ships primarily to Japan with smaller volumes to Taiwan, South Korea and India. Australia exports LNG from the Northwest Shelf, primarily to supply Japanese, South Korea and India utilities. About 90 percent of Brunei Darussalam output goes to Japanese customers.


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The only liquefaction facility in the United States was constructed in Kenai, Alaska, in 1969, and it has exported LNG to Japan for more than 30 years. [8] Atlantic Basin LNG producers accounted for about 38 percent of total world LNG exports in 2006. Algeria, the world s fourth-largest LNG exporter, serves mainly Europe (France, Belgium, Spain, and Turkey) and the United States via Sonatrach s four liquefaction complexes. Nigeria also exports mainly to Europe (Spain, France, Portugal, Turkey and Belgium) but also has delivered cargos under short-term contracts to the United States. Trinidad and Tobago exports LNG to the United States (the largest supplier o f LNG to the U.S.), Spain, the UK, Puerto Rico and the Dominican Republic. Egypt was the eighth largest LNG exporter in 2006, shipping about 7 percent of the world s total LNG export mainly to Europe (Spain, France, the UK, Belgium, Greece and Italy) but also to the US and Asian countries. Oman s LNG was shipped mainly to South Korea, Japan, India and Taiwan. Brunei, the first Asian exporter of LNG, exports mainly to Japan, with small quantities going to South Korea. The UAE exports mainly to Japan and a small part to India. [8] In October 2007 Norway s Snøhvit plant loaded its first cargo. Snøhvit is the first Norwegian and European production and export facility for liquefied natural gas (LNG). Most of the output from the Snøhvit facility has alread y been contracted to El Paso for delivery to the United States, with smaller amounts going to Iberdrola in Spain. Statoil planed to have an initial capacity of 4.1 million ton per year and a potential expansion to 8.2 million ton per year, but series of problems at Norway s Snøhvit plant resulted in slippage in the start-up of the already delayed project and restricted production to only two cargoes in 2007. [8] Liquefaction capacity in both regions has been increasing steadily so far, bu t it is expected that planned expansion could dramatically increase liquefaction capacity in the near future. Russia is becoming the newest Asia/Pacific Basin exporter. Its first LNG plant is under construction on Sakhalin Island off the country s east coast. This large facility is scheduled to begin operation in 2008. Planned expansions of existing plants in the Atlantic Basin could also dramatically increase its liquefaction capacity. [8]


Figure 3.2 World LNG exporters, January 1, 2007

Figure 3.3 World LNG importers, January1, 2007

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3.4 LNG importers

Worldwide, there are 60 existing import, or regasification, marine terminals, on or o ff shore, spread across 18 different countries. In addition to these existing terminals, there are approximately 182 regasification terminal projects that have been either proposed or are under construction all around the world. It is not expected that all of the proposed terminals will be constructed. Countries that currently import LNG (start up date of earliest regasification terminal is in parentheses) are: [5]

· Belgium, Kingdom of (1987) · China, People's Republic of (2006) · Dominican Republic (2003) · France (also known as the French Republic) (1972) · Greece (also known as the Hellenic Republic) (2000) · India, Republic of (2004) · Italy (also known as the Italian Republic) (1971) · Japan (also known as Nihon, Nippon, Nihon Koku) (1969) · Mexico (also known as the United Mexican States) (2006) · Portugal (also known as the Portuguese Republic) (2003) · Puerto Rico, Commonwealth of (U.S. Outlying Territory) (2000) · South Korea, Republic of (1986) · Spain, Kingdom of (1969) · Taiwan (Republic of China) (1990) · Turkey, Republic of (1992) · United Kingdom (2005) · United States of America (1971) Four countries in the Asia/Pacific Basin Japan, South Korea, India and Taiwan accounted for almost 64 percent of global LNG imports, while Atlantic Basin LNG importers took delivery of the remaining 36 percent. Japan remains the world s largest LNG consumer, although its share of global LNG trade has fallen slightly over the past decade as the global market has grown. Japan s largest LNG suppliers are Indonesia Malaysia, Australia, Brunei, Qatar and UAE, with substantial volumes also imported


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Africa, Trinidad and Tobago and USA. South Korea, the second-highest LNG importer in the world behind Japan, currently gets most of its LNG from Qatar, Malaysia, Oman and Indonesia with smaller volumes coming from Australia, Brunei, and Egypt. CPC operates Taiwan's only LNG receiving terminal at Yungan township of Kaohsiung, where LNG is imported from Indonesia and Malaysia, with smaller volumes from Australia, Nigeria, Egypt and Oman. India has started receiving LNG shipments in January 2004 with the start-up of the Dahej terminal in Gujarat state. Currently India is becoming one of the most important LNG players in the world, shipping mainly from Qatar, with small quantities from Oman, Egypt, the UEA, Algeria, Nigeria and Australia. Spain has one of the world s most rapidly growing natural gas markets, being the biggest LNG importer in Europe. In 2006 Spain received about 11.5 percent of the world s total LNG import, mainly from African s countries such as Nigeria, Egypt, Algeria and Libya, but also from Qatar, Trinidad and Tobago and Oman. Most French LNG imports come from Algeria, with smaller quantities from Nigeria and Egypt. Italy and Turkey receive LNG mainly from Algeria with smaller quantities from Nigeria and Egypt. Belgium has one regasification terminal and receives most of its LNG from Algeria. [8] Imports by Atlantic Basin countries are expected to grow as many expand storage and regasification terminal capacity. France is constructing a new, offshore LNG receiving terminal at Fos Cavaou, and Exxon Mobil has also proposed building an LNG import terminal near Fos Cavaou b y 2009. However the greatest growth in LNG import capacity is expected in the U.S. and in the United Kingdom. The US currently gets most of its LNG from Trinidad and Tobago, with smaller quantities from Egypt, Nigeria, Algeria and Norway. The US is planning to build four new LNG regasification terminals on the Atlantic and Gulf Coasts from 2007 through 2010 to meet the 58-percent increase in LNG imports that is projected for that timeframe. Currently, the UK has a single LNG import terminal, the NGT s Grain LNG on the Isle of Grain and imports mainly from Algeria with smaller quantities from Egypt and Trinidad and Tobago. Exxon Mobil and Qatar Petroleum have received regulatory approval for the South Hook LNG receiving terminal in Milton Haven, Wales. The terminal will receive its LNG from the Qatargas II liquefaction project in Ras Laffin. Finally, BG has collaborated with Netherlands-based Petroplus and Malaysia-based Petronas to also build an LNG receiving terminal in Milton Haven, on the site of an existing natural gas storage facility owned by Petroplus. [8]


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3.5 Growing world LNG trade

The number of countries involved in the LNG trade has expanded significantly in recent years. In 1995, there were 8 LNG exporting countries and 9 LNG importing countries. By 2008, this had increased to 15 exporting countries and 18 importing countries, with even more countries in the process of developing infrastructure to either export or import LNG in the near future. The market also saw significant expansion in delivered quantities of LNG during this time period, growing by 7.3% per year, or almost doubling to 211 b illion cubic metres in 2006. [9] The international trade in LNG will continue to grow in coming years. The price of natural gas has been growing in recent years when the costs of liquefying, transporting, and regasifying LNG have fallen significantly. Rising gas import demand, especially in North America, desire to making gas market more diverse and also the desire of gas producers to monetize their gas reserves is setting the stage for increased LNG trade in the years ahead. [9] Continued expansion of demand has motivated an interest in expanding the role o f LNG imports. The traditional consuming natural gas markets in Asia (Japan, Taiwan and South Korea) have virtually no indigenous production and, as a result, those countries rely principally on LNG for gas supply. The production in the US, Canada and Mexico has remained almost flat. This is especially telling given the continuous increases in drilling activity in recent years, and higher gas prices providing incentive to develop more costly unconventional natural gas resources in significant quantities. In Western Europe, the North Sea gas fields and the onshore fields in France, Germany and Italy are in decline, or has begun slowed considerably in recent years. Therefore, all three traditional OECD natural gas markets are faced with the need to secure gas supplies from other sources in order to satisfy growth in demand. [9] Large distances between potential producers and consumers favour using the LNG infrastructure . The majority of world s natural gas resources are in the Middle East, Central Asia and Russia with the traditional gas markets in OECD countries accounting for less than 10% of the global reserve base. Some significant resources are also in Africa,


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Latin America and Southeast Asia. However, each of these regions is distant from the major consuming markets in North America, Europe and Asia. Because of the distance gas cannot practically or economically be transported in its gaseous state via pipeline. Thus, LNG provides a means of linking remote gas to markets. Moreover consumers in OECD Europe have an additional incentive to diversify sources of supply to LNG imports, driven by fears of over-reliance on gas supply from Russia. Concerns arise from potential supply disruptions caused by Russian disputes with transit countries as well as longer term concerns over whether Russia will be able to invest sufficiently to maintain export capacity, particularly if its domestic consumption continues strong growth. [9] Emerging natural gas markets, such as China and India, are set to grow rapidly, albeit from a low base, and will also require increases in imports. Both have LNG and pipeline options, but geopolitical pressures make it probable that LNG will represent a significant share of supply to each of these emerging gas markets. Longer supply chains from a relatively concentrated number of suppliers may lead to an increase in vulnerability to supply disruption because of technical, logistical or geopolitical incidents. [9] All the consideration showed above leads to consensus that LNG trade will grow faster than natural gas demand. The World Energy Outlook by the IEA (2006) expects LNG trade to grow by 6.6% per year between 2004 and 2030, from 90 BCM (8.7 BCF/day) to 470 BCM (45.5 BCF/day). By comparison world natural gas demand is projected to increase by 2% per year, meaning the contribution of LNG to meeting demand is expected to grow substantially. In fact, the IEA projects that LNG will account for 70% of the increase in gas trade by 2030. If this were to happen, LNG would make up 50% of internationally traded gas by 2030, compared to around 22% in 2004. [9]


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3.6 Small-scale LNG trend

The LNG market is dominated by a large-scale LNG value chain. T ypically an LNG production and distribution system is a huge investment. Since all these investments have to be in place before the gas can move to market, LNG developments usually require longterm contracts with specific customers to secure financing. These contracts normally specify delivery of gas to a particular location for a duration of 20-25 years. Historically, LNG has almost exclusively been consumed by big power plants and, to some extent, supplied to gas grids for domestic consumption in densely populated areas. [9] We are now seeing some new possibilities for trading of LNG. Many places there are also reserves of "stranded" natural gas-resources that are abandoned because currently there is no economical way to get it to the markets. With natural gas becoming such an important and marketable commodity, producers would like to recover and get some value out of these resources which to a certain degree already are partly processed. As a way to meet these demands there is a growing interest in small scale LNG process and plant solutions to help solve the challenges mentioned above from a number of countries on almost all continents. [10] Small-scale distribution of LNG is a new approach. The source for LNG could be a smallscale LNG production facility, either a base-load LNG plant or an LNG receiving terminal. According to data provided by Gasnor (2007) production capacities of small scale LNG plants vary in the range from 2000 up to 500 000 tons of LNG per year. By comparison, a typical large scale plant has a production capacity of between 2.5 and 7.5 million tons of LNG per year. Compared to the large-scale LNG market, small-scale LNG distribution system would use smaller ships, in the range from 1 500 m 3 to around 10 000 m3 LNG (Gasnor 2007). The receiving facilities and local storage tanks are based on a modular design in order to support standardized solutions with good scalability. Small-scale LNG is mainly delivered to industrial end users, but can be also d elivered to smaller domestic users and as fuel for vehicles (mainly buses and heavy duty trucks). [11] Small-scale distribution of LNG gives many profits to new categories of consumers. Small-scale LNG could become cost-competitive with alternatives such as fuel oils. This


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could make natural gas available in regions with lower levels of demand than are commercially viable with pipelines or larger ships. Small-scale LNG is flexible, can cover widely dispersed demand at modest investment cost, is suitable to relatively small volumes of gas, and allows for competition. There are important environmental benefits to be gained from replacing oil fuel with gas: emissions of CO2, NOx, SOx and particulate matters are significantly reduced. This alternative may be an important contribution to reaching ambitious targets for reducing emissions to the atmosphere from human activities. That is also why this development is capturing the attention and interest of high-ranking politicians around the world. [12] Nowadays in Norway you can see a great interest of the small-scale distribution of LNG. Norway is rich in energy resources, particularly oil and gas, but a country with a somewhat difficult geography. Oil and gas have been produced since 1971, but only offshore. Thus all major pipelines are offshore, only on-shore for few kilometres to receiving terminals. However these few kilometres of large pipelines do not form an integrated onshore grid, they provide the opportunity for taking out some gas and distributing it locall y. Transporting liquid natural gas in bulk (LNG) is emphasized as the most appropriate solution for a country with the topography and population pattern of Norway. LNG is also the most suitable fuel for vessel and ship operators who are concerned about costs and environment. The small-scale distribution system for LNG in Norway is dominated by Gasnor. Gasnor established two production facilities for LNG at Karmøy and at Kollsnes and now is building a third production plant for LNG at Kollsnes. At these LNG plants, a high pressure gas is received from an export pipeline (Statpipe and Troll). Gasnor operates one small LNG vessel and one another should be delivered in autumn 2008. The LNG is stored in local terminals, and distributed to the end user through a pipeline. Some of the local terminals are designed for one single industrial user, but mainly the terminals are designed as a regional terminal for several customers and/or further distribution by tank lorries. Gasnor also deliver LNG to other gas distribution companies in Norway, and some LNG as fuel for heavy duty trucks and buses in England and Sweden. Nowadays in Norway there are about 30 LNG small-scale LNG terminals in operation. [13]


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4 LNG storage tanks 4.1 Background

There are variety of types of LNG tanks throughout the world according to energy needs and site environment. All of these tanks have to fulfil three basic functions:

· the liquefied gas must be stored without leakage, · the heat absorption of the gas must be kept as small as possible, · the tank must be leak tight in both directions (should prevent LNG from leakage and also should prevent any impurities from entering the tank) In general, storage tanks are broken down to three categories: underground storage tanks, in-ground storage tanks and above ground storage tanks as shown in Figure 4.1.

Figure 4.1 Various types of LNG tanks [15]

In Europe the above ground storage tanks have been adopted by most recent LNG projects. The above ground storage tanks can be subdivided, according to structural details in: single containment tanks (SCT), double containment tanks (DCT), full containment tanks (FCT) and full containment membrane tanks. Due to the high costs and schedule implications of constructing traditional storage tanks some new LNG storage techniques are still developed. Two projects of modern LNG storage tanks are presented in this work. They are the All-concrete LNG (ACLNG) tank, developed by Arup Energy, and concrete/concrete LNG tank (C/C tank), presented b y StatoilHydro.


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4.2 Single containment tanks (SCT)

A conventional single containment LNG storage tank consists of a suitable cryogenic metal inner container (economic current favour 9% nickel steel) designed to hold the LNG, with a carbon steel outer tank designed to contain the natural gas vapours at pressures up to 2.5 psig (0.17 bar), and a steel roof. This design pressure can be increased with additional engineering of the top roof to the wall joint, but at additional cost. The required distance between the bund and the tank adds significantly to the total land area. Insulations surround the inner tank to control heat leak into the tank. The outer tank is not designed to contain the LNG in the event of an inner tank leak. A secondary means of LNG containment (in case of a rupture of the inner tank) is generally provided, such as engineered earthen dike design to contain 110% of the full volume of LNG from the inner tank. Single containment tanks were the first type developed and are now used mainly in remote locations. [14]

Figure 4.2 Features of a typical single containment LNG tank.


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Advantages: [14]

· Generally the lowest installed cost per cubic meter of LNG storage (the cost of SCT is about 65% that of a corresponding FCT).

· Faster schedule, engineering and construction schedule can usually be reduced by several months from the typical 36 months for FCT.

· Regulatory approval of SCT designs has been consistent over the years and not a cause for approval delays.

