Simulation and Design of a Boil-Off Gas Re-liquefaction System in a Small-Scale LNG Supply Chain Case Study of Trafaria Joana Alexandra Santos Antunes Thesis to obtain the Master of Science Degree in Energy Engineering and Management Supervisor: Prof. Viriato Sérgio de Almeida Semião Examination Committee Chairperson: Prof. Francisco Manuel da Silva Lemos Supervisor: Prof. Viriato Sérgio de Almeida Semião Member of the Committee: Prof. Pedro Jorge Martins Coelho June 2018
133
Embed
Simulation and Design of a Boil-Off Gas Re-liquefaction ... · Simulation and Design of a Boil-Off Gas Re-liquefaction System in a Small-Scale LNG Supply Chain Case Study of Trafaria
This document is posted to help you gain knowledge. Please leave a comment to let me know what you think about it! Share it to your friends and learn new things together.
Transcript
Simulation and Design of a Boil-Off Gas Re-liquefaction System
in a Small-Scale LNG Supply Chain
Case Study of Trafaria
Joana Alexandra Santos Antunes
Thesis to obtain the Master of Science Degree in
Energy Engineering and Management
Supervisor: Prof. Viriato Sérgio de Almeida Semião
Examination Committee
Chairperson: Prof. Francisco Manuel da Silva Lemos
Supervisor: Prof. Viriato Sérgio de Almeida Semião
Member of the Committee: Prof. Pedro Jorge Martins Coelho
June 2018
ii
Acknowledgments
To my parents, for their enormous and tireless help, and always being by my side.
To my Grandmother, example of resilience and strength.
To my Gabi, because you're part of me.
To my "Split", Ana, for never letting down and for fighting side by side with me.
To my dearest Emanuel, for the restless fight alongside with me, every day.
To the esteemed Professor Viriato Semião, for guiding me through this work and for his precious help and
tutoring.
To the most considered administration board of OZ Energia and all their personnel involved in this project,
in particular Dr. Micaela Silva.
To my dear cousin Amílcar, for his example of courage and support along the way, and for teaching me to
apply Aikido and shisei every day.
To my buddies at IST, Monica, and Maxime, who constantly reminded me of the importance of getting a
parachute.
iii
Abstract
Liquefied Natural Gas (LNG) supply chains have gained a relevant position in the energy market during the
last 20 years, and economic projections indicate it will continue to grow. The port of Lisbon offers
geographically worthy conditions to develop a local small-scale supply chain, and the present work
analyses the feasibility of the Trafaria fuels terminal to house a small-scale LNG (SSLNG) storage facility,
mainly dedicated to LNG ships bunkering. Thus, a preliminary study of the main characteristics of an
SSLNG terminal is made, including its BOG (Boil-off Gas) management system as a major concern within
the operation of an LNG terminal.
The location and dimensions of the chosen in-ground tank are selected, and heat input into the tank is
simulated through the definition of the dimensions and insulation of the tank, respecting the maximum
BOG rate defined, allowing also the calculation of energy use and possible operating costs.
As a method of managing the generated BOG, a re-liquefaction system based on a Nitrogen turbo-
expander cycle is studied. The system is simulated for two different configurations, allowing to determine
the most efficient one. Also, a cogeneration plant is considered as a potential solution to manage the
generated BOG; both solutions are simulated for different BOG rates, climate conditions and modes of
operation of the terminal. The cogeneration plant is found to be an interesting alternative to manage the
BOG together with a re-liquefaction system as backup, capable of processing all the BOG in the most
demanding operation scenario.
Keywords: Liquefied Natural Gas, Small-scale supply chain, Boil-off gas, BOG Re-Liquefaction, Single
Nitrogen Expansion.
iv
Resumo
As cadeias de abastecimento de Gás Natural Liquefeito (GNL) assumiram uma posição relevante no
mercado de energia nos últimos 20 anos, e as projecções económicas indicam que continuarão a seguir
esta tendência. Oferecendo o porto de Lisboa condições geográficas para desenvolver uma cadeia de
abastecimento de pequena dimensão, o presente trabalho analisa a viabilidade do terminal de
combustíveis da Trafaria albergar um terminal de GNL de pequena escala, principalmente dedicada ao
abastecimento de navios de GNL. Para este efeito, é realizado um estudo preliminar das principais
características de um terminal de GNL, incluindo o sistema de gestão de BOG (Boil-Off Gas) destacado
como questão de grande importância durante a sua operação.
A localização e dimensões do tanque enterrado são seleccionadas e a entrada de calor no tanque é
simulada após definição das dimensões e isolamento do tanque, respeitando a taxa BOG máxima definida,
permitindo o cálculo do uso de energia e possíveis custos operacionais.
Como método de gestão e recuperação de BOG é estudado um sistema de liquefacção baseado num ciclo
de turbo-expansão de Azoto. O sistema é simulado para duas configurações distintas, permitindo avaliar
qual a mais eficiente. Uma instalação de cogeração é também estudada como solução para gerir o BOG.
Ambas as soluções são simuladas para diferentes taxas de BOG, condições climáticas e modos de
operação. A instalação de cogeração constitui uma alternativa interessante e viável para gerir o BOG,
juntamente com um sistema de re-liquefação como backup, capaz de processar o BOG produzido.
Palavras-Chave: Gás Natural Liquefeito, Cadeia de abastecimento de pequena escala, Boil-off gas,
Reliquefacção de Boil-off gas, Expansão Simples de Azoto.
2. The Case-Study .................................................................................................................................. 17
2.1 Description of the Company .......................................................................................................... 18
2.2 The Terminal – Case Study ............................................................................................................ 19
2.2.1 Characteristics of the Terminal ........................................................................................ 19
2.3 Choosing the Storage Facilities ..................................................................................................... 21
3. Literature Review .............................................................................................................................. 28
Table 12 – LNG Tank Specifications. ............................................................................................................................. 56
Table 13 - BOG Scenarios and Results .......................................................................................................................... 70
Table 14 – Heat Ingress in the LNG System through Piping and Pumping System ....................................................... 72
Table 15 – BOG Scenarios and Results - Piping and Pumping System .......................................................................... 72
Table 16 – Heat Ingress in the LNG System during each Operation Mode .................................................................. 72
Table 17 - Tank Insulation Costs ................................................................................................................................... 72
Figure 2 - Primary Energy Consumption in 2005 ............................................................................................................ 2
Figure 3 - Primary Energy Consumption in 2014 ............................................................................................................ 2
Figure 4 - Established and under consideration Emissions Controlled Areas [16] ......................................................... 4
Figure 5 - Resulting Emissions of the Combustion of Natural Gas vs Emissions Resulting from the Combustion of
Figure 6 - Levelized Cost of Energy [32] ......................................................................................................................... 8
Figure 7 - LNG Value Chain ............................................................................................................................................. 9
Figure 8 – Illustrative comparison of NG transportation: LNG carrier vessel versus Pipeline Transport of NG [21] .... 10
Figure 9 - Major import and export regions [38] ......................................................................................................... 11
Figure 10 - Main marine international traffic routes [45] ............................................................................................ 13
Figure 11 - Number of ships, per type, which entered the Port of Lisbon between 2015 and 2016 [47]. ................... 14
Figure 12 - Full Gas Field Processes .............................................................................................................................. 17
Figure 14 - Flow on the river estuary [52]. ................................................................................................................... 20
Figure 15 - Map of Conditioning Factors: Trafaria Terminal and Surrounding Areas [55] ........................................... 22
Figure 16 - General view of Trafaria Terminal with the three possible places to install the reservoirs (identified in
Figure 17 - First place considered – alongside the gasoline reservoirs (A in Figure 16) ............................................... 24
Figure 18 - Second place considered – where reservoirs T1 to T9 and T18 are placed (B in Figure 16)....................... 24
Figure 19 - Third location considered - Unbuilt terrain (C in Figure 16) ....................................................................... 25
viii
Figure 20 - Calculated distance from the Jetty to Location C (273.9 metres). ............................................................. 26
Figure 21 – Final location of the LNG reservoir. ........................................................................................................... 27
Figure 23 – Double Containment LNG Storage Tanks in Sines, Portugal [161]............................................................. 30
Figure 24 - Single Containment Storage Tank .............................................................................................................. 31
Figure 25 - Double Containment Storage Tank ............................................................................................................ 31
Figure 26 - Full Containment Storage Tank .................................................................................................................. 31
Figure 27 - In-ground Membrane Storage Tank ........................................................................................................... 31
Figure 28 - Process Flow of BOG Handling System [87] ............................................................................................... 37
Figure 29 - Working principle of a refrigeration / liquefaction system ........................................................................ 39
Figure 30 - Basic BOG Liquefaction .............................................................................................................................. 40
Figure 32 - Cascade Cycle with Pure Refrigerants [95] ................................................................................................. 43
Figure 33 - Example of Coldbox [97] ............................................................................................................................ 43
Figure 34 – Pure refrigerants commonly used to produce LNG - Vapour Pressure Curves [95] .................................. 44
Figure 40 - Ambient Temperature during the typical days of each season- Reference Period .................................... 54
Figure 41 – Solar Radiation during the typical days of each season - Reference Period .............................................. 54
Figure 42 - Soil Temperature - Reference Period ......................................................................................................... 54
Figure 43 - Tank Project Scheme with Main Dimensions and Levels ........................................................................... 57
Figure 44 - Bottom of the tank – Composition (layers) ................................................................................................ 58
Figure 45 – Walls of the tank – Constitution (layers) ................................................................................................... 58
Figure 46 - Dome (Roof) of the tank – Constitution (layers) ........................................................................................ 59
Figure 47 - Daily percentage of BOG for different tank capacities and LNG methane content [122]. ......................... 60
Figure 48 – Linear Fitting of Ordinate Interception Values. ......................................................................................... 60
Figure 49 - Equivalent Heat Transfer Diagram – Dome ................................................................................................ 63
Figure 50 - Scheme of the Temperatures considered for the Heat Ingress Calculation in the Dome .......................... 63
Figure 51 - Single Expander Nitrogen Cycle ................................................................................................................. 67
Figure 58 - BOG Volume - BOG=0.039% ....................................................................................................................... 71
Figure 59 - BOG Volume - BOG=0.050% ....................................................................................................................... 71
Figure 60 - BOG Volume - BOG=0.067% ....................................................................................................................... 71
Figure 61 – Liquefaction Cycles A (in blue) and B (in orange) ...................................................................................... 74
Figure 62 - Evolution of the Flow Rate of Refrigerant Required Vs BOG inlet Temperature ....................................... 75
Figure 63 – Specific Consumption and Cost per Ton of BOG Processed ...................................................................... 75
Figure 81 - Tank Project – Final Drawing .................................................................................................................... 102
Figure 82 - Insulation Example 1 [157] ....................................................................................................................... 103
Figure 83- Insulation Example 2 [157] ........................................................................................................................ 103
Figure 84 - Insulation Example 3 [157] ....................................................................................................................... 104
Figure 85 - Insulation Example 4 [158] ....................................................................................................................... 104
Figure 86 - Insulation Example 5 [158] ....................................................................................................................... 105
Figure 87 - Insulation Example 6 [140] ....................................................................................................................... 105
Figure 90 - Liquefaction Cycles A and B [159] ............................................................................................................ 108
of fuel, poisonous, colour and odourless; sulphur dioxide (SO2), enhancer of acid rains; and nitrogen oxides (NOX),
an indirect greenhouse gas.
Table 3 - Comparison of Fuel Emissions (Parts per billion of energy input)
Pollutant LNG Oil Coal
Carbon dioxide 117 000 164 000 208 000
Carbon monoxide 40 33 208
Nitrogen oxides 92 448 457
Sulphur dioxide 1 1112 2591
Particulate Matter 7 84 2774
Mercury 0.000 0.007 0.016
As it is possible to observe from Table 3, LNG appears as a breakthrough on the combat to particulate
emission, as it is evident a reduction of near 99%, and a great mitigator of SO2, that is reduced nearly 100%, and
NOX, that suffers a reduction of about 80% when compared with oil and coal [12].
When burned for power generation, SO2 emissions are practically extinguished and a significant reduction
of CO2 is obtained [35]. Hence, the increased use of LNG instead of other fossil fuels can potentiate significantly
the emission reduction of GHG to the atmosphere [36].
Due to the clean nature of the combustion of natural gas, heavy-duty vehicles (e.g. ships and trucks)
powered by LNG can, with the present technology, achieve low emissions rates without excessive and expensive
emission control equipment. It is estimated by Arteconi et al. (2009) that LNG can afford a 10% reduction in GHG
emissions when compared with a diesel engine. As a complement, another comparison of LNG emissions was
previously performed, which is directly connected to these heavy-duty vehicles mentioned.
1.2.3 Economics of LNG
The “Value Chain” concept was created in 1985 by Michael Porter as a competitive strategy to achieve
superior business performance [37]. This represents a combination of generic value-added activities operating
within a firm, activities that aim to cooperate in order to provide value to customers through a valuable product.
In order to better understand the LNG value chain, the process of an LNG chain should be analysed and
understood, so as to detect and evaluate what are the elements that add value to the chain – see Figure 7. To
perform this analysis, the whole process will be briefly described. A more detailed explanation is available on
Chapter 3.
Figure 7 - LNG Value Chain
10
The LNG production process starts with the exploration and production of the natural gas wells, being then
transported via pipeline to the liquefaction plant, where it is cooled to achieve -161⁰C at atmospheric pressure,
and becoming 1/600 of its original volume at gaseous state. The LNG is then loaded into tankers to be transported
by sea to the receiving countries, being then unloaded and stored as liquid or regasified to be fed into the
connecting pipelines to the natural gas grid of the accepting country.
With a brief analysis of this process, it is possible to conclude that LNG liquefaction creates the possibility
to transport a fuel with a much higher energy density per volume that it would be by pipeline in gaseous state,
which adds more value to this chain, since the same amount is transported in 1/600 of the volume, allowing
transport to and from more remote locations (where pipelines infrastructures were unfeasible), by ship or even
truck. This competence also weakens the probability of encounter geopolitical constraints, inherent to the use
of pipelines that cross countries with high instability, which may cause significant disturbance to the receiving
countries in case of war or other issues [38].
Even though pipelines deliveries continue to dominate, LNG plays an increasing role for EU natural gas
supplies and, due to the lack of capacity of international pipelines, LNG appears as the sole possibility for new
competitors to enter the market of natural gas; this situation enables traditional importers to widen their gas
suppliers assortment, considering that some producing locations of natural gas are only accessible by sea [39].
This result also enhances supply safety, since it broadens the offer and does not limit the worldwide distribution
of natural gas mostly to terrorism-susceptible pipelines.
Due to technological innovation, LNG costs have decreased significantly over time to about half the price
that was charged in 1990, and a level was reached where LNG was able to compete for pipeline supplies, as it is
shown in Figure 8, and the transportation of natural gas as LNG on carrier vessels has become preferred to
pipeline for distances larger than 2000 km [40].
Figure 8 – Illustrative comparison of NG transportation: LNG carrier vessel versus Pipeline Transport of NG [21]
Regarding the 5 main steps of LNG value chain, investment costs vary significantly amongst these:
exploration and production account for 15-20% of the total costs of the value chain; liquefaction for 30 to 45%;
shipping for 10-30%; and regasification for 15-25%. As LNG projects are very capital intensive with most projects
costing several billion dollars [41], these costs may diverge expressively from one value chain to another, as
factors such as distance, traded volumes and local conditions (construction costs, port configuration and site
11
conditions) have a great influence on the costs associated [38].