· Side and bottom LNG outlets can be used as long as certain other requirements are met. Disadvantages: [14]

· In the event of an inner tank failure or spill, the outer tank steel shell will not contain the LNG and the vapours will be free to go to atmosphere.

· Requires an external dike for secondary LNG containment; typically the large, engineered earthen dike to contain 110% of the full contents of the LNG tank. Thermal radiation and vapour dispersion zones are very large and this tank requires a very large tract of land, highest for the conventional designs.

· These tanks have lower design pressures than full containment tanks. The lower pressure design results in increased size and the cost of the vapour handling system.

· Added maintenance costs to periodically repair and recoat the outer tank paint system to prevent corrosion.

· A system needs to be designed to remove accumulated storm water runoff from inside the secondary containment dike.

· Poor resistance to external forces such as flying debris; breach of outer shell is more likely than other tank designs considered.


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4.3 Double containment tanks (DCT)

A conventional double containment LNG storage tank is essentially a single containment tank surrounded by a close-in, reinforced open top concrete outer container design to contain all spill or leak from the inner tank, but not to hold any vapour realized during a spill. Like a SCT DCT consists of a suitable cryogenic metal inner container (economics currently favour 9% nickel steel) designed to hold the LNG, with a carbon steel out er tank designed to contain the natural gas vapours at pressures up to 2.5 psig (0.17 bar), and a steel roof. This design pressure can be increased with additional engineering of the top roof to the wall joint, but at additional cost. Insulations surround the inner tank to control heat leak into the tank. The outer tank is not designed to contain the LNG in the event of an inner tank leak. In addition to t his outer carbon steel wall, the DCT design also includes a concrete outer container which functions as a secondary means of LNG containment. This outer container is an engineered reinforced concrete cylinder surrounding the outer carbon steel tank shell and is designed to contain the full tank volume plus some safety margin. [14]

Figure 4.3 Features of a typical double containment LNG tank.


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Advantages: [14]

· Lower installed cost per cu bic meter of LNG storage than FCT. · Engineering and construction schedule can likely be reduced by several months from the typical 36 months for FCT.

· Regulatory approval of DCT design has set a precedent for future approvals. · Smaller thermal exclusion zones and reduced conventional onshore land requirement (due to protection provided by outermost concrete container), similar to FCT, but at a lower cost than FCT.

· Resistance to external forces is improved with the high reinforced concrete dike. Disadvantages: [14]

· Higher installed cost per cubic meter of LNG storage than SCT. · In the event of the inner tank failure or spill, the outer tank steel shell will not contain the LNG and the vapours will be free to go to atmosphere due to the open top of the high concrete secondary containment wall.

· Lower pressure design in the same as SCT, this increases the size and cost of the vapour handling system when compared to FCT.

· Increased soil bearing requirements (over SCT) and higher foundation, loads due to the weight of the outer concrete containment dike.

· Added maintenance cost to periodically repair and recoat the out er tank paint system to prevent corrosion.

· System need to be designed to remove accumulated storm water runoff from inside the secondary containment dike.

· Personnel entry into the annular space between the outer tank shell and the concrete dike for maintenances is generally considered as a confined space and requires special procedures.


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4.4 Full containment tanks (FCT)

A conventional full containment LNG storage tank consists of a suitable cr yogenic metal liner container (economics currently favour 9% nickel steel) designed to hold the LNG, with a reinforced concrete outer tank designed to contain the natural gas vapours at pressures up to 4.3 psig (0.3 bar), and a reinforced concrete roof. The outer concrete tank is also designed to contain cryogenic LNG in the event of an inner tank leak or rupture. Insulation surrounds the inner tank to control heat leak into the tank. Different types of insulation are used in different parts of the tank. Typically, the annular space between the inner and outer tanks is filled with loose perlite. In addition, a resilient blanket, such as fibreglass material, is installed on the outside of the inner tank. This blanket provides resiliency of the perlite. The reinforced concrete roof is lined with carbon steel, with the liner also functioning as framework for the concrete. Heat leak from the roof of the tank is limited by installing insulation on the suspended deck (which is suspended from the roof). There is no insulation immediately beneath the roof, and the vapour space between the suspended deck and the tank roof will be close to ambient temperature. For the bottom insulation most of the LNG tanks use cellular glass (foam glass). [14]

Figure 4.4 Features of a typical full containment LNG tank.


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Advantages: [14]

· Highest integrity design: in the event of the inner tank failure, the outer tank is design to contain both an LNG spill and the vapour generated.

· No side or bottom penetration; all pipelines pass through the roof, so in the event of external pipeline failure the tank contents do not spill out of the tank.

· Smallest thermal exclusion zone; resulting in the smallest footprint, tank spacing and the most efficient use of land. Also land required to be under control of the owner to avoid problems related to adjacent properties is minimized.

· Inherent higher pressure capabilities than either SCT or DCT; allows the use of smaller capacity vapour handling system, reducing the capital and operating costs for the vapour recovery system.

· Best resistance to external forces with complete reinforced concrete outer shell. · Concrete finish minimizes coating maintenance of the outer tank. · Concrete shell can be designed to withstand realistic impacts from missiles or flying objects.

· The effect of cold-shock, if any, will most likely be restricted to a small area, and generally should not affect the vapour-tight integrity of the tank. Disadvantages: [14]

· Highest cost per cubic meter of LNG for the conventional flat-bottomed tank designs.

· Marginally the longest engineering and construction schedule (nominally 36 months from tank contractor approval to proceed).

· Increased soil bearing requirements and foundation loads compared to SCT due to the higher weight for the outer concrete wall.

· Tank profile is roughly the same as the SCT and DCT designs.


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4.5 Membrane tanks

A conventional full containment membrane tank consists of a cylindrical thin metal membrane primary container, designed to hold LNG. This inner membrane tank is structurally supported by an outer pre-stressed concrete cylindrical tank. The outer concrete tank also serves as the secondary leak containment. Insulation surrounds the inner tank to control heat leak into the tank. The reinforced concrete roof is lined with carbon steel, with with the liner also functioning as framework for for the concrete, just like in ordinary full containment system. Applications of membrane tanks have been far less than the o ther types of tanks except in Japan and Korea. [15] The side wall and bottom slab of membrane membrane storage tank has a multiplex structure with three layers: reinforced concrete, insulation and a membrane, as shown in Figure 4.5.

Figure 4.5 Membrane LNG storage tank multiples structure. [15]

(1) A two millimetre membrane layer maintains LNG and gas tightness. The membrane is corrugated to absorb contraction due to the difference in ambient temperature and LNG temperature which is minus 162 degrees Celsius. [15] (2) Rigid polyurethane polyurethane foam (PUF) insulation insulation restricts the permeation p ermeation of heat from outside and transfers the internal gas and LNG pressure exerted on the tank side wall and bottom slab. [15]


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(3) Reinforced concrete layer, which support all structure and it is also designed to contain cryogenic LNG in the event of an inner tank leak or rupture. [15]

Advantages: [15]

· A membrane-type membrane-type tank ta nk is characterized b y higher flexibility in storage capacity capacit y comparing to the 9% Ni type.

· A membrane-type membrane-type tank syste s ystem m can be b e built inside the gravity-based structures to provide a relatively large large storage volume. volume.

· Lower material costs due to less steel consumption comparing to the 9% Ni type. Disadvantages: [15]

· Because the wall insulation system on a membrane tank is also a stru ctural component component it s efficiency is only about about one-half of the wall insulation insulation on a full containment tank. Lower thermal efficiency creates boil-off gas that must be removed by compressors.

· Construction of membrane tanks are more labour intensive and require higher skilled workers.

· The membrane on an LNG tank is only 1.5 mm thick which w hich makes it more likely to be damaged during construction. The thickness of inner tank plates for a full containment tank average about 25 mm.

· However, a membrane-type tank requires a sequential sequ ential construction schedule wherein the outer concrete structure has to be completely co mpletely built before the insulation and the membrane can be installed within a cavity cavit y within the outer structure. This normally requires a long construction period which adds substantially to the costs.

· Membrane-type Membrane-type tanks ta nks are designed by b y principles known as "experimental design". Where new shapes and sizes are required or when different d ifferent environmental and/or seismic loading conditions are to be encountered, the satisfactory performance of membrane-type membrane-type tanks at various LNG levels is difficult to insure.


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4.6 New LNG storage technologies tech nologies

Metal-lined concrete tanks have been used for the primary containment of LNG for man y years. However, However, these ty t ypes of tanks are very expensive. LNG storage tanks account account for a large portion, often up to a third or more, of the cost of a LNG terminal. Moreover the speed of delivery of an LNG terminal usually depends on the time to construct the tanks. This is most evident at import terminals. Traditional tank solutions must be built in a sequential manner with the secondary container being adva nced to a considerable c onsiderable degree before the primary container container can start in earnest. earnest. Due to the cost and schedule schedule implications of constructing traditional storage tanks, every possible effort is made to reduce material and time-related costs. Two of the modern solutions, which can reduce construction time and costs significantly, are presented below. ACLNG tanks The All-concrete LNG (ACLNG) tank was originally developed in-house b y Arup Energy . A proposed ACLNG storage storage tank consist consist of primary containment containment walls and slab constructed in post-tensioned reinforced concrete without a liner l iner and a secondary container in post-tensioned reinforced concrete with a moisture vapour barrier applied. The joint between primary container walls and the the slab is monolithic. Base Base insulation is formed of weather-proofed weather-proofed blocks b locks and a secondary bottom is ideally constructed from a non-metallic material such as a Mylar sandwich. The secondary secondar y container and foundation arrangements are essentially identical to those of conventional 9% Ni tanks. Variations from a conventional tank are needed to suit the primary container geometry and the chosen construction method. [16] Construction of concrete primary containers without a metallic liner was made mad e possible by examining concrete s permeability in cryogenic conditions. conditions. Concrete exhibits exhibits excellent performance at cryogenic cryogenic temperatures, many properties improving as the the temperature falls. A key design parameter is the permeability of concrete, co ncrete, as this affects the total quantity of LNG lost from the primary container. This must be added to the boil-off gas to assess the operational performance of the tank. The most definitive tests performed demonstrated that an intrinsic permeability p ermeability,, K' , of 10 -18 m² could be obtained for typical concrete mix designs and that a permeability as low lo w as 10-19 was possible. Concrete mix

BOIL-OFF IN LARGE- AND SMALL-SCALE LNG CHAINS design does not require special consideration, although aggregates having similar coefficients of thermal contraction to cement paste are preferable. Water-cement ratios should not exceed 0.45. Admixtures such as silica fume that reduce permeability can b e considered if readily available in country. [16]

Figure 4.6 ACLNG tank details [16]

Potential advantages: [16]

· The ability to construct the primary and secondary containers in parallel and the elimination of metallic liners considerably shortens the construction schedule compared to conventional 9% Ni tanks.

· Cost differentials increase where construction takes place in less developed countries.

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· The overall delivery schedule of the All-concrete tank is 25 months from contract award to ready-for-cool-down.

· The use of weather-proof insulation materials permits the insulation works to proceed before the tank walls and roof have been constructed

· The adoption of a non-metallic secondary bottom minimizes the need for specialist steel fabricators associated with 9% Ni tanks

· Substantial cost savings could be realized when the concept becomes established in the market place Potential disadvantages: [16]

· The perception of concrete is that it will crack and leak and this will cause extra quantity of LNG lost from the primary container.

· Use of slipform construction demands a very high level of planning and preparation not normally associated with static forms, since once started the slide will continue to the top of the wall in one continuous operation, what sometimes is hard to put into practice.

·

Material supply to the slipform is critical to the continuous operation. Concrete batch plants must have redundant capacity. Reinforcement must be bent and clearly tagged and stored for delivery to the form with at least 3 days supply available, what can give some extra challenges.

· Construction of ACLNG tank is the challenge of civil engineering and requires higher skilled workers.

· It is a new technology, which has been never confirmed in practice before, so it can cause some maintenance problems. C/C tanks The concrete/concrete (C/C) tank was originally developed by StatoilHydro. CryoTank is a registered trademark in Norway, and the inner tank (liquid containment) is a u nique solution patented world wide. It is a land based Full Containment tank which complies with standard EN 14620, and also to the near finished recommendations from the EEMUA. The patented design principle concerns the inner tank or t he liquid containment. The sandwich wall is the key solution, with an outer reinforced concrete layer, which for big tanks is supplied with pre-stressing. A 1-millimeter high ductile metallic sheet liner is


30

completely welded to each other and to the bottom steel wall base on which the concrete wall rests. The last inner layer is also concrete which secures stable form and protection of the liner against impact and fatigue forces. The bottom steel plate is conventional and welded to the wall steel base. The containment is then liquid sealed. There are no particular requirements to the concrete quality and the amount of pre-stressing, apart from having sufficient strength. All reinforcement in the inner tank is Cryobar. [17] The outer tank can be conventional, or the thick carbon steel liner of the outer tank can be substituted by ductile metallic steel sheet liner of the same material as the inner tank liner substituted the thick carbon steel liner of the outer tank. This outer liner is welded to a new type of vertical liner strips that again are anchored in the concrete. The dome is conventional. The bottom of the outer tank can be also improved. Carbon steel is substituted by 5-millimeter ductile steel plates, which also cover the t ank wall five metres up from the bottom. Foam glass insulation is put behind the ductile bottom plate and placed inside the wall and underneath the bottom. Insulation protects the concrete corner in case of LNG pooling. Hence the commonly used extra bottom for corner protection is not required. The wall insulation is about twice the thickness of conventional tanks. This is governed by necessary space to operate when erecting the liners. Other insulation is conventional. [17] Potential advantages: [17]

· CryoTank tanks can be more than twice as large as conventional tanks, i.e. larger than 400,000 m3. This increased size can be achieved by minor increased diameter and increased height. This implies smaller footprint as well as less costl y and timeconsuming construction.

· The construction time will be reduced by 6 -12 months. For import terminals this implies early sale and increased present value.

· A CryoTank of the same size as a conventional tank will be 10 to 20% cheaper. Increasing the size, fewer tanks are necessary. Substituting three smaller tanks with two larger tanks reduces cost by 30 to 40 %.

· CryoTank can be made more resistant to earthquake. Sloshing breakers can also be installed.

· Reliability against leakage with the welded steel liner.


31

· CryoTank has double insulation in the walls compared to conventional tanks. More insulation combined with increased height gives smaller surface and the boil-off is reduced to the half of what standards require. Potential disadvantages: [17]

· Use of slipform construction demands a very high level of planning and preparation not normally associated with static forms.

· Construction method for thin plate liners is especially developed for the CryoTank so it requires higher skilled workers.

· It is a new technology, which has been never confirmed in practice before, so it can cause some maintenance problems.

Figure 4.7 A CryoTank design [17]


32

5 LNG vessel types 5.1 Evolution of LNG fleet

The LNG carrier (Liquefied Natural Gas) is product of the late twentieth centur y. LNG carrier is a ship designed for transporting liquefied natural gas (LNG). LNG carriers have two principal parts, the basic ship comprising the hull and propulsion plant, and the cryogenic section consisting of containment tanks and cargo handling arrangements. They are double-hulled, and specially designed and insulated to prevent leakage or rupture in an accident. The LNG is stored in a special containment system within the inner hull where it is kept at pressure in the range of 1,060 to 1,080 millibar (absolute) and -160°C. [25] Gas carrier tanks, according to International Maritime Organization (IMO) rules, must be one of three types. Those are ones built according to standard oil tank design (Type A), others that are of pressure vessel design (Type C), and, finally, tanks that are neit her of the first two types (Type B). All LNG tanks are Type B from the Coast Guard perspective, because Type B tanks must be designed without any general assumptions that go into designing the other tank types. There are three general Type B tank designs for LNG. The first type of design, the membrane tank, is supported by the hold it occupies. The other two designs, spherical and prismatic, are self-supporting. [18]

Figure 5.1 Changes of LNG cargo tanks types. [19]


33

Existing LNG carriers cargo containments systems reflect one of two main designs: spherical design produced by Kvaerner-Moss, and membrane design by two firms: Technigaz and Gaz Transport. Figure 5.1 shows that spherical design was used by most of LNG ships till 2003. Nowadays there are ordered 21 of 145 new vessels with Moss tanks only and the rest are being built with membrane design. Technigaz technology will be installed in 44% of new buildings and 41% new LNG carriers will be equipped with Gaz Transport membrane. [19] LNG fleet is in the midst of an unprecedented expansion. At December 2000 there were 119 vessels of summary tanks capacity 12,003 MSCM. The prediction was that in 2005 would be 148 LNG carriers and 172 ships in 2010. Nobody predicted that LNG market would start develop so quickly. At the beginning of XXI century some new players entered LNG market. They ordered a lot of ships to serve their new LNG projects. These ships started to be delivered in 2003 17 new vessels, in 2004 20 and in 2005 - 29. At the end of 2005 LNG fleet comprised 195 ships (47 more then was predicted in 2000) of summary tanks capacity 23,143 MSCM. 224 LNG carriers were sailed across the oceans on 1st March 2007 and they were able to carry 27,279.5 MSCM liquefied natural gas. New orders will boost the global LNG fleet to over 300 vessels in 2008, and to 369 at the end of 2010. [19]

Figure 5.2 Age of LNG fleet [19]


34

5.2 Kvaerner - Moss spherical spherical tanks

This is the most well known tank that many people equate with the appearance of an LNG carrier. The large spherical tanks, almost half of which appear app ear to protrude above a ship's deck, is often what p eople visualize when someone says "LNG carrier." The early ear ly sphere designs were shells of 9-percent nickel steel. Subsequently, aluminium was used. The sphere is installed in its own hold of a double-hulled ship, so that it is supported around its equator by a steel cylinder (called a skirt). s kirt). The covered insulation surrounding the sphere can channel any leakage to a drip tray located under the sphere's "south pole." [18]

Figure 5.3 LNG carrier equipped with Moss tanks. [20]

(1) Moss spherical tanks - developed by Norwegian firm Moss Rosenberg Verft AS (now Moss Maritime). [20] (2) Tank material, aluminium alloy. [20] (3) Tank dome, located at the top of the tank, it contains the t he entrance for servicing, as well as for the various pipes that go inside the tank. [20] (4) Tank thickness, between 25 and 60 mm (150 mm at the equatorial rings). [20]


35

(5) Thermal insulation features, Moss Moss tanks are covered with thermal t hermal insulation panels (200 to 300 mm thick). thick). Each multilayer m ultilayer panel is comprised of phenolic resin foam on the low-temperature side (tank side), polyurethane foam on the ambient temperature side, and aluminium-plastic sheet on the exterior. [20] (6) Pipe tower, made with the same materials as t he tanks, this shaft, about 3 m in diameter, is placed vertically in the middle m iddle of the tank to accommodate accommodate loading/unloading pipes, cargo pumps (located at the bottom of the shaft) to d ischarge LNG to onshore facilities, stairs and instrumentation. [20] (7) Contraction, Contraction, when loaded loaded with LNG of approx. 162ºC, the tank contracts about 150 150 mm in diameter. However, this deformation is absorbed by contractions of the cylinder-shaped support at the equator of the tank.[20] (8) Cylinder-shaped support, in order to reduce the entrance of heat into the tank, part of the structure is made of stainless steel (thermal brake).[20] (9) Propulsion plant (can use the boil-off gas). [20] Some of the known known advantages, from an operator s viewpoint, for for spherical tanks are: they cause no operational problems, they show a great tolerance in the event o f faulty operation and an inherent ability to limit the consequences of damage, and they can be pressurized for emergency discharge of LNG or as an alternate to pumping. pu mping. Some of the known disadvantages are: they protrude through the deck and cause a visibility problem from the bridge, have a higher centre of gravity, have a higher boil-off rate. In addition the older 9-percent 9-p ercent nickel nickel steel tanks have shown significant significant amounts of swallow cracking after years of service. The cracks develop next to the welds due to the effect of the heat of the t he welding on the original material (known as the "heat-affected zone''). The cracks can be repaired by b y gouging them out and welding in new material. Aluminium tanks can have a different cracking problem. Attaching the aluminium tank to a steel cylinder is a difficult process, due to the metals involved, and cracks are liable to develop where those materials are joined.


36

5.3 Membrane tanks

In general membrane cargo tanks are composed of a layer la yer of metal (primary barrier), a layer of insulation, another liquid-proof liqu id-proof layer, and another layer of insulation. Those several layers are then attached to the t he walls of the externally framed hold. There T here are three types of "Membrane" type, which are "TGZ Mark III system" (this design is originally by Technigaz), "GT NO96 system" (this is Gaz Transport's tank design) and "CS 1 system". "CS 1 system" is a new system which adopts merits of both "TGZ Mark III system" and "GT NO96 system". GTT Mark III First sealing barrier is made of a stainless steel with with waffles to absorb the thermal contraction when the tank is cooled down. Second sealing barrier, made of Triplex, has a function of preventing the cargo from leaking out during a pred etermined etermined period of time ti me when the primary barrier is broken down. The insulation layers are made of polyurethane foam. Plywood is installed between the first and second sealing barriers and the first and second insulation barriers, allows constant load to be applied to the sealing barriers due to the uniform arrangement of the insulation barriers, and reduces the displacement created due to vertical load. Glass wool is installed between b etween the insulation boxes, reduces the horizontal displacement and prevents the occurrence of high stress. stress. [21] GTT NO 96-2 First and second sealing barriers are sheets of Invar, an alloy of 36-percent nickel steel. Unlike regular steel, Invar hardly contracts upon cooling. The insulation layers la yers are plywood boxes boxes holding perlite, perlite, a glassy material. Function Tongue is installed at an insulation box and welded in three-ply way between membrane sheets to connect them, and it allows the membrane and insulation box to be connected to each other. Joist is installed between the insulation boxes to reduce horizontal displacement and prevent high stress from being created [21] Table 5.1 consists consists the most important important design s intricacies of both GTT Mark III and GTT NO 96-2 systems. systems.


37

Table 5.1 Features of LNG membrane cargo containment systems Gaz Transport System

Technigaz System

36% nickel steel (Invar)

Stainless steel

(Measures are not required due to very low coefficient of thermal expansion of membrane)

By expansion and convection of membrane

Insulation boxes filled with Perlite

Plastic foam

BOR (insulation thickness)

0.15%/day (about 530mm)

0.15%/day (about 250mm)

Secondary barrier

The same as primary

Triplex

Tank section

Insulation structure

Tank material Measures for thermal expansion and contraction Insulation material

Some of the known advantages for the membrane tanks are: they offer flat deck therefore adequate surface for topsides, this configuration gives also a good visibility from the bridge and improve maintenance of the deck, assure structural continuity throughout the hull space since the deck has no openings for tanks, a maximized hold space reduce the overall ship dimensions and gross tonnage for a given LNG cargo capacity, and it is a cost effective design for large tanks - competitiveness compared to other t ypes of LNG carriers. Some of the known disadvantages, from an operator s viewpoint, for the membrane tanks are: they are more likely to rupture during the collision, require higher primary barrier maintenance, and the most important is that they show a possibility of damage to the membrane, piping, and pumps support structures from sloshing (the study of sloshing is one of the greatest technical challenges presently facing today s designers).


38

5.4 Prismatic tanks

The second type of self-supporting tanks after Moss system is the Self-supporting, Prismatic, Type B (SPB) tanks by Ishikawajima Heavy Industries (IHI). These tanks are reminiscent of the tanks on old single-skin oil tankers. Prismatic tank do not form part of the ship s structure and are manufactured separately, incorporating pumps and lines etc before being inserted into the hull. Unlike other systems, they require their own support structure inside the tank, making them heavier and requiring more detailed i nspection. The material for tank construction can be aluminium, 9-percent nickel steel, or 304 stainless steel. The tank is subdivided by a centreline liquid tight bulkhead and a swash bulkhead into 4 spaces. Because of this, natural frequency of the liquid inside tank is far from that of ship s motion, eliminating any chance of resonance of the liquid cargo and ship two motions. The tanks are installed in the hold of a double hull ship and are insulated with covered polyurethane foam that also is able to serve as channelling for any possible tank leakage to drip trays. [22]

Figure 5.4 Inside view of SPB tank. [22]


39

IHI s technology, which is particularly robust, has been in use for years, both in LNG ships and in floating storage and offtake systems. The Polar Eagle and the Arctic Sun both utilize SPB storage and have been plying the Alaska-Japan route for many years. Elsewhere, the technology is employed in Chevron s SPB-enabled Escravos LPG Floating Storage and offtake unit that was installed offshore Nigeria in 1997. Nowadays because the membrane and Moss solutions are develop very rapidly IHI is no longer building the system and low numbers make units relativel y expensive. [22]


40

6 Large-scale LNG chain 6.1 LNG value chain

To make LNG available for use, energy companies must invest in a number of different operations that are highly linked and dependent upon one another. Figure 6.1 shows the main elements of the Large-Scale LNG Chain. The Chain starts with gas production, usually from offshore wells though some plants receive gas from onshore sources. The gas produced can be from a gas field (nonassociated gas) or may be produced along with oil (associated gas). The distinction between associated and nonassociated gas is important because associated gas must have liquefied petroleum gas (LPG) components (i.e., propane and butane) extracted to meet heating value specifications of the LNG product. [23]

Figure 6.1 The LNG chain-from production to user. [24]

The production gas enters the LNG liquefaction facility and goes through several steps of treating before being liquefied. The LNG leaving the liquefaction plant must b e stored until a ship arrives to transport the product. Although it would be possible, in theory at least, to run down the product directly into the ship and greatly reduce or eliminate storage. Storage tanks are less expensive than ships and economics favour storage at the facility. [23]


41

Stored in production facility LNG is then transported to regasification terminals. There is only one economical solution of transport these quantities of liquid to distant destination shipping. LNG tankers are double-hulled ships specially designed and insulated to prevent

leakage or rupture in an accident. The ships typically travel at 19 knots, but to calculate a total duration you have to add at least a day of turn-around at each end. [23] To return LNG to a gaseous state, it is fed into a regasification plant. On arrival at the receiving terminal in its liquid state, LNG is first pumped to a storage tank, similar to those used in the liquefaction plant, at atmospheric pressure. The time needed to unload a ship once the unloading pumps, are started is about 12 to 18 hours. The receiving terminal stores the LNG, which is later vaporized and sent out into a pipeline, or in some case directly to an electric power plant (commonly done in Japan).[23] Due to heat leakage into LNG during holding , shipping and loading/unloading modes large quantities of boil-off gas are generated. From the receiver s viewpoint the most important are unloading and holding modes, and the loses of methane during these periods. The thermal analyses of boil-off of LNG for these modes are carried out below.


42

6.2 Thermal analysis of boil-off of LNG for the unloading mode

The unloading mode is the period when an LNG carrier is moored to the jetty and is connected via the unloading arms and the jetty piping to the onshore storage tank. The pumps on the LNG carrier will transfer the LNG in both the unloading and the recirculation lines to the onshore storage tanks. At the end of unloading, pressurized nitrogen gas will be used to purge the arms o f LNG before disconnecting. A typical LNG Unloading System consist of all the facilities, infrastructure and equipment required to safely dock the LNG ship, to establish the necessary ship to shore interfaces, and for transferring the cargo from the ship s tank to the onshore piping. Typical unloading time for a full-size tanker (125,000 to 250,000 cubic metres) is 12 to 18 hours, depends on a size of the ship. [25] Main factors that affect the quantity of LNG boil-off during the unloading mode are the followings: [25]

· Higher ship s operating pressure than the LNG storage tank · The energy used by the ship s pumps, transferred to the LNG as heat · Heat leak into the LNG through the pipes, and equipment · Heat leak into the vessel s tank · Vapour returned to the ship · Vapour displacement Tanks operating pressure Differences in operating pressures between ship and onshore storage tank can affect the quantity of boil-off gas. The cargo tanks of the LNG ships operate in the range of 1060 to 1080 millibar absolute pressure. The LNG cargo attains an equilibrium temperature corresponding to the cargo tank pressure. Each 10 millibar increase in operating pressure will result in approximately 0.1°C increase in the LNG temperature. So if we have differences in operating pressures between cargo tank and onshore storage tank, for example the LNG cargo tank operates at 1,060 millibar absolute p ressure, and the onshore LNG tank operates at 1,050 millibar absolute pressure, the LNG in the ship will be about 0.1°C warmer. To attain to the new tank conditions the LNG will cool itself, by evaporate


43

a small portion of the LNG. This process is called auto- refrigeration. For the conditions assumed above, each cubic meter of the LNG will result in approximately 0.3kg of boil-off gas. At a typical unloading rate of 12,000m3/hr, this translates into 3,600kg/hr of boil-off due to the 10 millibar lower pressure in the onshore tank. [25] Energy of pumping One of the very important element in transporting LNG, which has a big effect on boil-off rate is the transfer LNG from the ships to the onshore storage tanks. LNG is transferred from the ships to the onshore tanks by the pumps located on the ships. The LNG ships have two different types of pumps. These are the large cargo pumps for transferring LNG, and the small spray pumps that provide LNG for the spray ring that helps keep the entire storage container in a cool state. The size and capacity of these pumps vary from one ship to another, but the cargo pumps usually have a capacity of 1,200 to 1,400 m3/hr and develop 150 to 240 metres of head. The spray pumps usually have a capacity of 40 to 50 m3/hr [23] When we consider the most typical 130,000 cubic meter tanker it requires over 3,000kW of pumping energy. Almost all this energy is converted to heat and adsorbed by the LNG. This large amount of heat is sufficient to heat the LNG by as much as 0.5 °C. To keep the temperature constant corresponding to the LNG tank pressure some portion of the LNG will evaporate. This phenomenon can result in about 20,000kg/hr of boil-off gas. All or a portion of this boil-off gas can be suppressed if the LNG tank can be operated at higher pressure. [25] Heat leak vie unloading line The unloading piping also referred to as the unloading line is the transfer pipe from the jetty area to the LNG storage tank area. During periods between ship arrivals the unloading line should be maintained in a cold condition and not allowed to warm up due to heat leak from the surroundings. To keep the unloading line cold, a small portion o f the LNG from the discharge of the first stage sendout pumps is allowed to flow through the unloading line, toward the jetty. At the jetty this LNG is diverted to a smaller-sized recirculation line, and returned to the onshore process area. [25] There are two choices for configuring the unloading line:


44

· One large-diameter unloading line with a smaller recirculation line · Two equal-sized lines, each sized fro 50% flow. With the first configuration, the majority of the unloaded LNG will be transferred through the larger line, which is usually in the 32-inch to 36-inch range and a small portion through the recirculation line, 10 to 12-inch. With the second configuration flows in both pipes are equal, and during the holding mode the second unloading pipe also serves as the recirculation path. Typically, the unloaded line in this configuration will be in 24 or 26inch range. [25] The Unloaded pipelines can be made of stainless steel, 9% nickel and invar 36. They are usually either mechanically insulated with up to 8 inch thick glass foam or polyisocyanurate insulation, insulated using a pipe in pipe technique with aero gel (or other powder type) insulation, or a high vacuum jacket insulation using one of several techniques. [26] However the unloaded pipelines are insulated, there is always some heat leak into the LNG. The rate of this leaking per square meter of outside insulation is small of course, but when we consider the large diameter and long length of the unloading line it can result in a meaningful heat leak. Some examples of the boil-off gas rates generated b y insulated pipeline heat gain are shown in the Figure 6.2.