One of the problems associated with the production and use of LNG and that has been a major constraint
consists on the fact the suppliers await for a bigger number of users (ships), while ship owners do not invest on
LNG-based propulsion due to the fact that there are no sufficient suppliers or distribution that satisfy their
immediate demand [13]. This problem is being overcome by the bet from energy investors on the LNG technology
as its importance on the energy markets is actually significant and it represents a tactic to compete against the
conventional pipeline supply.
The globalization of natural gas markets has been favouring safety of supply as well as introducing
competition between previously separated regions. While the transportation of natural gas in its liquefied form
by tanker has been used for more than 40 years, only recently the industry achieved a remarkable level of global
trade [41]. During the last two decades, large investments along all the stages of the value chain have been
realized: new players (countries and companies) have entered the industry and LNG technology began to support
the globalization of formerly regional markets. Changes in the framework from monopolistic structures to
competition) have had an impact on organizational behaviour of market participants, rising strategic partnerships
and engaging both oil and natural gas producers and distributors on all stages of the LNG value chain [38].
Nowadays, LNG is responsible for supplying the US, UK, Iberian Peninsula, and Japan, among others. The
Middle East accounts for more than 40% of worldwide proven natural gas reserves and it is predictable that will
become the largest regional exporter of LNG, alongside with Australia. Also, the outlook for LNG demand in Asia-
Pacific region is very strong, as India, China, Singapore, Vietnam and Thailand are emerging as new consumers,
as Figure 9 illustrates.
Figure 9 - Major import and export regions [38]
As for Europe, the imports account for 48% of the share, and it is expected that this figure will rise to 74%
12
in 2030. Hence, the worldwide growth in the demand of natural gas has led to a major investment on LNG
projects, and projections indicate that by 2030 the demand will rise to the triple of nowadays’, and no other fossil
fuel is foreseen to grow as fast as LNG [42].
1.2.4 LNG in Portugal
Portugal relied on natural gas mainly on power plants, to fulfil the electricity demand whenever RES
(Renewable Energy Sources, wind and hydropower) were not sufficient, with a share of natural gas accounting
for about 18% of the total energy mix, and an average load factor of the gas-fired power plants of about 26% in
2012. The country is dependent on imports for about 74% of its energy needs in 2014 and 100% of natural gas
requirements, having had a total consumption of natural gas of 45.3 TWh. Considering only natural gas, 61% of
its consumption was made by the energy sector, ahead of both the industrial sector with 25% of consumption
and the Retail and Consumer sector with about 10%. As for existing natural gas storages, under Decree Law
140/2006, it is mandatory that Portugal holds reserves capable of answering, at least, for the demand for 15 days
of non-interruptible consumption on gas-fired power plants and 20 days of non-interruptible consumption of
household costumers [6]. As so, two main reserves exist on the country: LNG storage in Sines of about 240,000
m3 in combined storage of two tanks, that was recently increased by another tank of 150,000 m3, totalling
390,000 m3 (maximum storage of energy between 2874 GWh); and a storage facility on five salt caverns on
Carriço of 333 million cubic metres (total storage of energy of 3963 GWh [43]), with two additional storage
caverns foreseen to be completed soon [44]. A more detailed map of the Portuguese gas infrastructure can be
found on Annex II.
In 2016, natural gas demand in Portugal was assured 2/3 by the pipeline connection coming from Spain on
the interconnections of Campo Maior and Valença, while the remaining 1/3 was delivered on the LNG terminal
in Sines (gas original from Nigeria). The total consumption in 2016 totalized 55.8 TWh, registering a growth of
6.9% when compared with the previous year [43]. The LNG terminal received, in 2016, 26 ships (22 unloads, 3
loads and one cooling operation) and supplied 4629 tanker trucks. As for the underground storage, 45% more
natural gas was moved in, when comparing with 2015.
1.2.5 Portugal, Lisbon, as a strategic location for an LNG terminal
Taking into account the scenario for the power generation mix in Portugal up to 2030, it is expected that
the role of natural gas on power generation becomes progressively eroded by the rise of renewables and the
forthcoming low-carbon energy transition, assuming that there will be no significant ascents on power demand
[5]. Nevertheless, it is wise to observe Portugal potential to commercialize and distribute natural gas in its
liquefied form to and from the ships that travel across Portuguese waters, as about 75 000 ships pass offshore
Lisbon annually and most of them heading to or coming from ECA and SECA zones, as it is illustrated in figure 10,
where it is also possible to observe the great affluence of marine traffic existent on the Portuguese maritime
area.
13
Figure 10 - Main marine international traffic routes [45]
Knowing the crescent regulatory constraints that influence ship owners, and that these owners search for
cleaner fuels to head to northern Europe, an LNG terminal capable of supplying these vessels might be a great
contribution for the local and national economy as increasingly more ships would be expected to enter the Port
of Lisbon and use its facilities.
A terminal located in the south bank of river Tagus firth, where an important connecting link is made
between cargo coming from Spain, Northern Europe and the Americas [46], represents a promising affluence to
an LNG terminal to be built on this zone, as it is possible to see in Table 4 from the statistical data from The Port
of Lisbon, stating that about 200 ships enter the Port monthly.
Table 4 - General vessel traffic entering the Port of Lisbon in 2015 and 2016 [47] – GT: Gross Tonnage.
Traffic Monthly average January to December
2015 2016 2015 2016 Variation
Ships Entered (number)
217 192 2606 2300 11,7%
National (number)
33 37 396 441 11,4
Foreign (number)
184 155 2 210 1 859 -15,9
Total Capacity (GT)
4 153 574 3 757 375 49 842 885 45 088 498 9,5%
National (GT)
238 035 279 179 2 856 423 3 350 152 17,3
Foreign (GT)
3 915 539 3 478 196 46 986 462 41 738 346 -11,2%
Total Freight (Tons)
965 185 854 718 11 582 223 10 256 612 -11,4%
Assuming that around 205 ships pass daily offshore Lisbon (almost the same number of ships that enter the
Port monthly) [48], it is expected that the presence of an LNG terminal will make this number to increase; also
because the majority of the ships entering the Port are cargo vessels (see Figure 11), these are the potential users
of LNG as the motive fuel used, and the most probable visitors of Ports inside ECA/SECA zones.
14
Figure 11 - Number of ships, per type, which entered the Port of Lisbon between 2015 and 2016 [47].
In order to have a typical and normalized journey to consider along this document, a reference voyage for
a full tank of an LNG-powered cargo ship was considered (approximately 2000 km), and is well represented by
the trip Lisbon > Funchal > Lisbon. As so, and considering the reference travelled distance, it was possible to
estimate the distance between Lisbon and the other existing LNG storing ports where the vessels can refuel again
after the reference distance was travelled.
Table 5 - Travelling Distance from Lisbon to the main European ports and e Algeria
Departure Arrival Distance
(approximate) Country Port
LISBOA
Portugal (Madeira) Funchal 1000 km (540 Nm)
United Kingdom Southampton 1604 km (866 Nm)
Isle of Grain 1869 km (1009 Nm)
Belgium Zeebrugge 1889 km (1020 Nm)
Netherlands Rotterdam 2011 km (1086 Nm)
Algeria Arzew 1030 km (556 Nm)
Skikda 1670 km (900 Nm)
Spain
Barcelona 1508 km (814 Nm)
Cartagena 993 km (536 Nm)
Bilbao 1085 km (586 Nm)
France Montoir de Bretagne 1260 km (680 Nm)
Fos-Tonkin 1830 km (988 Nm)
It is clear from Table 5 that a ship coming to refuel LNG in Lisbon can reach the great majority of the
important LNG terminals in Europe and also Algeria, making Lisbon a strategic location for a mid-way refuelling
site between travels. For more detailed information on Europe and Northern African LNG terminals, please
consult Annex I.