Figure 6.2 Boil-off gas generated by insulated pipeline heat gain. [26]


45

We could consider some heat that leakage into the LNG through the unloading arms, which are normally uninsulated, but the extreme cold of LNG causes ice build-up on the exterior surface of these arms. The ice layer acts as insulation, so heat inleak is relatively small and can be omitted. [25] Heat leak into ship cargo tanks Cargo tanks in LNG ships also absorb some quantities of heat from the ambient during the voyage. Due to warming up during transportation, gas naturally evaporates from the cargo. Boil-off typically averages 0.12 to 0.15% per day of full tank contents, depends o n tanks type. When we consider a typical 130,000 cubic metre tanker, about 150 to 195 cubic metres of LNG will boil-off each day. This corresponds to a boil-off rate of 2,800 to 3,600 kg/hr. Typically the boil-off gas generated during voyage is recovered. Until now ships have employed gas compression and use the boil-off gas as fuel for the propulsion systems. However, the high consumption of the steam turbine, as compared to last-generation diesel engines, results of their replacement. Instead of the common application of using the bo iloff gas as fuel, the LNG BOG re-liquefaction systems are used. The LNG re-liquefaction system has merit in the large savings in total fuel consumption and improved propulsion redundancy. [25] Ship vapour return Ship vapour returned from the storage tank is also the bo il-off source somehow. During unloading operation large volumes of LNG are pumped out of the ship during a short time. This results in rapid pressure drop or even in a tendency to create a vacuum. To offset this, and to maintain the cargo tanks at their operating pressure, natural gas is brought in to replace the void created by the exiting LNG. Some of the vapour needs of the ship will be satisfied by the boil-off its own cargo tanks, but the remaining volumes needs to be transferred from onshore. The pipeline to transfer natural gas from onshore plant to the ship is referred to as the vapour return line. The ship vapour return line, unlike the unloading line, is not maintained in a cold condition between ships unloadings. During the initial period of unloading, until the line cools do wn, the vapour reaching the jetty will be to warm to be admitted into the cargo tanks. The gas is therefore cooled at the jetty, in a desuperheater, before it is transferred to the ship. [25]


46

When we consider a typical 130,000 cubic metre tanker and assuming a tanker unloading at 12,000m3/hr, this correspondents to about 22,000 kg/hr of gas (at -160°C), needed to maintain the cargo tank pressure. Cargo tank boil-off provided about 3,600 kg/hr (boil-off rate 0.15%) but the remaining volumes, about 18,400 kg/hr, will have to b e delivered through the ship vapour return line. [25] Physical vapour displacement The LNG entering the tanks will physically displace an equal volume of vapour. Though this is not boil-off in the true sense, it does contribute to the net volume of gas exiting the tank, and hence needs to be considered in sizing the boil-off system. The scenario in the LNG storage tank is merely a mirror image of what in the ship cargo tanks. For example, if LNG is being unloaded at 12,000 m 3/hr, a similar volume of vapour is physically displaced from the tank. This volume would correspond to approximately 22,000 kg/hr of natural gas displaced from the tank. [25]


47

6.3 Thermal analysis of boil-off of LNG for the holding mode

The holding mode we can refer to as the period between unloadings. This system consists of one or more special designed storage tanks. It is a very important component in largescale LNG chain, which provides a buffer between the LNG discharged from the ships and the regasification system. In general you can say that the minimum required storage capacity is the volume of LNG discharged from the largest ship expected at the terminal. In practice this capacity is larger than this minimum to provide a cushion to account for scheduled and unscheduled delays in ship arrival. The current technologies used to store LNG are to be reviewed in particular in the chapter 4. Main factors, which affect on the boil-off gas rate during the holding mode, are [25]:

· Heat leak from the surroundings into the LNG via the floor, walls and roof o f the LNG storage tanks

· Barometric pressure drop · The phenomenon referred to as rollover Heat leak into LNG storage tanks Heat leakage into LNG storage tanks is the main factor that causes boil-off during the holding mode. To predict the boil-off rate a thermal a nalysis of the LNG storage tank is required. The structural details of LNG tanks are usually very complicated as presented in chapter 4, so the full thermal analysis modelling including all the components inside the LNG tank may involve cumbersome tasks and even be impractical. A simplification thermal analysis of the 200,000 cubic metres LNG storage tank was showed in the subchapter 6.4. According to made calculations the boil-off rate averages 0.07 to 0.095% per day of full tank contents. This correspondents to about 2,600 to 3,300 kg/hr or 62,400 to 79,200 kg/day per tank. Barometric pressure drop Barometric pressure drop can cause a significant increase in the boil-off rate. Storage tanks are operated generally over a small range of gauge pressure. Typical LNG storage tanks operate in the range of 1,050 to 1,250 millibar absolute pressure. When barometric pressure drops, the absolute pressure in the tank falls as well. To equilibrate with this lower


48

pressure, the temperature of the L NG in the tank has to fall (by approximately 0.1 °C for every 10 millibar drop). The only one way to decrease the temperature in the tank is by release some of the liquid to gas. Of course it can be estimate the rate of boil-off due to changes and rate of changes in tank pressure. A drop in barometric pressure has a real matter if it is rapid, because only then it can cause a significant increase in the rate of boiloff from the LNG tank. So if in some locations rapid drops in barometric pressure are expected in designing vapour handling systems, it is prudent to make some reasonable allowance for barometric pressure drops. [25] Boil-off by rollover Incorrect maintenance of the LNG tank can result in phenomenon referred to as rollover. Under certain conditions it is possible for two different cargoes of LNG, having different densities, to form two separate layers or strata in the LNG storage tank. Liquefied Natural Gas is generally stored in refrigerated tanks at temperatures of about -160°C and pressures slightly above atmosphere in liquefaction plants and LNG regasification terminals. Heat leaks, even in well-insulated tanks, cause a slow boil-off of the LNG, and this requires removal of some vapour. During this weathering process the composition of the LNG changes because the small amount of nitrogen present is much more volatile t han the methane and the heavier hydrocarbons are effectively non-volatile at storage conditions. Nitrogen boils off preferentially leading to an increase in the bubble point of the mixture and a reduction in liquid bulk density. In nitrogen-free LNG, loss of t he more volatile component methane leads to a slight increase in saturation temperature without a significant change in the liquid density. The density variations resulting due to loss of nitrogen lead to stratification, as shown in Figure. 6.3. [27]

Figure 6.3 An LNG storage tank with the liquid stratified


49

In any of aforementioned instances, the temperature creep will ultimately cause a slightly warmer layer of product to boil off . This layer will then rise to the top in the tank s vapour space, and it will evaporate and become denser. This phenomenon is called Weathering . Subsequent heating then can cause the product to stratify in the tank, with the lighter layer on top. If the bottom layer continues to heat, its density can begin to resemble that of the upper layer, and this will cause rapid mixing and instability in the tank. As the densities of two layers approach each other, the two layers mix rapidly, and the lower layer which has been superheated gives off large amounts of vapour as it rises to the surface of the tank. This phenomenon is known as rollover. The large amounts of vapour generated by this phenomenon can cause a dramatic vapour expansion and increase in internal tank pressure. [27] Rollover has been studied extensively and physical models have been developed to predict tank behaviour under rollover conditions. Correct tank filling procedures and proper operational practices should prevent stratification from occurring. In addition, tanks are provided with sophisticated monitoring devices than can help in early detection of stratification. Because of these reasons the sizing of the boil-off gas handling system does not require a provision for rollover. However, in the design of the tank overpressure protection system it is prudent to make an allowance for rollover. [27]


50

6.4 Thermal analysis of the LNG storage tank

LNG has a cryogenic temperature as low as 163C to ensure the minimum storage volume when stored in LNG tank. Of the various types of LNG storage tanks, the full containment, above-ground type (Figure 4.3) is now employed worldwide; thus, it is selected as the main structural type considered in this study. However, the structural details of the FCT tanks are very complicated as presented in the Subchapter 4.4, so the full thermal analysis modelling including all the components inside the LNG tank may involve cumbersome tasks and even be impractical. A convenient procedure of thermal analysis of t he LNG tank was proposed by Se-Jin Jeon, Byeong-Moo Jin and Young-Jin Kim in an article entitled Consistent thermal analysis procedure of LNG storage tank , published in Structural Engineering and Mechanics, Vol. 25, No. 4 (2007). A thermal analysis of the LNG storage tank, presented in this thesis work is based mainly on this article.

Roof analysis Let s assume the equilibrium of the heat flow rates penetrating the roof (Figure 6.5) in a steady state.

Figure 6.4 Heat flow rates through the roof

We can not neglect the effect of convection between the outer face and the environment, in which the outer face temperature makes a slight difference from t he ambient temperature.


51

To efficiently introduce the convection effect into the present formulation, a concept of equivalent convection thickness is devised. This indicates an add itional imaginary thickness of concrete attached to the actual concrete thickness by which we can conveniently set the surface temperature equal to the ambient temperature. Convection heat flux can be expressed by Eq. (6.1) [28], where

is a temperature

difference between the surface and environment, and h c is the convection coefficient of the concrete. q

= hc DT ,

(6.1)

Heat flux by conduction in a surface normal direction (n) through the imaginary concrete thickness (tc,eq ) is expressed in Eq. (6.2) [28], where c is the thermal conductivity of the concrete. q

= lc

¶T DT = lc , ¶n t c, eq

(6.2)

By equating Eqs. (6.1) and (6.2), an equivalent convection thickness can be calculated, as in Eq. (6.3) [28] t c ,eq

=

lc hc

,

(6.3)

In Figure 6.4 three kinds of heat flow rates are considered, Q1 and Q3 for the heat conduction and Q2 for the heat radiation, as follows: [28]

æ T - T ö = çç lc a b ÷÷ Aroof , t c ø è

(6.4)

= ( F × e × s (T b4 - T c4 )) Aroof ,

(6.5)

Q1 Q2

Q3

where

d is

æ T - T ö = çç ld c d ÷÷ Adeck , t d ø è

(6.6)

the thermal conductivity of the deck insulation; tc and td are the thicknesses of

concrete roof and deck insulation, respectively; Aroof and Adeck are the areas of the roof and suspended deck, respectively; F is the form factor; is the emissivity; and is the StefanBoltzmann constant.


52

Here, the conduction effects of the carbon steel liner attached inside t he concrete roof and the suspended deck itself may be neglected due to their negligible thicknesses and high thermal conductivities. Note that tc should be calculated by adding the equivalent convection thickness to the outer face of the actual concrete thickness. The resultant emissivity in Eq. (6.5) can be calculated taking into account an interaction of two relevant materials as shown in Eq. (6.7) [28]:

e=

1 1

e cs where

cs is

+

1

e d

,

(6.7)

-1

the emissivity of the carbon steel liner and d that of the deck insulation.

When a heat balance is achieved in an equilibrium condition, the equality of Eqs. (6.4) to (6.6) can be established. We can determine the temperatures and heat rates shown in Figure 6.4 by solving these nonlinear systems of equations as represented in Eq. (6.8) [28]. Q1

= Q2 = Q3 ,

Wall analysis Fig. 6.5 shows the original configuration of the LNG wall.

Figure 6.5 Configuration of the LNG tank wall

(6.8)


53

Let s convert insulation into equivalent concrete with the condition that the heat flux should be equivalent even after the conversion, as shown in Eq.(6.9) [28] and Fig. 6.6, by which the equivalent concrete thickness (tci,eq ) corresponding to an i-th insulation can be obtained in Eq. (6.10) [28].

Figure 6.6 Configuration of the LNG tank wall using equivalent concrete.

q

= li

DT i DT = li i , Dt i t ci ,eq

t ci ,eq

=

lc t , li i

(6.9) (6.10)

The aforementioned procedures are based on heat conduction theory for a one-dimensional case. Therefore, the theories can be applied to the bottom slab precisely but can be approximately applied to the wall. Strictly speaking, the temperature distribution of the wall part of circular tank structures follows the axisymmetric heat conduction theory shown in Eq. (6.11) [28], where the heat flow rate (Q) is represented for t he circumference of circular wall and the wall height (L). Q

=l

DT × 2p × L , r + t ö æ log e ç ÷ è r ø

(6.11)

The reason why a one-dimensional theory can be alternatively applied to the heat transfer through the LNG tank wall is that, for almost all the LNG tank dimensions, the radius (r) is sufficiently larger than the thickness (t) of the concrete wall or the wall insulation layers.


54

For such conditions, it can be proven that axisymmetric theory is well approximated to a sufficient degree of accuracy using one-dimensional theory. By substituting the Taylor series expansion of the natural logarithm of Eq. (6.12) [28] into Eq. (6.11), the onedimensional heat conduction equation of Eq. (6.13) [28] can be derived, where 2 rL indicates nothing but the area. It also indicates that the logarithmic temperature distribution of Eq. (6.11) can be approximated by the linear distribution of Eq. (6.13). 2

3

æ r + t ö = log æ 1 + t ö = t - 1 æ t ö + 1 æ r ö - ... » t , log e ç ÷ ÷ ç ÷ ç ÷ eç r è r ø è r ø r 2 è r ø 3 è t ø Q

= lc

DT t c ,eq

× 2prL ,

(6.12) (6.13)

Where tc,eq should be calculated by adding the equivalent convection thickness (like in roof analysis) and equivalent thicknesses of all insulation layers as shown in Eq. (6.14) [28].

lc l t i + c + t c , hc i =1 li n

t c,eq

=å

(6.14)

Bottom slab analysis Analysis of the bottom slab is similar to the procedure used in the analysis of the wall. First we convert bottom s insulation into equivalent concrete with the condition that the heat flux should be equivalent even after the conversion, using Eq. (6.10). t ci ,eq

=

lc t , li i

(6.10)

Then the heat flow rate through the bottom slab can be obtained in Eq. (6.15) [28] as: Q = lc

DT t c ,eq

× pr 2 ,

(6.15)

Note that tc,eq should be calculated by adding the equivalent thicknesses of all insulat ion layers, as shown in Eq. (6.16).

lc t i + t c , l i =1 i n

t c ,eq

=å

(6.16)


55

Numerical example Table 6.1 shows the thicknesses of the main sections of an LNG tank with 2 00,000 m3 capacity adopted in this example. Table 6.1 Dimensions of the LNG tank [28] Sections

Thickness [m]

Remarks

Wall

0.75

General part

Roof

0.6

General part

Bottom slab

1.8

General part

Diameter of wall

92.0

Inner diameter

Radius if curvature of roof

73.6

Inner radius

Height of wall

36

Except ring beam

Table 6.2 contain the properties of concrete at normal temperature. Table 6.2 Concrete properties at normal temperature [28] Properties

Value

Poisson s ratio ( c)

0.2

Density ( ) [kg/m3]

2300

Thermal conductivity ( c) [W/(m·K)]

2.324

Specific heat (cc) [J/(kg·°C)]

920.5

Convection coefficient (hc) [W/(m 2·K)]

12.78

Coefficient of thermal expansion ( c) [/°C]

1 ×105

Roof The form factor (F) (or, alternatively, view factor), which is a fu nction of various factors, is defined with reference to two surfaces that radiate toward each other. However, in the case of a flat dome roof of a typical LNG tank and suspended deck, the form factor can b e assumed as a unity. Additionally required information is:

d =

0.038 W/(m K) [28]; td = 0.5

m; cs = 0.66 [28]; d = 0.96 [28]; Aroof = 7467.4 m2; Adeck = 6647.6 m 2;  = 5.67 10-8 W/(m2 K 4) [28].


56

(1) Equivalent convection thickness (Eq. (6.3)). t c ,eq

=

l c hc

=

2.324 = 0.182m 12.78

(2) Emissivity (Eq. (6.7)). 1

e=

1

e cs

+

1

e d

= -1

1 1 1 + -1 0.66 0.96

= 0.6423

(3) Heat flow rates (Eqs. (6.4) to (6.6)), with T a = 288.15K and Td = 110.15K. Q1

æ T - T ö 288.15 - T b ö æ = çç lc a b ÷÷ Aroof = ç 2.324 ÷ × 7467.4 0 . 6 + 0 . 182 t è ø c è ø

Q2

= ( F × e × s (T b4 - T c4 )) Aroof = (1 × 0.6423 × 5.67 × 10 -8 (T b4 - T c4 ))7467.4

Q3

æ T - T ö T - 110.15 ö æ = çç ld c d ÷÷ Adeck = ç 0.038 c ÷6647.6 t d ø 0.5 ø è è

(4) Solve the nonlinear systems of equations (Eq. (6.8)). T b

= 284.3 K

T c

= 280.8 K

Qr

= 6.174 × 10 6 W

Wall Table 6.3 shows the thicknesses, thermal conductivities and the corresponding equivalent concrete thicknesses (Eq. (6.10)) of insulation layers of the wall considered in this example. Table 6.3 Insulation layers of wall [29] Material

Actual thickness

Thermal conductivity

Equivalent thickness

[mm]

W/(mK)

[mm]

9% Ni inner tank

10

Resilient glass blanket

12

Not considered 0.038

18347

BOIL-OFF IN LARGE- AND SMALL-SCALE LNG CHAINS Perlite powder

635

Carbon steel liner

5

Outer tank wall

750

0.023

57

36893 Not considered

2.324

750

Convection effect

182

Total thickness

56170

Heat flow rate through the wall (Eq. (6.13)), with T a = 288.15K and Td = 110.15K. Qw

= 2.314

288.15 - 110.15 × 2p 46 × 36 = 7.663 × 10 4 W 56.173

Bottom slab Table 6.4 shows the thicknesses, thermal conductivities and the corresponding equivalent concrete thicknesses (Eq. (6.10)) of typical insulation layers of the bottom slab considered in this example. Table 6.4 Bottom slab configuration. [29] Material

Actual thickness

Thermal conductivity

Equivalent thickness

[mm]

W/(mK)

[mm]

9% Ni inner tank

6

Ply wood

12

0.209

133

Dry sand

88

1.104

185

Foam glass 1

200

0.038

12,232

Dry sand

95

1.104

200

9% Ni secondary protection

Not considered

5

Not considered

Ply wood

12

0.209

133

Dry sand

88

1.104

185

Foam glass 2

300

0.038

14,525

Dry sand

95

1.104

200

Carbon steel liner

5

Outer tank bottom slab

900

Not considered 2.324

900

(distance to the heater) Total thickness

32,516


58

Heat flow rate through the bottom slab (Eq. (6.15)). Qb

= 2.314

288.15 - 110.15 × p 46 2 = 8.457 × 10 4 W 32.516

Boil-off gas generation Assuming that all the heat which leaks through the wall and bottom slab and only 5% of the heat which leaks through the roof warms the LNG, we have: Q = 0.05 × Qr + Qw

+ Qb = 4.699 × 10 5 W

The boil-off rate (in % of storage per day) can be calculated directly for the 200,000cubic metres tank by Eq. (6.17) [29] and Eq. (6.18) [17] as follows: BOG(kg / hr ) =

Q( J / s) × 3600( s / hr ) Heat _ of _ vaporization( J / kg )

,

(6.17)

( BOG (kg / hr ) / Liquid _ density ( kg / m 3 ) × 24(hr / day ) × 100% BOR(% / day ) = , Tank _ volume(m 3 )

Table 6.5 BOG and BOR for numerical example.

Tank size [m3]

Cargo

200,000

Density

Heat of vaporization

[kg/m3]

[J/kg]

BOR

BOG

[%/day] [kg/hr]

LNG (Snøhvit) 450.61 [28]

640,360 [28]

0.07

2642

Pure methane

509,500 [28]

0.095

3320

419.64 [28]

(6.18)


59

6.5 BOR in large-scale LNG chain

Table 6.6 is a tabulation of quantities of boil-off gas generated during holding and unloading modes for a receiving terminal for the set of conditions and assumptions listed below. It is emphasized that the boil-off rates will vary significantly as the design parameters change, and the tabulation here is intended merely to illustrate the boil-off rates for a specific set of assumptions. Basic assumptions: Ship cargo tanks volume ......................................................................... 130,000 m 3 Cargo tank pressure ................................................................................ 1,060 mbar (ab.) Ship cargo tank heat leak ........................................................................ 0.15 %/day Unloading rate ........................................................................................ 12,000 m 3/hr Unloading line length.............................................................................. 1,000 m each Unloading line size ................................................................................. 2 x 24 inch Ship cargo pump head............................................................................. 150 m Onshore storage volume.......................................................................... 200,000 m 3 Onshore LNG tank pressure.................................................................... 1,050 mbar (ab.) Onshore tank heat leak ........................................................................... 0.08 %/day Table 6.6 Boil-off gas sources, an example study Source of boil-off

Unloading Mode,

Holding Mode,

kg/hr

kg/hr

3,600

-

Energy of pumping

20,000

-

Unloading line heat leak (vacuum insulated)

1,600

-

Ship cargo tank heat leak

3,600

-

Onshore LNG tank heat leak

2,800

2,800

Vapour return to ship cargo tanks

(22,000)

-

22,000

-

Flash due to difference in tanks (ship and onshore) operating pressures

Displacement from LNG tanks due to unloaded LNG


60

As presented above large quantities of boil-off gas are generated in large-scale LNG chains. It has been also discussed that the unloading mode vapour load can be many times that in the holding mode. According to the Table 6.6 total quantity of boil-off gas, generated during unloading operations, can even reach a value of 25,200 kg per hour. Assuming that the time needed to unload a ship is about 12 to 18 hours, about 300,000 to 450,000 kg of boil-off gas is generated. A quantity of boil-off gas generated during the transport by ships has also a significant meaning. The ships typically travel at 19 knots (1 knot 0.514 m/s). Assuming that the average distance that ships have to cover is about 4000 km, that gives about 5 days of shipping. As presented before ships produced about 3600 kg of boil-off gas every hour, so the total quantity of boil-off gas generated during the whole journey can be about 430,000 kg. According to the calculations made in the subchapter 6.4, current LNG storage tanks are designed to limit the boil-off gas generation to about 0.07 to 0.095% per day. Assuming that LNG is kept in the tank up to ten days, a 200,000 cubic metres tank generates about 600,000 to 800,000 kg of boil-off gas during the storage. In 2006, about 211 billion cubic metres of natural gas were imported in t he form of LNG [4]. If make an assumption that all this quantity of LNG were transported by 130,000 cubic metres tankers, each of the unloading operations took 18 hours, and LNG were kept in the storage tanks for ten days, about 5 billion cubic metres (about 2.061012 kg) of boil-off gas were generated. Of course a real boil-off rates will vary significantly as t he design parameters change (design parameters means here: ships and tanks sizes, delivery time, duration of unloading operations etc.), and the numbers presented above are intended merely to illustrate how big the boil-off gas generation can be. Large quantities of boil-off gas can increase substantially the greenhouse gas emissions. It is worthy to say that only small portion of generated boil-off gas is vented or flared, at least in theory. Not all companies physically measure venting/flaring. Often, from an operator s point of view there is no need to measure the vent/flare unless undertaking a study to see the economic losses resulting from venting/flaring, or if required to do so b y national


61

legislation. According to this infor mation we can state that the venting or flaring of methane does not constitute a major source of GHG from the LNG Chain. Disposition of gas that evaporated contribute an additional source of GHG emissions. As discussed above most portion of boil-off gas is collected and recirculated. Recirculation of boil-off gas requires compression equipment. Compressors along with the drivers to power them are large single point emissions sources, resulting in CH4 emissions due to leakage, and CO2 emissions from fuel combustion to power the compressors. Compressor stations can have upwards of 2,500 different components, nearly all of which are susceptible to leaks whether intentionally (vented emissions) or unintentionally (fugitive emissions). [30] A good review of CO2 life cycle of LNG, including liquefaction, transport and regasification stages was presented by Tamura (2001) et al. According to his study over half of the CO2 emissions associated with liquefaction of natural gas arise from the refrigeration compressors/turbines used to cool and compress the natural gas. Another significant source of emissions arises from the removal of CO2 from the feed gas stream, however, emissions can vary greatly from field to field depending on the CO2 content of the source gas. There is some venting of CO2 associated with LNG production. For example, while the CO2 content of raw gas may be low enough to be suitable for pipeline transport, it still may have to be removed during liquefaction. Carbon dioxide has a higher freezing point than LNG, so if it is not removed prior to liquefaction, it will freeze out in the processing train causing blockages. As part of the CO2 removal process, the gas is often vented into the atmosphere. [30] Gas vapours also are released when LNG is loaded into tanks on cargo ships. These vapours are either flared, or collected by a compressor and re-injected into the LNG liquefaction process. The temperature of the ship when it arrives will impact the amount of vapours released, and thus the feasibility, and costs, of flaring versus recovery. Ships will normally arrive cold, but not as cold as when the L NG is in the ship. As these ships are loaded with LNG, some of the LNG immediately vaporises. These initial vapours are normally flared. [30]


62

Emissions from LNG transport were examined by looking at LNG transportation between Indonesia and Japan. Average emissions were determined using the average amount of fuel loaded, the amount of LNG boil off gas and fuel oil consumed during transport and cargo handling. [30] Regasification emissions, reported by Tamura et al., used an assumption that only 0.15% of the gas is used to run the regasification terminal, while electricity, which may be generated with cleaner energy sources, provides the additional energy requirements. These values were used as lower and upper bounds of the range of emissions from regasification of LNG. The results from Tamura s studying are presented in the Table 6.7. Table 6.7 Average emissions intensity of various life-cycle stages of LNG imported by Japan Stage of life cycle

Emission intensity: g-CO 2e/MJ *

Liquefaction

2.15

CO2 from fuel consumption

1.43

CO2 from flare combustion

0.09

CH4 from vent

0.15

CO2 in raw gas

0.48

LNG transport

0.44

Regasification terminal

0.36

Source Tamura I. et al. 2001 *

CO2 equivalent per LNG heat value at liqu efaction terminal outlet.

Using the numbers from the Table 6.7 we can evaluate approximate quantity of CO2 emissions from the typical LNG train. An LNG train is the term u sed to describe the liquefaction and purification facilities on an LNG plant. A standard LNG p lant train has a capacity of 4 millions ton per annum (International Gas Union, 2008). When multiply the typical LNG train size by the LNG heat value (approximately 30MJ/m3 - Wikipedia) and divided by the average LNG density (423kg/m3 - Wikipedia ) we get a value of 2.837108 MJ. According to the Table 6.7 the production of every MJ of LNG results in 2.15 grams of carbon dioxide emit to the atmosphere. This means that a typical LNG train can emit about 670 metric tons of equivalent carbon dioxide.


63

It has been presented that, however methane leakages are relatively small, there is a greenhouse gas emissions from LNG. According to data given by Tamura et al. it can be seen, that most part of GHG emissions comes from the liquefaction p lant. The conclusion can be that, however most part of boil-off gas is collected and recirculated, a significant increase in LNG trade, as expected by the EIA(2006), can result in larger emissions of GHG arises from the boil-off gas handling systems. Thus, some effort should be made to implement newer compressor technology, since they are a major part of all boil-off gas handling systems. And the main attention should be paid to reduce GHG emissions.


64

7 Small-scale LNG chain 7.1 Background

Small-scale LNG is a complement to the traditional large-scale LNG supply chains where LNG is transported over long distances to large and costly receiving terminals where it is turned into gas and fed into national pipeline systems. With the small-scale LNG concept, natural gas in the form of LNG can be supplied directly to end-users located outside the normal cover of pipeline systems. This will give these end-users the unique opportunity to switch to natural gas - an energy source with significantly lower emission levels of greenhouse gases. As a complement to the large-scale LNG chain, small-scale plants are plants that are installed near one of the major export lines and connected to these lines for continuous LNG production in a smaller scale. In other words, small-scale LNG is not a large system in terms of gas quantities.

Legend

Figure 7.1 Conceptual sketch of small-scale LNG chain. [12]


65

Typical small-scale LNG chain consists of small-scale production plant, where production capacity is between 20 and 200,000 tons/year, typical small-scale tanker, with capacity up to 10,000 cubic metres, roadtanker and a small-scale receiving terminal, as shown in Fig. 7.1. In small-scale LNG chain the LNG is distributed locally by tanker tru cks, in a range of about 300 km from the production facility, to various customers with a small to moderate need of energy or fuel. The tanker trucks are superinsulated to keep the gas liquefied at 162°C. A truckload is typically 50 cubic metres of LNG, or 30,000 standard cubic metres of gas. The small-scale receiving terminal is the location to which those trucks deliver. This small-scale receiving terminal provides gas for local users, mainly industrial, but it is also possible to deliver natural gas to smaller domestic users or as fuel for vehicles (mainly buses and heavy duty trucks). The main component of small-scale LNG receiving terminal is a vacuum insulated pressure vessel ranging in capacity from 2,000 to 60,000 litres (standard VT-LNG storage tanks) or in customized engineering tanks, going up to 680,000 litres gross volume. [12][29]

BOIL-OFF IN LARGE- AND SMALL-SCALE LNG CHAINS 7.2

66

Thermal analysis of boil-off of LNG in cryogenic tanks

A convenient procedure of thermal analysis of boil-off of LNG in small-scale LNG facility was made by Chen Q. S., Wegrzyn J., and Prasad V., in a paper entitled Analysis of temperature and pressure changes in liquefied natural gas (LNG) cryogenic tanks , published in Cryogenics 44 (2004). A thermal analysis of boil-off of LNG in L-CNG refuelling station, presented in this thesis work, is based mainly on this article.

Heat leak through shell of LNG storage tank A typical small-scale LNG storage vessel consists of a 9% nickel steel inner liner and carbon steel outer liner, using double wall construction with super insulation under high vacuum. For this kind of structure the thermal resistance of the shell o f tank can be estimated as [31] R

=

1 1 R m

+

1

,

(7.1)

R s

where, R m is the resistance of the multilayer superinsulation, Rm = Dh /(k m S ) [31], R s is the parasitic heat resistance of the support connecting the inner and outer shells of tank, R s

= Dh /( k s S s ) [31], S is the area of inner shell of tank, Ss is the area of support junction,

h is the thickness of multilayer superinsulation, k m is the average thermal conductivity of superinsulation, k s is the conductivity of stainless steel. For steady flow through the wall, the heat flow rate across the shell of LNG tank can be estimated as [31] q

=

bV æ k S k S ö æ k S + k saS ö , = DT × ç m + s s ÷ = DT × ç m ÷ = DT (k m + k sa ) Dh ø Dh R è Dh è Dh ø

DT

(7.2)

where, the ratio of the support junction area and total area a = S s / S , the area density of tank b = S / V (for a plain tube equal to b = 4 / D , where D is the diameter of the tube),V is the capacity of LNG tank, and DT = T ¥ - T is the temperature difference between the ambient and the LNG, where T ¥ is the ambient temperature.


67

From Eq. (7.2) the heat conductance of the tank shell can be estimated as [31] C = ( k m

+ k sa )

bV , Dh

(7.3)

If we assume that all heat which leaks into the tank warms the LNG, the boil-off rate o f LNG due to heat leak through the shell of LNG storage tank is estimated as [31] m1

=

q h g - hl

,

(7.4)

where hg and hl are the enthalpies of methane in gaseous and liquid states, respectively. From Eq. (7.4), the boil-off rate of LNG can be estimated as [31] r =

m1 V r

= DT × (k m + k sa )

b r × Dh × ( h g - hl )

,

(7.5)

where is the density of LNG. The enthalpy of liquid methane can be estimated as [32] T

hl

= ò c p dT ,

(7.6)

0

The heat capacity of liquid methane we can estimate using correlation based on a series expansion in temperature [33], c p

= A + BT + CT 2 + DT 3 ,

(7.7)

where, A=5149, B=-43.249, C=0.301449, and D=-4.49243*10 -4 The enthalpy of gaseous methane can be obtained as [33] h g

= hl + D H ,

(7.8)

where H is the heat of vaporization and it is based on the Watson correlation [32] n

é T - T ù D H = D H 1 ê c ú , T T ë c 1û

(7.9)

where, H1 is the heat of vaporization of methane at boiling point,

D H 1 = 0.5095 × 10 6 J / kg , Tc is the critical temperature of methane, Tc=190.55 K, T1 is the temperature of boiling point, T1=111.65 K, and n = 0.38 for 90.55K < T < 190.55K.