0
100
200
300
400
500
Nr
of
Ship
sNational
2015
2016
0
400
800
1200
1600
Nr
of
Ship
s
Foreign
2015
2016
15
1.3 Objectives of the Thesis
As seen along this first and introductory chapter, Portugal has met the circumstances that led to enforcing
the development of a stronger primary energy supply chain, as the energy dependency on the outside should
decrease in order to ensure energy safety. Also, accompanying the market trends and the increasingly stricter
regulatory demands, Portugal gathers the conditions to develop a local LNG supply chain in the Port of Lisbon,
as it is a waypoint for ships travelling to and from ECA and SECA zones, areas where LNG is largely used as fuel.
Being so, the work presented on this thesis results from the cooperation of the author with Tecnoveritas, a
Portuguese engineering company, on the initial study and development of a small LNG supply chain for OZ
Energia, in the south bank of river Tagus, focusing on the energy usage during the energy conversion associated
to the normal operation of a small-scale LNG terminal.
The ultimate purpose of this thesis is to cooperate in the planning of a new LNG Terminal, more specifically,
to choose and develop the system of liquefaction of the boil-off gas (BOG). The boil-off gas comprises the amount
of gas that heats up back to the gaseous state either when being transported or when stored, due to imperfect
thermal insulation. This occurrence can be translated into energy losses, as the gas will necessarily have to be re-
liquefied or burned, meaning that energy will have to be spent on this process. One of the goals is to present a
solution as efficient as possible to manage the amount of BOG produced by the LNG terminal during its normal
operation.
In order to explore the most adequate solutions to perform the BOG management, it is necessary to
determine the BOG production during operation. Being a terminal yet to be built, the BOG production
determination will be based on the intended features of the terminal, the typical climate and meteorological
characteristics of the zone, the capacity of the terminal, typical insulation materials used, etc., that can influence
the BOG to manage, in order to build and study the adequate models to study the behaviour of the future
terminal.
1.4 Thesis Outline
The present thesis comprises six chapters:
Chapter 1 presents the overview of the energy scenario in Portugal and of the global LNG
development nowadays, aiming at contextualizing the following chapters.
Chapter 2 describes the case-study and the facilities where the main project is to be implemented,
characterizing the territory and its surroundings, as well as presenting the location of the LNG
storage.
In Chapter 3 it is performed a literature review on the existing LNG terminal and BOG recovery
technologies, in order to choose and dimension the more adequate and efficient system to put in
practice further on, on the terminal.
16
Chapter 4 includes a description of the methodologies and models used in the several steps of the
simulation.
Chapter 5 presents the final simulation results, for different seasons of the year, along with
alternatives to re-liquefaction that might also address the problem of BOG management.
Chapter 6 presents the general conclusions, as well as the perspectives to continue the present
work.
17
2. The Case-Study
The process of obtaining and commercializing natural gas in the liquid state comprises a value chain that is
of major importance to understand and deepen the knowledge of it up to the stage where the regasification
terminal is used, one of the key steps on the LNG technical and economic cycles. A simplified scheme of the full
process is schematized in Figure 12, which contemplates the 5 stages of the LNG value chain: exploration,
production, transportation, storage and commercialization of liquefied natural gas.
Figure 12 - Full Gas Field Processes
The process begins with the capture of gas and liquid (crude) from the natural reservoirs (wells), through
production separation, which will be treated differently. The liquid phase of the collected assets is subjected to
few treatments in loco, being transported to refineries to continue to further crude processing. As for the gaseous
part, until it is ready to be shipped and sold, there are important stages through which the gas passes in order to
collect other valuable components from the original gaseous mixture, and finally attain the purity levels required
on LNG. On Gas Conditioning (see Figure 12), the gaseous mixture is then prepared to be liquefied and later sold
this way. On this step, at the inlet of the liquefaction process, the impurities that are removed comprise non-
hydrocarbon contaminants as water, mercury, solids and acid gases. For acid gases, there is a dedicated removal
unit (AGRU) to collect CO2 that freezes and blocks the liquefaction section, and H2S that has toxic and corrosive
characteristics. On the refrigeration, heavy hydrocarbons and LPG are recovered from fractionation and stored
material, providing then the required characteristics of less than 0.1% of water content, less than 50 mol. ppm
of CO2 and less than 4mol. ppm of H2S, required to proceed to liquefaction [49].
Whilst liquefaction occurs, the NGL (Natural Gas Liquids) components are also separated as these are
valuable as separate products, meaning that it is profitable to remove them from the mixture. In NGL it is possible
to find propane, butane and ethane, which are also removed to obtain a rich and pure mixture of natural gas to
be liquefied, reaching the best possible liquid to gas volume ratio when liquefied. This process is of major
18
importance, since it allows the volume of natural gas to be 600 times less than the same mass of natural gas at
room temperature [12], proceeding then to storage of natural gas liquefied at -161⁰C. According to the laws of
thermodynamics, even with the latest insulation technologies, it is impossible to have a perfect storage with no
losses by regasification. This regasified gas constitutes the so-called the boil-off gas.
With the desired amounts of gas stored, it is then possible to ship LNG to distant places (see Figure 12), the
main method of transportation being the LNG marine carriers, which come in different classes with distinct
volume capacities (small, conventional, Q-Flex and Q-Max carriers). Later on, the LNG is unloaded on
regasification facilities and then distributed to the consumers.
In this chapter, it is intended to describe the basic characteristics of an existing terminal and elucidate the
relevant planning factors, as they will play an important part on the subsequent development of a local LNG
small-scale supply chain. The characteristics of the terminal, its surroundings and also the operations that are
already performed in it will be described, so that the possibility of retrofitting the existing terminal also to an
LNG receiving terminal is assessed.
2.1 Description of the Company
The present thesis was developed under a project in progress by TecnoVeritas1, a 20-years-old Portuguese
engineering company, for OZ Energia, the owner of the existing terminal and of the project in development.
OZ Energia is a Portuguese company (former ESSO Portuguesa) that has been operating in the market for
more than 40 years. The company has as main driver the target of being a reference brand in the market of
energy and services, looking always for innovative opportunities and the generation of value in the energy chain.
OZ Energia is positioned on the top four largest gas bottle distributors in Portugal, also competing on the
distribution of propane gas for domestic and industrial use, aviation fuels, and also production of pellets as
substitute of firewood.
Following the strong core values of continuously improving and adding value to their business, OZ Energia
decided to explore the possibility of benefiting from their Terminal of Trafaria and assess, alongside with
Tecnoveritas, if it is suitable to develop a Small-scale LNG Chain on the existing terminal.
1 TecnoVeritas has a large technological scope of expertise on the areas of marine industry, mechanics, chemistry and
electronics, and a high focus on R&D, being a technology provider for national and international companies. Composed by a skilled and experienced team, TecnoVeritas has earned several recognition prizes throughout the world, such as the Green Project Awards in 2013 and the Seatrade Awards, in 2012, for Clean Shipping. This visibility and experience on the field of energy engineering and maritime industry has led TecnoVeritas to participate on this project to provide consultancy and technical support on the planning and further assembly of an LNG terminal located on the south bank of river Tagus, in Lisbon, which will be held during the next years, alongside with a major stakeholder in the area of Oil & Gas.
19
2.2 The Terminal – Case Study
2.2.1 Characteristics of the Terminal
Trafaria Terminal, located on the south bank of River Tejo, Murcafém, comprises a total area of 79,825 m2,
having the possibility of an expansion zone southeast – see Figure 13. The terminal possesses on its premises 38
metallic reservoirs, some of them deactivated, where oil derivate products – such as gasoil, biodiesel, lubricants
or LPG – are stored, gasoil being the product with the biggest nominal storage capacity on the terminal.
Figure 13 - Trafaria Terminal - Aerial View [50].