68

The thermal conductivity of superinsulation k m is generally estimated as 5 ·10-5 W/(m·K ) [31], conductivity of 1% chrome steel at 273K, k s as 43 W/(m·K) [31], the tank is filled with the LNG at -150 °C at the pressure 2.5bar. The enthalpy of liquid methane from Eq. 7.6 is estimated as hl = 4.707105 J/kg. The heat of vaporization, H according to Eq. 7.9 is estimated as 4.779105 J/kg, and the enthalpy of gaseous methane hg obtained from Eq. 7.8 is 9.485 105 J/kg. Fig. 7.2 shows the boil-off rate as a function of insulation thickness for 50 cubic metres tank, the area density of tank = 2 m-1, and the area of the cross-section of support strut of 0.001%, 0.002%, 0.005% and 0.01%. The boil-off rate were calculated using Eq. 7.5 The boil-off rate here means what percentage of fuel to be boiled off to keep the same temperature when heat is added into the fuel.

Figure 7.2 Boil-off rate as a function of thickness of superinsulation.

In the Fig. 7.2 you can see that the boil-off rate strongly depends on the area o f the crosssection of support strut, which links the outer and inner shells of the t ank. For example for junction area ration =0.005%, the boil-off rate for insulation of 0.03 m thickness is 1.2% per day. With a reduction in the area of strut cross-section, e.g., =0.002%, the boil-off rate is reduced to 0.45% per day for the insulation of the same thickness.


69

Fig. 7.3 shows the thermal conductance as a function of insulation thickness for 50 cubic metres tank, the area density of tank = 2 m-1, and the area of the cross-section of support strut of 0.001%, 0.002%, 0.005% and 0.01%. The thermal conductance was estimated using Eq. 7.3.

Figure 7.3 Thermal conductance as a function of thickness of insulation.

In the Fig. 7.3 it can be seen that, for junction area ratio =0.005%, the thermal conductance for 0.04 m thickness insulation is 5.5 W/K. With a reduction in the area of strut cross-section, e.g., =0.002%, the thermal conductance is reduced to 2.2 W/K. However, the junction area ratio has to be large enough for the strut to support the weight of the tank.

Heat release by boil-off When heat is added into the LNG, the vapour pressure inside the tank will increase. Venting of natural gas can be used to reduce the vapour pressure and thus the LNG temperature. We assume that the vapour is in the satu rated state, so that the relationship between the vapour pressure and temperature of LNG is known (Fig. 7.4).


70

Figure 7.4 The vapour pressure curve for methane ( Source: http://encyclopedia.airliquide.com)

If the initial mass of LNG is m 1, and temperature is reduced by T after venting a certain amount of LNG, m; the following equation is valid for small T [31] h g (T ) - hl (T )]× m = [hl (T ) - hl (T - DT )] × (m1

- m)

(7.10)

From the above equation, the boil-off is then [31] r = m / m1

= [hl (T ) - hl (T - DT )] [ / h g (T ) - hl (T - DT )]

The percentage of LNG to be boiled off in order to reduce vapour pressure is shown in Fig. 7.5.

(7.11)


71

Figure 7.5 Percentage of LNG to be boiled to reduce saturated vapour pressure.

For example to reduce the saturated vapour pressure from 20 bar to 2.5 bar, 32.25 % LNG is to be boiled. Similarly, to reduce the saturated vapour pressure from 20 to 10 bar, 17.95% LNG has to be boiled of, and from 10 to 2.5 bar, 17.36% LNG has to be boiled off. Evidently, the venting of boiled off gas can result in the loss of large amount of LNG. Certainly venting is not an efficient way to reduce the vapour pressure and has to be avoided


72

7.3 Dynamic process during storage and fueling

Storage process without fuelling buses In this work a cryogenic tank of 50 m3 is considered. The initial fill is 25 m3 with a saturated pressure 2.5 bar and the equilibrium boiling temperature of the LNG ~123.9 K. The thermal conductance of the LNG tank is estimated to be about 2 W/K (with latent heat of vaporization for LNG in these conditions it gives a heat leak rate, Q = 338.2W ). We desire to know how the saturated pressure in this refuelling tank changes with the time, without filling and venting operations. A good solution of this problem was proposed by J. A. Barclay, A. M. Rowe and M. A. Barclay in an article entitled Pressure build-up in LNG and LH 2 vehicular cryogenic storage tanks , published in Advances in Cryogenic Vol. 710 (2004). A consideration showed below is based on this article. The key to solving this problem without having to solve the comp lex changes in the vapour and liquid phases separately as a function of temperature and pressure is to realize that this is a closed system. Therefore, the average density in the tank remains constant as the pressure and temperature increase, due to the heat leak into the cryogen. Using the code, called AllProps [35], we can estimate the properties of the LNG at the initial pressure and temperature, such as: the density of the liquid phase,

r l = 403.85kg / m 3 , the density of the vapour phase, r v = 4.18kg / m 3 and the initial internal energy, ui = -863.62kJ / kg . Using these densities and the volume of the vapour and liquid phase in the tank the initial mass of the LNG in liquid and vapour phase can be estimated using Eqs. (7.12) and (7.13) [34]. ml m g

= V l × r l ,

= (V tan k - V l ) × r v

(7.12) (7.13)


73

Using Eqs. (7.12) and (7.13) the mass of the LNG in the vapour phase is mv = 104.5kg and the mass of the LNG in the liquid phase is ml = 1.01 ×10 4 kg . The quality of the LNG is given by the ratio of the mass of t he vapour to the mass of the liquid estimated by Eq. (7.14) [34], and it gives a value, X = 0.01 . X = mv / ml ,

(7.14)

Using the quality, the average density in the tank can be calculated using Eq. (7.15) [34]. -1

é1 - X X ù r av = ê + ú , r rv û ë l

(7.15)

Under the given conditions the average density in this tank is, r av = 202.98kg / m 3 . Now, assuming that we know the final pressure, set by p f = 2.6bar for example, and knowing the constant average density, using the code AllProps [35] we can estimate the final temperature, T f = 124.49 K and the final internal energy as u f = 861.49kJ / kg . The constant volume process means that the changes in internal energy between the final and the initial states times the total mass of the LNG in the tank Eq. (7.16) [34] divided by the rate of the heat influx will give the time it takes to reach the final pressure Eq. (7.17) [34].

DU = (ml + mv ) × (u f - ui ) , time =

DU Q

,

(7.16) (7.17)

Using above equations, the time to reach the pressure 2.6 bar is about 18 hours (~0.744 day). Above procedure is then repeated for successive values of the final pressure and the results are shown in Fig. 7.6.


74

Figure 7.6 Predicted saturated pressure for 50 m 3 tank with an initial fill of 25 m 3 LNG.

It is seen very well that the saturated pressure increases with time without filling and venting. With set of assumption used in this example the saturated p ressure increases about 0.15 bar each day. Boil-off rate with number of buses Loosing fuel by boil-off is one of the most important factors which have an affect on costeffectiveness of using LNG as a fuel for vehicles. Since the LNG as a cryogenic fluid has to be maintained at very low temperature it is not efficient to store it in the tanks for a long time, where it is jeopardized through the heat leakage. Longer time of storing LNG in the tank increases its temperature and causes a higher boil-off rate. Using a large tank for storing LNG, or fuelling only a few vehicles each day can lead to the situation describe above. LNG is kept in the tank for a long time, instead of being used, what causes a higher loss of fuel. It is expected then, that number of vehicles fuelled each day can have a significant effect on fuel consumption. Figure 7.7 shows the average fuel consumption for ten cities where natural gas is used as a fuel for city buses. Number of buses varying from 4 (Trondheim, Norway) to 136 (Colmar, France). It can be seen that


75

fuel consumption of buses in Trondheim is surprisingly high, while in the Malmö where is 125 CNG buses the average fuel consumption is the lowest.

Figure 7.7 Average fuel consumption (Source: Fryczka, D., Natural Gas use for on road transport, Diploma thesis, June 2004)

The effect of number of buses fuelled each day on fuel loss rate is analyzed by considering an LNG tank of 50 cubic metres and thermal conductance varying from 1 to 5 W/K. It is assumed that the pressure in the tank is 2.5 bar and the equilibrium boiling temperature of the LNG is 123.9 K, and this conditions is maintained constant during the t est time. The boil-off rate for each conductance can be estimated b y the Eq. (7.18). BOR =

C × (T ¥

- T ) , D H × r l × V

(7.18)

Where T is the ambient temperature (assumed as 293 K), T is the equilibrium boiling 

temperature of the LNG, l is the density of the liquid phase of the LNG ( r l = 403.85kg / m 3 estimated by using AllProps [35]), V is the tanks volume and H is the latent heat of evaporation for the LNG (in calculations I will use methane heat of evaporation as the main component of the LNG). The latent heat o f evaporation at boiling point is H1 = 0.5095 ×106 J/kg. To estimate the value for condition used in this example I will use the Watson correlation [32].


76

n

é T - T ù D H = D H 1 ê c ú , T T ë c 1û

(7.19)

Using Eq. (7.19), and knowing the critical temperature of methane Tc=190.55, the temperature of boiling point T1=111.65 K and n = 0.38 for 90.55K < T < 190.55K, H = 0.4779×106 J/kg. Knowing the heat of evaporation and using the Eq. (7.18), the boil-off rates for the tanks of 1, 2 and 5 W/K conductance, are 0.15%, 0.3% and 0.76% respectively. The effect of number of buses fuelled each day on the fuel loss rate is shown by the total fuel loss from the tank, when the number of buses fuelled each day varying from 1 to 40. Only the one total volume for each case is considered, and the total fuel loss is estimated as the amount of boil-off gas generated during the time of emptying tank, divided by the total tank s capacity. The fuel loss with number of buses is shown in Fig. 7.8.

Figure 7.8 Total fuel loss with number of buses.

For thermal conductance of 2 W/K, the total fuel loss is about 7% of the total filled fuel, when fuelling four buses every day. The fuel loss is reduced to less than 3% when fuelling more than ten buses every day, and it can be reduced to less than 1%, when fuelling more than 31 buses each day. For 40 buses and for the tank of the same thermal conductance the


77

total fuel loss is about 0.75% of the total filled fuel. It is evident that increasing number of buses fuelled each day can reduce the fuel loss, as a percentage of total fuel delivered. It is important also to reduce the thermal conductance of the shell of tank and the thermal conductance is related to the steel strut support between shells o f tank. Fig. 7.9 shows the ratio of the daily boil-off rate to the average daily consumption of the LNG, used for fuelling buses (number of buses varying from 1 to 40). The bo il-off rates for the tanks of 1, 2 and 5 W/K conductance, considered in this example, are 0.15%, 0.3% and 0.76% respectively.

Figure 7.9 Boil-off rate as a percentage of daily consumption of the LNG for the LNG tank.

It is evident and easy to forecast that increasing number of buses fuelled each day, causes that daily boil-off rate becomes less important. As shown in Fig. 7.8 the boil-off rate is an important part of the LNG consumed each day, when number of buses is less t han five. For example for the tank of 2 W/K conductance the boil-off rate is more than 15% of daily consumption of the LNG, when fuelling two buses every day. For the same tank the percentage of the boil-off decreases to 3%, when fuelling ten buses every day. The boil-off rate can be neglected, when fuelling more than twenty buses every day using an LNG cryogenic tank with C = 2 W/K.


78

8 Use of boil-off gas 8.1 Use of BOG at ships

Even the cargo tanks are well insulated some quantities of boil off gas are produced due to heat inleak. Typical values are about 0.1 to 0.15% of the full contents per day, which over a 20 day voyage, becomes a significant amount. Until now ships have employed gas compression and use the boil-off gas as fuel for the propulsion systems. LNG carriers have been equipped with steam turbines powered by heavy fuel oil (HFO) and/or LNG BOG. The high consumption of the steam turbine as compared to last-generation diesel engines in addition to environmental concerns and future regulation will eventually motivate their replacement. Instead of the common application of using the boil-off gas as fuel, the LNG BOG re-liquefaction system provides a solution to liquefy the boil-off gas back to the cargo tanks. The LNG re-liquefaction system has merit in the large savings in total fuel consumption and improved propulsion redundancy. To illustrate how the on board re-liquefaction system for LNG ships looks like I will describe the concept developed by Tractebel Gas Engineering (TGE). The TGE process concept for the re-liquefaction of boil-off gas is based on the classical Brayton Cycle. BOG is withdrawn from the cargo tanks and compressed to an intermediate pressure of about 3 6 bar a. It is then liquefied in a main process exchanger (BOG Liquefier). Liquefied BOG is flashed down to tank pressure in a separate valve and sparged into each of the cargo tanks on the ship. The process is designed to achieve 100 % liquid BOG at tank pressure. The cooling and liquefaction of the BOG is done in exchange with cold, gaseous nitrogen. [37] The main heat exchanger assembly is an aluminium plate fin t ype exchanger which has 3 streams. The BOG is cooled in one of the streams whilst HP nitrogen is cooled in the second stream. The third stream is the cold, low pressure nitrogen, which provides the refrigeration for the process. [37] Nitrogen is compressed in a three stage turbo compressor to a high pressure. It is cooled after each stage in a shell & tube heat exchanger to ambient temperature using seawater as


79

coolant. The pre-cooled high pressure nitrogen is then fed to the BOG liquefier and cooled down to approx. 80°C to -110 °C. Cold high pressure nitrogen is fed to an expander which is directly coupled to the third compressor stage to form a Compander . Outlet temperature of the low pressure nitrogen is approx. -170°C to -180°C. A simplified flowshame of boil-off reliquefaction process is shown in Fig. 8.1. [37]

Figure 8.1 Process flow-scheme of boil-off re-liquefaction unit.


80

8.2 Use of BOG at receiving terminals

The LNG gasification plant is mainly composed of LNG storage tanks, LNG pumps, LNG vaporizers, and the gas pipeline. During normal operation, boil-off gas (BOG) is produced in the tanks and liquid-filled lines by heat transfer from the surroundings. The quantity of vapour in the tank outlet increases significantly during ship unloading. These additional vapours are a combination of volume displaced in the tanks b y the incoming LNG, vapour resulting from the release of energy input by the ship pumps, flash vapour due to the pressure difference between the ship and the storage tanks, and vapour generated from heat leak through the unloading arms and transfer lines. These quantities of boil-off gas are collected using compressor systems and then they should be utilized. The usual order of priority for utilizing the boil-off gas from the discharge of the boil-off gas compressor is the following:

· Return to ship during unloading · Use as a fuel on-site · Recondense into LNG · Compress and place into the sales stream/pipeline · Flare (only in emergencies) Return to ship This is the first priority during ship unloading. When LNG is pumped out of t he ship there will be a tendency to create a vacuum. To offset this, and to maintain the cargo tanks at their operating pressure, natural gas is brought in, by the vapour return line, to replace the void created by the exiting LNG. Unlike the unloading line, the vapour return line is not maintained cold during periods between ship unloadings, so during the initial period of unloading the vapour returned to the jetty is too warm. Therefore, the vapour has to be cooled, in a desuperheater, before it enters the ship cargo tanks. Use as a fuel on-site When considering typical LNG gasification plant, there will be a significant fuel gas demand. The gas from the discharge of the boil-off compressor is less valuable than the high pressure gas from the vaporizer discharge. Therefore, every possible effort is made to


81

reduce the usage of the gas from the vaporizers discharge. The boil-off gas is a convenient source to meet the plant fuel needs. For example the boil-off gas can be used as the heat source for the vaporizer (SCV type vaporizers consume a significant quantities of fuel gas). If high pressure gas is used, its pressure needs to be reduced before it enters the fuel gas system. This pressure reduction can cause a substantial drop in temperature, and the gas may have to be heated before it enters the fuel gas system. [25] Recondense into LNG During normal operation, boil-off gas (BOG) is produced in the tanks and liquid-filled lines by heat transfer from the surroundings. This vapour is collected in the bo il-off header that ties into the boil-off compressor suction drum. Boil off vapours generated during normal operation (not unloading) by heat leak into the storage tank and piping are compressed and liquefied in a recondenser . [25] The basic principle of the recondenser s operation is very simple. The boil off gas is compressed to around 6 to 9 bar gage range and mixed with supercooled LNG. The supercooled LNG, meaning that it has the capacity to absorb natural gas and hold it as a liquid. The supercooled LNG arises when pumped in the first stage sendout pumps, the LNG attains greater pressure but the temperature rises only slightly. At operating pressure of the recondenser (6 to 9 bar gauge range) every kilogram of LNG, from the discharge of the first stage pumps, can absorb or recondense about 0.1 kilogram of boil-off gas from the discharge of the boil-off compressor. [25] Compress and place into sales pipeline Compressing large volumes of gas to high pressure is usually costly. Therefore, compress boil-off gas and place it into the sales stream/pipeline is used only if it is the only option. These situations arise usually where there is very low internal demand for t he boil-off gas, for example there is no sendout from the terminal, or the sendout is extremely low. Then the ability to recondense is drastically reduced and to avoid venting or flaring the boil-off gas a high pressure compressor might be necessary. [25] Flaring The flare system should be used only during the plant up sets or other unexpected circumstances. [25]


82

8.3 Use of BOG in small-scale LNG chain

It has already been described that the boil o ff gas (BOG) is produced as the LNG is received and stored even in small-scale. The boil-off gas, produced due to heat from ambient conditions and tank pumps, in addition to barometric p ressure changes, causes the pressure build-up inside the LNG tank. To reduce the storage tank pressure boil-off gas should be removed. Removed boil-off gas is stored then in a special made BOG tank. To protect environment from additionally greenhouse gas emissions and also to prevent fuel loss in LNG stations boil-off gas should be utilize. In plants using the LNG for fuel equipment for factories and city gas LNG plants, the supply pressure is only approximately 0.2 to 0.3MPa. Therefore, the BOG can be mixed in the supply gas without any problems. However, the application of the LCNG refuelling station, considered in this work, is intended only for refuelling to NGV. Therefore, it is difficult to process the low pressure gas, which has been evaporated once. Additionally, as the BOG is produced, the weathering problem must be investigated that the LNG component in the LNG tank is concentrated to heavy contents. It is thought that this problem may easily occur in the refuelling station where a large LNG tank is installed and only few vehicles are charged every day, just like it arises in Trondheim. [38] In small-scale LNG chain boil-off gas can be used as a fuel on-site, to power an electric generator or be re-liquefied. All of these ways of utilizing BOG can be successfully applied in Trondheim. BOG used as a fuel on-site The BOG of the BOG tank can be used as the heat source for the vaporizer. As for the process other than this method, a system is used that increases the pressure using the compressor and collects the gas to the gas storage unit. This compressor is intended to process the BOG and is not intended to increase the pressure at normal working level. Therefore, a compressor having a large capacity is not required. In this s ystem, a small engine compressor can be used. [38]


83

BOG to power an electric generator or be re-liquefied A typical storage LNG tank with electric generator or liquefier module is shown in Fig. 8.1. The LNG tank pressure should be below 175-200 psi (12-13.8 bar). LNG tank needs to be vented or vented gas be used when head pressure exceeds 150-175 psi (10.3-12 bar). A pressure-activated valve is used to keep the tank pressure below the set point, for example 80 psi (5.5 bar). When the tank pressure exceeds the set point, the three way pressureactivated valve routes ullage vapour instead of liquid to the engine. T his decreases the tank pressure the same way as venting. When the fuel tank pressure is below a set-point, liquid is drawn from the tank to the engine. [34]

Figure 8.2 LNG storage tank with module of electric generator or li quefier.


84

9 Discussion The strong price increases for oil and gas of recent years have led to a re-evaluation of the attractiveness of natural gas for power generation, the principal growth market for gas. Natural gas reserves are mainly concentrated in the Middle East and Former Soviet Union, accounting for over 71 percent of the global reserves at the end o f 2006. Unlike global natural gas reserves, the major consuming nations are located in Pacific Asia, North America and Europe. This imbalance in resources has created an opportunity for international trade in natural gas. Because of the distance between producers and consumers gas cannot practically or economically be transported in its gaseous state via pipeline. Thus, LNG provides a means of linking remote gas to markets. Moreover consumers in OECD Europe have an additional incentive to diversify sources of supply to LNG imports, driven by fears of over-reliance on gas supply from Russia. Continued expansion of demand has motivated an interest in expanding the role o f LNG import. The number of countries involved in the LNG trade has expanded significantly in recent years, accounting for 15 exporting countries and 18 importing countries, with even more countries in the process of developing infrastructure to either export or import LNG in the near future. This involves the large volumes of LNG, which need to be stored. LNG storage tanks account for a large portion, often up to a third or more, of the cost of a LNG terminal. Usually metal-lined concrete tanks are used for the primary containment of LNG. Due to the high costs and schedule implications of constructing traditional storage tanks, there is a great interest in finding new solutions for storing LNG. One of the innovations is all-concrete LNG tank (ACLNG). The ACLNG tank eliminates the need for a liner in the primary container and utilises a simple and cost-effective water vapour barrier on the secondary wall. Savings are achieved through a performance-related approach to design simplicity and speed of construction, avoiding the long lead time associated with proprietary liners, membranes or 9% Ni-steel, the cost of specialist sub-contractors. One of the disadvantages is that the perception of concrete is that it will crack and leak and this will cause extra quantity of LNG lost from the primary container. Some other solution is proposed by StatoilHydro. CryoTank is a concrete/concrete tank (C/C tank), where the structural strength comes from the concrete and the tightness from a completely sealed


85

metallic liner. The mount of steel used is substantially reduced compared with conventional LNG tanks. CryoTank tanks can be more than twice as large as conventional tanks, i.e. larger than 400,000 m3. This increased size can be achieved by minor increased diameter and increased height. One of the challenges in transporting and storing LNG is the generation of methane through the boil-off. Boil-off is caused by the heat added into the LNG during the storage and loading/unloading operations. In this work the sources of boil-off for typical largescale receiving terminal was presented and discussed. A special emphasis was put on the thermal analysis of an example LNG storage tank. In this study the heat transfer through the roof, wall and the bottom slab of the 200,000 cubic metres LNG tank, was considered. It was showed that the range from 0.07% to 0.095% of stored LNG is lost every day by boil-off, when assuming LNG (Snøhvit) and pure methane respectively. It has been showed also that the quantity of boil-off gas generated during the ship loading/unloading operations can be several times that generated during storing (holding mode). It has been shown that, there are probably some methane losses in LNG chains, due to leakages, venting or flaring, however they are hard to define. Not all companies physically measure venting/flaring. Often, from an operator s point of view there is no need to measure the vent/flare unless undertaking a study to see the economic losses resulting from venting/flaring, or if required to do so by national legislation and even then that information are not easy to get. It has been presented that even when assume that the main part of boil-off gas, generated by LNG chain, is recirculated some additional GHG emissions arise. A significant increase in LNG trade, as expected by the EIA(2006), can result in larger emissions of GHG arises from the boil-off gas handling systems. Thus, some effort should be made to implement newer compressor technology, since they are a major part of all boil-off gas handling systems. And the main attention should be paid to reduce GHG emissions. Generating methane by boil-off in small-scale is also a significant consideration. In general, the relative value of boil-off in small-scale facilities is larger than in large-scale facilities (relative value means here the boil-off as a fraction of stored volume). A thermal analysis of a typical small-scale 50 cubic metres LNG tank was carried out. The results


86

showed that the boil-off rate strongly depends on thickness of superinsulation and the area of the cross-section of support strut, which links the outer and inner shells of the tank. For example for junction area ration =0.005%, the boil-off rate for insulation of 0.03 m thickness is 1.2% per day. With a reduction in the area of strut cross-section, e.g., =0.002%, the boil-off rate is reduced to 0.45% per day for the insulation of the same thickness. Because of the smaller sizes of tanks in small-scale facilities than in large-scale facilities, an excessive pressure build-up in LNG tanks, caused by boiling-off some portion of LNG, is much more important. When considering a 50 cubic metres tank, which thermal conductance is estimated to be 2 W/K you can see that saturated pressure increases about 1.5 bar in ten days without filling and venting operations at about 25 cubic metres fill and 2.5 bar saturated pressure. This gives about 0.15 bar pressure build-up each day. Natural gas is being developed as a transportation fuel for heavy vehicles such as trucks and city buses. In Trondheim there are 4 CNG buses, but the problem is that the natural gas consumption of Trondheim s buses seems to be relatively high. The thing is that natural gas for Trondheim s buses is stored as an LNG form in cryogenic tank. Higher natural gas consumption of Trondheim s buses is caused probably by boil-off loses of stored LNG at refuelling stations. When only few buses are fuelled each day the pressure of boil-off gas may build up inside the LNG tank. To reduce the storage tank pressure, boil-off gas is removed, what causes a bigger loses of fuel (LNG). In this study it was calculated that for a 50 cubic metres LNG tank, which thermal conductance is estimated to be 2 W/K, the total fuel loss is about 7% of the total filled fuel, when fuelling four buses every day. The fuel loss decreases to less than 3% and less than 1%, when fuelling more than ten and more than thirty one buses every day. It is evident that the total fuel loss strongly depends on number of buses fuelled each day.


87

10 Conclusions Liquefied natural gas (LNG) will play an increasingly important role in the natu ral gas industry and global energy markets in the next several years. The co mbination of higher natural gas prices, lower LNG costs, rising gas import demand, and the desire of gas producers to monetize their gas reserves is setting the stage for increased global LNG trade. Boil-off generation during loading/unloading operations can be man y times that in the holding mode. Boil-off generation during ship unloading is a significant consideration while defining the parameters for the LNG tanks. However, the selection of LNG tank t ype and its related design basis has many ramifications, and boil-off gas is onl y one of them. The number of buses fuelled each day in an LCNG station has a large effect on the total loss of fuel. By increasing number of buses fuelled each day the total fuel loss can be greatly reduced. It is important also to reduce the thermal conductance of the shell of tank and the thermal conductance is related to the steel strut support between shells of tank. The total fuel loss for the tank, which thermal conductance is estimated to be 2 W/K, is about 7% of the total filled fuel, when fuelling four buses every day. The fuel loss is reduced less than 1% when fuelling more than thirty one buses every day. Boil-off gas is essentially gasified LNG at atmospheric pressure and it has substantial fuel value. Methane is about 21 times more greenhouse gas than carbon dioxide so it should not be vented or flared, except in emergencies. To eliminate the fuel loss, by boil-off, evaporated gas should be re-circulated. Boil-off gas can be disposed by re-liquefaction, use as a fuel on-site or compress and place into the sales stream/pipeline.


88

References [1] Chevron, Gorgon Project, What is LNG?, [Internet, read April 2008] [2] U.S. Department of Energy, Office of Fossil Energy, Liquefied Natural Gas: Understanding the basic facts , August 2005, [Internet, read April 2008]

[3] International Finance Corporation, World Bank Group, Environmental, Health, and Safety Guidelines: LNG LIQUEFIED NATURAL GAS FACILITIES , April 2007,

[Internet] [4] BP, BP Statistical Review of World Energy 2007 , London, UK, June 2007, p. 22. [Internet] [5] California Energy Commission, Liquefied Natural Gas Worldwide, http://www.energy.ca.gov/lng/international.html, [Internet, page updated 11/20/2007] [6] Energy Information Administration, U.S. Department of Energy, The Global Liquefied Natural Gas Market: Status & Outlook , Washington, USA, December 2003.

[7] Weems, P. R., Rogers, D. M., Atlantic Basin LNG sees rapid growth; Mideast capacity plays major role , LNG Observer April 01, 2007, volume 4, issue 2

[8] Energy Information Administration , Official Energy Statistics from the U.S. Government, Country Analysis Briefs, http://www.eia.doe.gov/cabs/ [Internet, read April 2008] [9] Petroleum Council Global Oil & Gas Study, Topic paper#13, Liquefied Natural Gas (LNG), made available July 18, 2007, www.npc.org, [Internet]

[10] Kunert, S., Larsen, Ø. B., Small is beautiful  Mini LNG concept , presented at Gastech 2008, International Conference, Bangkok, March 10-13. [11] Skjervheim, A., Erfarenheter av LNG från Norge, paper made for Gasdagarna i Båstad 17-18 October 2007 [12] Jarlsby, E., Lowering downstream entry barriers for natural gas: Small-scale LNG distribution in Norway , presented at IRAEE international conference Energy &

Security in the Changing World , Tehran, May 25-27, 2004 [13] Gasnor homepage: http://www.gasnor.no/1005/Side.aspx, [Internet, read April 2008] [14] CH IV International, Downeast LNG import terminal, Major equipment alternatives ·

study, Document: 04921-TS-000-106, July 2006.

[15] TOKYO GAS Co., LNG Technologies, Chapter 3 Receiving Terminals, http://www.tokyo-gas.co.jp/lngtech/chap_03/index.html [Internet, read April 2008]


89

[16] Powell, J., Thomas, G., Const ruction of All Concrete LNG Tanks, presented at Gastech 2008, International Conference, Bangkok, March 10-13 [17] Skovholt O., A new C/C LNG tank , presented at Gastech 2008, International Conference, Bangkok, March 10-13 [18] © 2000-2008 GlobalSecurity.org, site maintained by John Pike, http://www.globalsecurity.org/military/systems/ship/tanker-lng.htm [Internet, read April 2008] [19] Starosta, A., Safety of cargo handling and transport liquefied natural gas by sea. Dangerous properties of LNG and actual situation of LNG Fleet, Gdynia Maritime University, Gdynia, Poland. [20] Scope, Kawasaki Heavy Industries, Quarterly Newsletter, Technologies Behind LNG Carriers: Transferring LNG Safely at Ultralow Temperatures , No 69, pp 6-7 October

2006 [21] U.S. Patent No. 6,035,795, Ship with liquid tank , Issued on February 6, 2007, http://www.patentstorm.us/patents/7171916-fulltext.html, [Internet, read April 2008] [22] Ship & Offshore Engineering Dept., Shipbuilding & Offshore, IHI website, http://www.ihi.co.jp/offshore/spbinside_e.htm [Internet, last modified 12/27/00] [23] Coyle, D. A., Patel, V., Process and Pump Services in the LNG Industry, Proceedings in the twenty-second pump users symposium, Houston Texas, 2005 [24] The independent natural gas information site Copyright © Vivek Chandra., http://www.natgas.info/html/liquefiednaturalgaschain.html, [25] Tarakad, Ram R., LNG Receiving and Regasification Terminals, An Overview of Design, Operation and Project Development Considerations , Zeus Development

Corporation, Houston, Texas 2003. [26] Kitzel, B., Choosing the right insulation, PHPK Technologies , USA, reprinted from LNG INDUSTRY, spring 2008 [27] Bates, S., Morrison, D. S., Modeling the behavior of stratified liquid natural gas in storage tanks: a study of the rollover phenomenon, J. Heat and Mass Transfer, Vol.40

No. 8, pp. 1875-1885, 1997. [28] Se-Jin Jeon, Byeong-Moo Jin and Young-Jin Kim, Consistent thermal analysis procedure of LNG storage tank , Structural Engineering and Mechanics, Vol. 25, No. 4

(2007), pp. 445-466 [29] Chart Ferox Group a member of Chart Industries, Inc., http://www.chart ferox.com/systems/systems-lng-systems-satellite-plants.htm, [Internet, read April


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2008] [30] Tamura, I., Tanaka, T., Kagajo, T., Life Cycle CO2 analysis of LNG and city gas, Applied Energy 68 (2001) , pp.301-319. [31] Chen, Q. S., Wegrzyn, J., Prasad, V., Analysis of temperature and pressure changes in liquefied natural gas (LNG) cryogenic tanks , Cryogenics 44 (2004), pp. 701-709.