As relevant information regarding the adjacent areas, river Tagus comprises the northern frontier whereas
the remaining frontier is a natural reserve, REN – Ecological National Reserve, which imposes some restrictions
regarding, respectively, the conservation of river species on the estuary and the natural habitats existing within
the Ecological Reserve.
Also important to refer is that the terminal is located near sensitive areas, namely the passenger pier of
Tagus’ Ferry, Basic School and Kindergarten of Trafaria, and also a Health Centre; these facilities represent public
organizations that are subject to be severely affected in case of a malfunction of the LNG terminal, and should
be taken seriously into account while conceiving the safety measures of the terminal during its planning.
Being on the bank of the river Tagus, the terminal possesses a jetty with 170 metres long and the
bathymetric on the riverbed allows it to support ships that have up to 9 metres of sea-gauge, which means that
20
the maximum loaded draft of the incoming ships cannot exceed 8.5 metres as, otherwise, safety of both the
vessels, the jetty and the personnel might be at risk [51].
Figure 14 - Flow on the river estuary [52].
Consulting the Portuguese Hydrographic Centre, it was possible to apprehend that, while at the entrance
of the estuary the medium amplitude of the tide reaches 2 metres, upstream the river (entering the estuary) the
tide is amplified to 3.5 metres, providing good sea-gauge conditions for the ships unloading on Trafaria terminal.
It is also possible to verify in Figure 14 that the terminal is sheltered from the major flow, providing good stability
to the jetty and to the careful operations to be performed [52].
In order to determine the consumption of a ship that could be representative for this particular study, a
search was made for the type of ships that enter the most in the Port of Lisbon (see Figure 11), and, within these,
which ones would represent the most probable client for the infrastructures we intend to study and build, and
also what could be the size of the main supplier ships, according to the characteristics of the jetty and the actual
bathymetric.
According to the data that was possible to gather on this matter (see Chapter 3, section 3.1.1), and with the
characteristics of Trafaria terminal jetty, the most adequate type of ship considered for the initial assumptions is
a small LNG carrier ship (supplier), capable of docking on the terminal transporting the maximum amount of fuel
of approximately 30,000 m3, or a container ship (client) of up to 1500 TEU, assuring, this way, that the vessels
are compatible with the bathymetric of the river along the jetty [53].
Due to legal restrictions, only REN (National Energy Network) can commercialize natural gas in gaseous
state. This implies that the facilities to be built cannot include a regasification unit. So said, natural gas shall only
be delivered from the terminal in liquid state, either to fuel ships or to supply LNG carrier trucks, providing,
therefore, LNG for both land and sea/river users. This circumstance demonstrates the major importance and role
21
that the boil-off recovery system will have to play on the facilities, as all the BOG (Boil-off Gas) will have to be
either used to unload LNG from incoming cargo (situation that will probably not occur as desirable in using the
BOG due to the need of sharing the jetty slots with other users) or reliquefied in order to be stored once again
in its liquid form.
LNG is often used to supply industries (more often, cogeneration), mainly where there are no natural gas
pipelines, finding, this way, another interesting market niche for exploiting the facilities while the marine LNG
market for the terminal is being formed (see Chapter 3, section 3.1.4). In fact, small industries exist near to the
terminal, that might represent potential clients and should be options to explore by the LNG terminal operator:
a food dry bulk storage and receiving terminal – around 650 metres away (might benefit from refrigeration
coming from the LNG terminal), NATO Ammunitions Dock (whose pipes pass beneath the terminal about 350
metres away) and a petrol station about 2 kilometres away.
One of biggest present difficulties on creating new LNG terminals to supply ships resides on the fact that
the market for LNG fuelled ships is still under development, as ship owners do not invest on these vessels because
LNG terminals are not abundant. As for investors, an LNG terminal destined to fuel ships is still a risky investment,
as the market is still not mature enough to guarantee the profitability of the terminals. This vicious cycle still
constitutes a great barrier to the development of LNG chains and to the use of LNG as a marine fuel, and can
only be solved by new investments on this area that can promote this business. As so, the present project
represents an opportunity to contribute to the development of a stronger LNG market in Portugal, also creating
a chance to improve and advance maritime economy, one of the present targets on the national strategic
development plans [54], attaining the economical, geostrategic and geopolitical potential that Portugal
possesses, and creating conditions to attract national and international investments.
2.3 Choosing the Storage Facilities
In order to determine later on the most suitable LNG liquefaction system to be installed on the terminal,
and previously to any other further studies, it was necessary to assess which will be the better place on the
existing terminal to place/build the storage facilities, taking into account all the restrictions regarding other
products that are handled in the terminal, and also the legislation regarding the identified sensible surrounding
areas mentioned above.
As a first step to visualize and learn the surrounding premises, the municipal plans of Almada were
consulted, accessing the GIS system of the city council, in order to assess what type of terrains will have to be
taken into account – see Figure 15.
22
Figure 15 - Map of Conditioning Factors: Trafaria Terminal and Surrounding Areas [55]
It is possible to recognise that there are three sensitive areas around the terminal: the river Tagus, a
National Ecological Reserve and a Historical Centre on the vicinity. As so, in order to plan the location of the
storage tanks on the terminal, some thoughtfulness is required on this matter while the studies are developed,
implying that the inherent restrictions of this special areas must be acquainted and applied.
To complement the study of the terrain, Trafaria facilities were visited in loco, and the following available
places for LNG storage were identified on building plans, through the use of AutoCAD software to identify and
measure the available areas, as depicted in Figure 16.
The identified regions in Figure 16 as A, B and C, are the available and possible locations for the LNG tank
and systems, and are the options under consideration:
A: Located near the Gasoline Reservoirs;
B: Located where reservoirs T1 to T9 and T18 are placed;
C: Located on unbuilt land.
A more detailed general view of Trafaria Terminal can be found on Annex III.
23
Figure 16 - General view of Trafaria Terminal with the three possible places to install the reservoirs (identified in green)
The three identified locations for the storage facilities are presented and discussed next.
24
A - Storage facilities located near the Gasoline Reservoirs
Figure 17 - First place considered – alongside the gasoline reservoirs (A in Figure 16)
B - Storage facilities located where reservoirs T1 to T9 and T18 are placed
Figure 18 - Second place considered – where reservoirs T1 to T9 and T18 are placed (B in Figure 16)
25
C - Storage facilities located on unbuilt land
Figure 19 - Third location considered - Unbuilt terrain (C in Figure 16)
Table 6 summarizes the advantages and disadvantages found for each possible location, in order to choose
the best location for the LNG storage facilities.
Table 6 - Summary of the Advantages and Disadvantages of the Three Considered Locations for the LNG Facilities.
Option Advantages Disadvantages
A
999 m2
Proximity to the reception jetty.
Reduced boil-off losses while being stored.
Basic Infrastructures to receive the storage tanks are already built.
Reduced area.
Possibility of building constraints regarding safety distances to be kept from the other existing reservoirs.
B
1966 m2
Biggest area among the considered options.
Existing tanks and structures in this area are currently out of service.
Urge to demolish/remove the existing tanks and structures already existent in this area.
Necessity to create infrastructures capable of transporting LNG to a higher elevation.
C
1125 m2
Unnecessary to remove equipment or infrastructures already existent.
No safety restrictions regarding the proximity to reservoirs of other fuels.
Proximity to a National Ecological Reserve (REN), implying a restriction buffer to any construction to be made on its vicinities.
Unavoidability to create infrastructures to transport LNG to a high elevation (∆h ≈ 50 metres).
Farthest location from the jetty.
Urge to perform excavations, earthworks and creation of basic infrastructures (roads, etc.) that already exist on the other options.