[32] Moran M. J., Shapiro Howard N., Fundamentals of engineering thermodynamics , third edition, John Wiley & Sons Ltd, 1998. [33] Yaws C. L., Physical properties, Chem Eng 1977. [34] J. A. Barclay, A. M. Rowe and M. A. Barclay, Pressure build-up in LNG and LH 2 vehicular cryogenic storage tanks , Advances in Cryogenic (2004), Vol.710, pp. 41-47.

[35] AllProps code has been made available by the Thermophysical Science Group at the University of Idaho, (www.uidaho.edu) [36] White, FM., Heat transfer , Addison-Wesley Publishing Company, 1984 [37] Gerdsmeyer, K-D., Isalski, W. H., On-board reliquefaction for LNG ships , TGE Gas Engineering (read April 2008). [38] Yonezawa, M., Development of L-CNG Refuelling System, Chiyoadkikai Works Co., Ltd


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Appendix A. Composition of Natural Gas and LNG Natural gas is composed primarily of methane but also contains ethane, propane and heavier hydrocarbons. Small amounts of impurities, including carbon dio xide (CO2), hydrogen sulphide (H2S), nitrogen (N2) and water (H2O) may also be found in natural gas. Because these impurities can detract from the heating value and properties of natural gas, they are often removed during the refining process and used as co mmercial by-products. The Table A.1 provides a typical natural gas composition. Natural gas is an odourless gas that is classified according to its composition. Dry gas has very high methane content, while wet gas contains considerable amounts of hydrocarbons of higher molecular weight known as alkanes, which include ethane, propane, and butane. Residue gas is the gas remaining (mostly methane) after the alkanes have been extracted from wet gas. Sour gas contains high concentrations of hydrogen sulphide (a colourless, poisonous gas with the odour of rotten eggs). The Table A.1 provides examples of natural gas compositions. Table A.1 Examples of Gas compositions

Troll (1)

Sleipner Field(2)

Draugen (3)

Methane

93,070

83,465

44,659

Ethane

3,720

8,653

13,640

Propane

0,582

3,004

22,825

i-Butane

0,346

0,250

4,875

n-Butane

0,083

0,327

9,466

C5++

0,203

0,105

3,078

Nitrogen

1,657

0,745

0,738

Carbon Dioxide

0,319

3,429

3,429

100

100

100

Molar content %

Total

Source: Fryczka, D., Natural Gas use for on road transport, Diploma thesis, June 2004 (1) After processing at Kollsnes (on-shore processing plant), average fo r Nov. 2000.


92

(2) After off-shore processing into off-shore pipelines, combination of Sleipner East and West, average Nov. 2000. (3) After off-shore processing into pipeline Åsgard Transport to Kårstø (on .shore processing plant) for further processing, average for Dec. 2000. The liquefaction process requires the removal the some of the non-methane components such as water and carbon dioxide from the produced natural gas to p revent them from forming solids when the gas is cooled to about LNG temperature (-162 C). As a result, LNG is typically made up of methane. The Table A.2 provides examples of Liquefied Natural Gas compositions. Table A.2 Examples of LNG compositions Properties at bubble point at normal pressure

LNG

LNG

Example 1 Example 2

LNG Example 3

Molar content % Nitrogen

0,5

1,79

0,36

Methane

97,5

93,9

87,20

Ethane

1,8

3,26

8,61

Propane

0,2

0,69

2,74

i-Butane

-

0,12

0,42

n-Butane

-

0,15

0,65

C5++

-

0,09

0,02

Molecular weight (kg/kmol)

16,41

17,07

18,52

Bubble point temperature ( C)

-162,6

-165,3

-161,3

431,6

448,8

468,7

590

590

568

1,367

1,314

1,211

3

Density (kg/m ) Volume of gas measured at 0 C and 101325 Pa/Volume of liquid (m3/m3) Volume of gas measured at 0 C and 3

3

101325 Pa/Mass of liquid (m /10 kg)

Source: Bengt Olav Neeraas, Statoil ASA, September 2007


93

Appendix B. Major trade movements  Natural Gas and LNG (2006)


Appendix C. Major trade movements  LNG (2006)

94


94

Appendix C. Major trade movements  LNG (2006)

BOIL-OFF IN LARGE- AND SMALL-SCALE LNG CHAINS Appendix D. Maps of LNG facilities worldwide

Caribbean, South & Central America Approximate location, Calypso LNG, Grand Bahama Island

Ocean Cay Island, Northern Bahamas Approximate location, Northwest region

Approximate location, Southeast region Peñuelas LNG, Bahia de Guazanilla

Puerto Corts Andres LNG-AES Sparrow Piont LNG Port Esquivel Mariscal Sucre LNG-Venezuela LNG-CIGMA LNG

La Unión

Atlantic LNG +expansion, Port Fortin El José, State of Anzoategui

Tazrona Basin, Caribbean Coast Approximate location,

95

BOIL-OFF IN LARGE- AND SMALL-SCALE LNG CHAINS Appendix D. Maps of LNG facilities worldwide

Caribbean, South & Central America Approximate location, Calypso LNG, Grand Bahama Island Approximate location, Southeast region

Ocean Cay Island, Northern Bahamas

Peñuelas LNG, Bahia de Guazanilla

Approximate location, Northwest region

Puerto Corts Andres LNG-AES Sparrow Piont LNG Port Esquivel Mariscal Sucre LNG-Venezuela LNG-CIGMA LNG

Atlantic LNG +expansion, Port Fortin

La Unión

El José, State of Anzoategui Tazrona Basin, Caribbean Coast Approximate location, Northeast region (Petrobras) Approximate location, Northeast region (Shell, Petrobras) Port of Pecém

Saupe Power Plant, GNL do Nordeste

Camisea LNG/Peru LNG, Pampa Malchorita

Pacific LNG

Bahia de Mejillones LNG, Mejillones LNG

Baia de Guanabara, Rio de Janeiro

Quintero LNG

Approxiamte location, San José

Bahia Blanca

Source: http://www.energy.ca.gov/lng/worldwide/africa.html, © 1994-2008 CALIFORNIA ENERGY COMMISSION

95


96

Asia Pacific Countries - Map A

Source: http://www.energy.ca.gov/lng/worldwide/asia_pacific.html, © 1994-2008 CALIFORNIA ENERGY COMMISSION


Asia Pacific Countries - Map B

97


97

Asia Pacific Countries - Map B

Source: http://www.energy.ca.gov/lng/worldwide/asia_pacific.html, © 1994-2008 CALIFORNIA ENERGY COMMISSION


Africa

98


98

Africa

Source: http://www.energy.ca.gov/lng/worldwide/africa.html, © 1994-2008 CALIFORNIA ENERGY COMMISSION


Western Europe

Map A

99


Western Europe

99

Map A

Source: http://www.energy.ca.gov/lng/worldwide/western_europe.html, © 1994-2008 CALIFORNIA ENERGY COMMISSION


Western Europe

Map B

100


Western Europe

100

Map B

Source: http://www.energy.ca.gov/lng/worldwide/western_europe.html, © 1994-2008 CALIFORNIA ENERGY COMMISSION


Mexico

Energia Costa Azul + expansion 14 miles north of Ensenada, Baja California

Terminal GNL de Sonora/Sonora Pacific LNG, Sonora

Dorado Hiload LNG Regasificatio n Terminal+ 35 nautical miles offshore in Gulf o f Mexico, Tamaulipas

Topolobampo, Sinaloa Terminal de LNG de Altamira, Tamaulipas

Approximate o l cation, Port of Manyanillo, Colima

Puerto Layaro, Láyaro Cárdenas, Michoacán

101


101

Mexico

Energia Costa Azul + expansion 14 miles north of Ensenada, Baja California

Terminal GNL de Sonora/Sonora Pacific LNG, Sonora

Dorado Hiload LNG Regasificatio n Terminal+ 35 nautical miles offshore in Gulf o f Mexico, Tamaulipas

Topolobampo, Sinaloa Terminal de LNG de Altamira, Tamaulipas

Approximate o l cation, Port of Manyanillo, Colima

Puerto Layaro, Láyaro Cárdenas, Michoacán

Salina Cruy, Oaxaca

Source: http://www.energy.ca.gov/lng/worldwide/mexico.html, © 1994-2008 CALIFORNIA ENERGY COMMISSION


Middle East Countries

102


102

Middle East Countries

Source: http://www.energy.ca.gov/lng/worldwide/middle_east.html, © 1994-2008 CALIFORNIA ENERGY COMMISSION


Northeastern Europe

103


103

Northeastern Europe

Source: http://www.energy.ca.gov/lng/worldwide/northeastern_europe.html, © 1994-2008 CALIFORNIA ENERGY COMMISSION


Southwest Pacific Rim Countries

104


104

Southwest Pacific Rim Countries

Source: http://www.energy.ca.gov/lng/worldwide/southwest_pacific_rim.html, © 1994-2008 CALIFORNIA ENERGY COMMISSION


United States of America West Coast

Map A

105


United States of America West Coast

105

Map A

Source: http://www.energy.ca.gov/lng/worldwide/united_states.html, © 1994-2008 CALIFORNIA ENERGY COMMISSION


United States of America Gulf Coast

Map B

106


United States of America Gulf Coast

106

Map B



United States of America East Coast

Map C

107


United States of America East Coast

107

Map C



Canada

108


108

Canada

Source: http://www.energy.ca.gov/lng/worldwide/canada.html, © 1994-2008 CALIFORNIA ENERGY COMMISSION


109

Appendix E. Conversion tables Table A.3 Frequently used conversions To

Billion Cubic

Billion Cubic

Million Tons of

Trillion

Metres of NG

Feet of NG

LNG

Btu

From Billion Cubic Metres of NG

Multiply by

1

35.315

0.760

38.847

Billion Cubic Feet of NG

0.028

1

0.022

1.100

Million Tons of LNG

1.136

46.467

1

51.114

Trillion Btu

0.026

0.909

0.020

1

Source: DOE Office of Fossil Energy

Table A.4 Typical liquid-vapour conversions


109

Appendix E. Conversion tables Table A.3 Frequently used conversions To

Billion Cubic

Billion Cubic

Million Tons of

Trillion

Metres of NG

Feet of NG

LNG

Btu

From

Multiply by

Billion Cubic Metres of NG

1

35.315

0.760

38.847

Billion Cubic Feet of NG

0.028

1

0.022

1.100

Million Tons of LNG

1.136

46.467

1

51.114

Trillion Btu

0.026

0.909

0.020

1


Table A.4 Typical liquid-vapour conversions To From

Liquid Measures Metric Ton

Cubic Metre

Cubic Foot

LNG

LNG

LNG

Vapour Measures

Heat Measure

Cubic Metre Cubic Foot

Btu

NG

NG

Multiply by 1 Metric Ton LNG

1

2.193

77.445

1.316

46.467

51,113,806

1 Cubic Metre LNG

0.456

1

35.315

600.00

21.189

23,307,900

1 Cubic Foot LNG

0.0129

0.0283

1

16.990

600.00

660,000

1 Cubic Metre NG

0.000760

0.001667

0.058858

1

35.315

38,847

1 Cubic Foot NG

0.000022

0.000047

0.001667

0.02832

1

1,100



110

Appendix F. Methane density at liquid and gaseous states Table A.5 Methane pressure and density at liquid and gaseous states Pressure

Temperature

Liquid density

Vapour density

bar

psi

C

K

F

kg/m3

lb/gal

kg/m3

1 1,1 1,2 1,3 1,4 1,5 1,6 1,7 1,8 1,9 2 2,1 2,2 2,3 2,4 2,5 2,6 2,7 2,8 2,9 3 3,1 3,2 3,3 3,4 3,5 3,6 3,7 3,8 3,9 4 4,1 4,2 4,3 4,4 4,5 4,6 4,7 4,8 4,9 5 5,1 5,2 5,3 5,4 5,5 5,6 5,7

14,50 15,95 17,40 18,85 20,30 21,75 23,21 24,66 26,11 27,56 29,01 30,46 31,91 33,36 34,81 36,26 37,71 39,16 40,61 42,06 43,51 44,96 46,41 47,86 49,31 50,76 52,21 53,66 55,11 56,56 58,01 59,46 60,91 62,36 63,81 65,26 66,72 68,17 69,62 71,07 72,52 73,97 75,42 76,87 78,32 79,77 81,22 82,67

-161,64 -160,48 -159,39 -158,37 -157,41 -156,49 -155,63 -154,8 -154,01 -153,26 -152,53 -151,83 -151,15 -150,5 -149,87 -149,25 -148,66 -148,08 -147,52 -146,97 -146,44 -145,92 -145,41 -144,91 -144,42 -143,95 -143,48 -143,03 -142,58 -142,14 -141,71 -141,29 -140,88 -140,47 -140,07 -139,68 -139,29 -138,91 -138,53 -138,16 -137,8 -137,44 -137,09 -136,74 -136,39 -136,05 -135,72 -135,39

111,51 112,67 113,76 114,78 115,74 116,66 117,52 118,35 119,14 119,89 120,62 121,32 122 122,65 123,28 123,9 124,49 125,07 125,63 126,18 126,71 127,23 127,74 128,24 128,73 129,2 129,67 130,12 130,57 131,01 131,44 131,86 132,27 132,68 133,08 133,47 133,86 134,24 134,62 134,99 135,35 135,71 136,06 136,41 136,76 137,1 137,43 137,76

-258,95 -256,86 -254,90 -253,07 -251,34 -249,68 -248,13 -246,64 -245,22 -243,87 -242,55 -241,29 -240,07 -238,90 -237,77 -236,65 -235,59 -234,54 -233,54 -232,55 -231,59 -230,66 -229,74 -228,84 -227,96 -227,11 -226,26 -225,45 -224,64 -223,85 -223,08 -222,32 -221,58 -220,85 -220,13 -219,42 -218,72 -218,04 -217,35 -216,69 -216,04 -215,39 -214,76 -214,13 -213,50 -212,89 -212,30 -211,70

422,59 420,88 419,28 417,77 416,34 414,98 413,67 412,42 411,22 410,06 408,95 407,87 406,82 405,8 404,81 403,85 402,91 402 401,1 400,23 399,38 398,54 397,72 396,91 396,12 395,35 394,59 393,84 393,1 392,38 391,66 390,96 390,26 389,58 388,91 388,24 387,58 386,94 386,29 385,66 385,04 384,42 383,81 383,2 382,6 382,01 381,42 380,84

3,527 3,512 3,499 3,486 3,475 3,463 3,452 3,442 3,432 3,422 3,413 3,404 3,395 3,387 3,378 3,370 3,362 3,355 3,347 3,340 3,333 3,326 3,319 3,312 3,306 3,299 3,293 3,287 3,281 3,275 3,269 3,263 3,257 3,251 3,246 3,240 3,235 3,229 3,224 3,218 3,213 3,208 3,203 3,198 3,193 3,188 3,183 3,178

1,7946 1,9587 2,1216 2,2836 2,4446 2,6049 2,7644 2,9233 3,0816 3,2393 3,3966 3,5533 3,7097 3,8656 4,0212 4,1765 4,3314 4,4861 4,6405 4,7947 4,9486 5,1024 5,2559 5,4093 5,5625 5,7156 5,8686 6,0214 6,1741 6,3267 6,4792 6,6317 6,7841 6,9364 7,0887 7,2409 7,3931 7,5453 7,6974 7,8495 8,0016 8,1538 8,3059 8,458 8,6102 8,7623 8,9145 9,0668

Boil-Off in Large and Small Scale LNG Chains

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