26
Available area is definitely a major constraint to consider: whether is the place chosen, as the BOG recovery
system will be an installation in the surroundings, and the available space should be as large as possible. Also,
the distance to the jetty is an important factor as there is heat ingress through the piping system, and the farthest
the storage tank is, the higher is the heat ingress, and thus larger is the BOG production while loading or
unloading LNG. The proximity to other storage tanks in the limited space of the terminal, where trucks often pass
carrying other fuels, highlight the option of building an in-ground tank; this technology offers two significant
advantages – effective land use and structural safety [56] – which meets the requirements of the terminal.
Building an in-ground tank is only possible on the second or third locations considered - locations B and C.
This alternative is considered as it might be sufficient to supplant the issues related to the proximity to the special
areas surrounding and the other products storage tanks, since it has almost no landscape impacts or leakage
problems if any situation occurs. It is important to notice that, in case of choosing this location for the
implementation of an in-ground storage tank (see Chapter 3, section 3.1.2), the buffer from the National
Ecological Reserve might not be necessary, enlarging the available area of the third location to the triple of its
actually defined value.
Figure 20 - Calculated distance from the Jetty to Location C (273.9 metres).
It is also known that, when the LNG is unloaded from ships to the storage facilities, after approximately 250
metres of transport through pipelines the regasification losses (BOG production) are significant [57].
Acknowledging that the maximum distance covered by pipeline inside the terminal might be greater than this
value - maximum height (jetty to third location) of 50 metres and maximum distance approximately 270 metres
(see Figure 20) – and disregarding the possibility of installing an intermediate boil-off recovery system, if the
27
chosen storage location is the farthest from the jetty, the production of extra boil-off gas while the operations
occur must be considered when dimensioning the boil-off recovery system.
The different hypothesises were subjected to the appreciation of the responsible people for the project and
after consideration of all the details, option B – Storage facilities located where reservoirs T1 to T9 and T18 are
placed - was chosen as the most suitable site to place the LNG facilities. This option overcomes the eventual
licensing problems regarding construction near to the National Ecological Reserve (REN) and it is closer to the
jetty than Option C would be (approximately 220 meters). Simultaneously, it does not present the space issues
option A has, and allows the construction of an in-ground tank. Also, it was decided that the inactive tanks should
be removed in a very near future, therefore leaving the place available to implement the LNG storage facility and
also the required BOG recovering unit.
Being so, Figure 21 demonstrates the preview of the final location of the in-ground LNG storage tank to be
built on Trafaria Terminal.
Figure 21 – Final location of the LNG reservoir.
As the characteristics of the terminal and the site options are presented, and in order to better understand
the several processes that shall be expected on Trafaria Terminal, on the next chapter a bibliographic review
regarding LNG terminals will be performed, having as objective the clarification the main operations on the
terminal and the assessment of the options and constraints probable to encounter during the stages of planning
and development, deepening later on the need for liquefaction units or other technologies able to recover the
boil-off gas produced on such facilities.
28
3. Literature Review
As the project under development comprises solely technologies within LNG storage and re-liquefaction,
the current chapter will focus essentially on this type of facilities and on the associated boil-off gas recovery
technologies, as well as practices to apply later on the liquefaction system.
A more detailed explanation of the most significant infrastructures related to the regasification and/or re-
liquefaction plant can be found next, which comprises the scenery of the second chapter of the present thesis
and explains in detail each section that will be part of the operations on Trafaria Terminal.
3.1 LNG Receiving Terminal
The receiving terminal (for regasification, storage and/or re-liquefaction) comprises the final step of the
LNG supply chain before the commercialization, as that is where LNG is delivered to the end users, and includes
the LNG unloading jetty (berth), the storage and boil-off recovery, and finally the send out facility, where LNG is
either heated back to its gaseous state to be sent through pipelines, or delivered to tankers on liquid form. The
following sections approach each of these steps with more detail.
3.1.1 The Jetty
The positioning of a jetty at an LNG marine terminal is a crucial factor in determining the overall risk on the
transfer operation of ship/shore and its position should be studied on the conceptual stage of the project [58].
The jetty should also be planned according to the bathymetric, tide, wind and currents [59] that characterize the
docking area as well as being provided with the necessary stability to perform the loading and unloading
operations [60]. The jetty design should be projected according to the planned volume capacity for the storage
facilities at the terminal, as its characteristics will determine the ships that are allowed to moor and load/unload
on the terminal, and its dimensions will determine the volume the moored tanker can carry. As an advised
minimum water depth for a small-scale LNG terminal, 10 metres are usually sufficient for the operations to be
carried out on the terminal [57].
With the purpose of clarifying the meticulous operations that take place at the jetty, the unloading and
loading operations will be briefly explained.
The LNG is usually unloaded from the tanker vessel through articulated unloading arms (cryogenic hoses)
to an unloading pipeline that drives the LNG to the tank – see Figure 22. It is common that two different types of
arms are connected to the vessel tank: one for unloading LNG and the other to return natural gas in its gaseous
form to the tank, in order to avoid vacuum and aid on the removal of LNG. Another hypothesis, not always viable,
prescind from the return blower and perform the return the gas to the tanker through a pressure difference
29
between the storage tank and the vessel [61]. This
procedure is usually temporary as it does not always
ensure that the maximum volume of LNG is removed
from the tanker.
As for the loading procedures, LNG is loaded into
each of the tankers tanks through the arms to liquid
header pipes and finally to the tank bottom. The gas
displaced by the LNG, as well as the BOG generated
during the loading process, must be returned to shore
installations and are controlled by the safety devices that
control cargo vapour pressures and liquid levels. Overfilling is also controlled by self-closing valves, automatically
activated whenever the predefined levels are reached. During both processes of loading and unloading, it is
compulsory that the ballasting (while emptying) and deballasting (while loading) occur, while the vessel draught,
stability and longitudinal bending are carefully monitored onboard [62].
According to SIGTTO’s safety procedures [60], it is of major importance that, during all the loading and
unloading procedures, the arms and all the process are handled in a manner that eliminates any risk of liquid
release and reduces the cargo vapour leaks to the atmosphere to an absolute minimum, in order to ensure the
operations safety, as well as guarantee the safety of all the personnel executing the activities on the jetty.
When it comes to planning the receiving terminal, care should be taken to make sure that there will not be
oversizing or undersizing of the different facilities inside the terminal, as these will be working directly with each
other and depend on each other. Being so, there is an important connection between the cargo ships, the jetty
and the storage. If there are no storage restrictions, these should be planned according to the possible
dimensions of the jetty and vice-versa. Also, the size of the LNG carriers should not exceed the maximum value
allowed on the jetty. Andrieu [63] refers in his research the target dimensions of LNG carriers, the storage
facilities, and also the working pressures and flow rates for a small-scale receiving terminal (SSLNG) and a large-
scale receiving terminal (LSLNG), which are reproduced in Table 7:
Table 7 - Main differences between SSLNG and LSLNG Terminals [63]
Terminal Functions Characteristic SSLNG
Terminal
LSLNG
Terminal
Unloading LNG Carriers Size From 7,500 to 35,000 m3 From 70,000 to 265,000 m3
Storage LNG Storage Tank
Capacity From 20,000 to 50,000 m3
> than 160,000 m3, up to
millions of m3
Send-out
Flowrate From 0.2 mtpa* to 1 mtpa > 2 mtpa
Pressure From few barg to 25 - 40
barg
Gas Network Pipeline
pressure (typically between
55 and 90 barg)
*1 mtpa ≈ 170 Million m3/h
Figure 22 - LNG Tanker Unloading
30
As it is possible to observe in Table 7, the main operational resides on a reduced send-out flow rate on the
SSLNG, which can be 5 to 20 times lower than on a LSLNG terminal. Also, due to the storage capacity and the
send-out flowrate, SSLNG terminals, contrary to LSLNG that can supply several costumers, are usually dedicated
to few or even just one consumer, which, due to the reduced number of users, increases the availability and
flexibility of the SSLNG terminal. Similarly, the send-out pressures on the SSLNG terminal are customizable for
the specific consumer needs, whilst on LSLNG terminals the pressure is usually determined by the natural gas
network connected to it [63].
3.1.2 Storage
The types of storage facilities depend mainly on whether they are supposed to be used to meet winter
shortages of gas (or seasonal fluctuating gas demand) or to supply baseload gas by long-distance shipment. An
LNG import terminal developer faces two important decisions related to storage: how much to build and the
type of storage tank more adequate to the planned dynamics of the terminal. The selection of a tank design as
well as its complementary foundations are influenced and should also account for the different characteristics
of the terrain, such as the topography, geology (soil conditions), seismic concerns, regional safety regulations (as
a vapour or liquid leakage should be concerned and prevented), and, finally, exclusion and protected zone
requirements [64].
On board ships, apart from the indispensable insulation to minimize evaporation losses, it is necessary that
the LNG cargo is kept away from the ship structure as it might lead to a disastrous situation in case of contact
with the ship structure, as mild steel becomes brittle below -50⁰C. Provided that insulation is adequate,
evaporation losses (boil-off gas) might be as low as 0.1% per day for the tank contents [12].
According to the European Standards, an LNG
containment should be designed to safely contain
the cryogenic temperature, allow safe filling and
removal of LNG as well as the boil-off gas to be
safely removed, minimize the rate of heat in leak,
and also prevent the ingress of moisture and air,
except as a last resort to prevent vacuum conditions
in the NG vapour space, as the tank should be
prevented from going into negative relative
pressure beyond the permissible limit.
LNG onshore can be contained in double-walled metal tanks (similar to those used on board ships) - see
Figure 23 - as aluminium or nickel steel inner vessels or membranes, surrounded by insulation and weather-
proofing materials. Another option is to erect pre-stressed concrete tanks with extra resistance above the ground
or cast them below the ground surface. Occasionally, it is possible to adapt already existing underground spaces
for LNG storage, e.g. on salt caverns or depleted oil reservoirs, as Wang and Economides [65] refer on their study.
Figure 23 – Double Containment LNG Storage Tanks in Sines, Portugal [161]
31
In order to better organize the different tank categories, these are presented in four main categories: single,
double and full containment, for above-ground storage tanks, and membrane, for in-ground tanks.
Single Containment
This type of tanks (see Figure 24) is the fastest and easiest to build as
the structure to assemble is not very intricate. These tanks require a
large area to build in, as they require leak prevention dykes to secure the
LNG on this pre-designated area [66] as there is only one outer wall made
of carbon steel [67]. Although it is cheaper and has a simple construction,
it is the most difficult type of containment to get approved by the
regulatory entities, as it requires a larger safety distance and it comprises
the less safe choice among the several tank options.
Double Containment
Comparing with single containment tanks, these tanks (see Figure 25)
allow a closer spacing between tanks, as they do not require a
prevention dyke. In case of leakage, the LNG is contained on a second
bund wall of pre-stressed concrete.
Full Containment
For this type of tanks (see Figure 26), no bund wall is required, as, in case
of failure, both natural gas and LNG are contained by the concrete walls,
making this the safer kind of tank above ground and also the most used
nowadays, alongside with the in-ground membrane tanks [68].
In-ground Membrane Tanks
In-ground tanks (see Figure 27) are usually membrane tanks and
consist of a pre-stressed concrete outer wall and an inner layer of
insulating load-bearing foam, over which is laid a thin cryogenic steel
membrane with 9% nickel [67] that will be in direct contact with the LNG,
assuring, this way, that no intrusions of water enter the tank [64]. It is
also possible to build in-ground spherical membrane tanks, which have
similar characteristics to the cylindrical tanks and are suited to areas that
have a high seismic potential, as described on the European Standards for LNG tanks design.
Figure 27 - In-ground Membrane Storage Tank
Figure 25 - Double Containment Storage Tank
Figure 26 - Full Containment Storage Tank
Figure 24 - Single Containment Storage Tank
32
The main advantage of in-ground tanks, both concrete or natural, lies in the fact that the building of
containment dykes is not mandatory, as the risk of leaking is low and there is no danger associated to the burst
containers, meaning that there will not be any leakage products to collect. On the other hand, above ground
containers are attractive for the fact that they allow repairing and there is a much stricter control of the
temperature and behaviour of the tanks insulation.
The safety characteristics of in-ground tanks, as well as the protection from solar radiation to the walls that
this technology provides, made this type of tank the chosen to store LNG in Trafaria Terminal. Also, the reduced
aesthetic damages of the landscape are a plus on this type of tanks, as only the dome and some auxiliary
equipment is visible.
Another way of storing LNG is on floating storage regasification units (FSRU), special moored vessels capable
of storing, regasifying and, if necessary, transport LNG onboard [69]. These facilities are either converted from a
traditional LNG vessel or it can be purpose-built, always requiring an offshore terminal, which is connected by
undersea pipelines to transport regasified LNG to shore or to a receiving terminal. The FSRU is a solution for
smaller or seasonal markets, and can be developed cost-effectively and considerably faster than onshore
facilities. For that reason, this is often a temporary solution while onshore facilities are constructed, as it can be
easily redeployed elsewhere and used just as effectively as before and in short time [70].
As these floating facilities do not provide a direct analogy with the industry case-study at issue, they will
not be discussed further.
3.1.3 Materials and Insulation
Insulation has become a theme where a great effort of research is put on, as many uprising fields of
engineering that use cryogens are growing, such as energy storage, superconductivity and even space
technology.
When it comes to maintaining such temperatures as the ones used to operate and store LNG or other
cryogenic fluids it is of utmost importance to have a correctly dimensioned insulation in order to reduce the heat
that enters the tank. Consequently, insulation is one of the major determining factors that influence the
production of BOG in an LNG system, and which will be analysed and applied later on.
Nevertheless, the performance of the insulation must always justify the cost [71], which means that, in the
present case study, pondering must be done regarding the achieved daily BOG rate and its management and the
cost of erecting the tank with an improved insulation. Therefore, insulation of the tank will be dimensioned
according to the thermal performance requirements, limited by the calculated BOG rate.
The three elementary factors that determine the overall suitability of the insulation materials are the
thermal conductivity, density/weight, and the cost of labour and materials. These factors will be presented for
every insulation material studied, especially for those usually utilized on LNG in-ground tanks.
33
LNG tanks usually present different materials for the bottom, walls and roof, being a studied assortment of
materials that provide structural strength to the tank and thermal insulation to the cryogenic fluid.
Below follows a short description of materials typically used in LNG tanks to insulate and for structure
purposes:
Concrete: it is meant to provide structural strength to the tank and resistance to weather conditions.
9% Nickel Steel: standard ferric structural steels are not suitable for extreme cryogenic temperatures and
LNG’s, as there is an increased risk of brittle fractures and not enough toughness. Alloy 9% Nickel steel is
the material that must be in direct contact with LNG [67], achieving the mechanical and physical properties
required for building storage tanks and cryogenic pipes, withstanding temperatures down to -196°C while
still offering the structural integrity required [72].
Sand: a sand layer is usually placed between the nickel steel layer and the foam glass insulation.
Asphalt: a thin layer of asphalt is commonly laid between the layers of foam glass insulation (occasionally
also with a felt layer) [73] in order to seal and drawn tight the layers so that the system is vapour sealed
and no additional vapour barrier is required [74].
Foam Glass: this impermeable material is designed for industrial applications on with a high load-bearing
requirement, having a combination of high compressive strength and low thermal conductivity. Its
attributes make this material suitable for cryogenic tanks bases [75]. A possible substitute for foam glass as
insulation is polyurethane but it usually turns out to be more expensive as this material is highly flammable
and thus needs fire proof coating in order to be used in a hazardous environment (such as an LNG terminal)
and comply with all the safety regulations applied.
Expanded Perlite: being a naturally occurring siliceous volcanic rock, perlite can be expanded from four to
twenty time its original volume by heating it to above 900°C with two to six percent combined water,
causing entrapped water molecules to turn to steam and creating countless tiny glass bubbles that allow
the crude rock to pop and expand [76]. Expanded perlite, in addition to its thermal properties, is easy to
install, relatively low costly, non-combustible, and does not shrink, swell, warp or slump [77], being often
the main insulation material chosen for LNG tanks.
Aluminium: this material is usually an alloy that receives a special treatment to develop a temper that
guarantees the required intergranular and exfoliation corrosion, as well as temperature resistance without
risking brittle fractures. It is often used on LNG tanks as the supporting material of the insulation platform
(deck) hanging from the roof, often used as an alternative to welded nickel steel, for it represents a lighter,
safer and with better strength-to-weight ratio than former technologies [78].
According to the particularities of these materials, the tank characteristics will be chosen and planned later
on in order to project the BOG that shall be produced on the tank. All the described materials will be used in the
34
Trafaria LNG tank project, according to examples of actual tanks built and information available from industrial
projects. According to these examples, the typical order of placement and thickness of each material will be
taken into consideration, as there is no rule or standard for the choice of the materials of an LNG tank, and each
contractor has their own developed technology and method. As so, the basic characteristics of these materials
are presented in Table 8, for further reference and guidance, as well as reference prices for each material.
Table 8 - Materials Used on the Construction of an LNG Tank and Principal Characteristics.
Material Conductivity Emissivity Density Price per m3
W/m.K kg/m3 €
Concrete 1,80 0,97 - 79,93 2
9% Nickel Steel 17,18 - - 125,18 3
Sand 0,25 - 1 682 9,96 4
Asphalt 0,75 - - 1,88 5
(price per m2)
Foam Glass 0,02 - - 888,46 6
Expanded Perlite
0,03 - 32 1 544,37 7
Aluminium 71,21 - 2 700 43,21 8
The prices displayed in Table 8 were obtained from manufacturers of the presented materials, which divulge
the prices publicly, and are used only as a reference. To note that for the actual project planning and budget
phase it is necessary to resort to official quotation requests to adjust these values to the actual market
conditions, eventual bulk quantities special prices, location influence and final tank project.
3.1.4 Boil-Off Gas Management
Due to temperature differences between tanks, pipes and the surrounding atmosphere, whenever the
tanks are filled, LNG tankers are loaded or unloaded, or due to heat exchange [58], boil-off gas is generated,
usually with an assumed volume 600 times greater than that in liquefied form. This makes essential the existence
of an adequate treatment of the boil-off gas.
As seen before, LNG is stored and transported in cryogenic tanks in liquid form, i.e. liquid at a temperature
below its boiling point. Nevertheless, due to heat transfer, LNG continuously evaporates. Inside the tanks, LNG
exists in thermodynamic equilibrium, where liquid and vapour coexist, their masses depending on the operating
pressure and temperature. Having a low pressure on the tanks, it is possible to apply Raoult’s law to the multi-
2 [167] Orçamentos 2009-2017, “Orçamentos e Orçamentação na Construção Civil,” 2014. [Online]. Available: http://orcamentos.eu/precos-de-betao-pronto/.
Results obtained indicate Cycle B as the most efficient one, presenting a significantly smaller specific energy
consumption to perform the liquefaction of the BOG, of approximately less 24%. The reference cost of electrical
energy was consulted from an energy supplier, for a consumer receiving energy in medium voltage, and its value
is 0.1022€/kWh. Figure 63 illustrates the energy performance and associated cost of the liquefaction cycles.
Figure 63 – Specific Consumption and Cost per Ton of BOG Processed
It is important to refer that, regarding the energy consumption values computed, the circulation pumps,
lubrication pumps, and other inherent auxiliary equipment were not contemplated.
Table 21 and Figure 64 present the values of the COP for the cycles, as well as the real COP (COPactual) values.
The COP value was calculated using equation (12), and it does not consider the work performed by the turbine
as the driver of the second compressor. The KPI COPactual was calculated due to the specific characteristic of this
liquefaction cycle, by having a turbo-expander; it was calculated dividing the absorbed heat from the BOG by the
work performed by compressor 1, assuming that the work performed by the second compressor is recovered by
the work produced by the expander. It is worthwhile to note that the use of a turbo-expander contributes
drastically to the efficiency of the cycle by providing the whole power absorbed by the second stage of
compression. A perfect matching of these two turbomachines is essential to reach high COP values.
y = 0,2691x + 4,3092
y = 0,1869x + 2,9925
y = 0,2432x + 3,8969
y = 0,169x + 2,706
2,00
3,00
4,00
5,00
6,00
-155⁰C -140⁰C -125⁰C -110⁰CNit
roge
n F
low
Rat
e [k
g/s]
Temperature
Evolution of the Flow Rate of Refrigerant Required Vs BOG inlet Temperature
CYCLE A, BOGr=0.067%
CYCLE B, BOGr=0.067%
CYCLE A, BOGr=0.05%
CYCLE B, BOGr=0.05%
CYCLE A, BOGr=0.039%
CYCLE B, BOGr=0.039%
0,0
1,0
2,0
3,0
4,0
5,0
6,0
0,00
50,00
100,00
150,00
200,00
250,00
-155ºC -140ºC -125ºC -110ºC
Co
st p
er t
on
of
BO
G li
qu
efie
d
[€/t
on
]
Ener
gy p
er t
on
of
BO
G li
qu
efie
d
[kW
h/t
on
]
Temperature
Specific Consumption and Cost per Ton of BOG Processed
CYCLE A, kWh/ton
CYCLE B, kWh/ton
CYCLE A, €/ton
CYCLE B, €/ton
76
Table 21 – Coefficients of Performance
Cycle A Cycle B
COP 0,800 1,047
COPactual 1,600 1,646
Figure 64 - Coefficients of Performance - Cycle Comparison
The COP values of Cycle B are higher than those of Cycle A, as expected; the actual COP shows the actual
potential of each cycle, reflecting the work recovered from the expander.
Notice that, with such a significant load variation (between modes of operation of the plant), it is advised
that the turbomachinery components have adequate characteristics to guarantee the system can process
different BOG flow rates with optimized efficiency.
The capacity control of the re-liquefaction system may be achieved using a pressostat, by the increase of
the pressure of the tank, which starts the re-liquefaction system, and through an LNG valve; when this valve is
opened, cold LNG enters the tank, lowering the temperature inside, and, therefore, its pressure - see Annex XV.
Moreover, it is necessary that the temperature of the tank and of the re-liquefied BOG is monitored
carefully, to avoid the vapour in the storage tank to become sub-cooled; overcooling may result in the occurrence
of vacuum inside the tank, potentially damaging the tank structure [91].
5.2.2 Cogeneration
Taking the LHV of BOG as 39.05MJ/Nm3 (10.85kWh/Nm3), and after converting the produced BOG rate to
Nm3, it was possible to calculate for each scenario, the power of a potential cogeneration installation in the
Terminal. Assuming the thermal efficiency of the engine as 35% and the electrical efficiency as 40%, it was
possible to calculate several characteristics of this possible installation, as summarized in Table 22.
Table 22 – Cogeneration Prospect Scenarios
Scenarios BOG rate = 0.039 %/day BOG rate = 0.050 %/day BOG rate = 0.067 %/day
Best (Winter)
Worst (Summer)
Best (Winter)
Worst (Summer)
Best (Winter)
Worst (Summer)
BOG Rate [m3/h] 114.03 117.12 142.14 147.51 182.62 191.55
BOG Rate [Nm3/h] 121.91 125.21 151.96 157.70 195.24 204.78
Power of the Cogeneration [MW]
1.322 1.358 1.648 1.711 2.118 2.221
Electric Power [kW] 528.95 543.28 659.34 684.25 847.12 888.53
Thermal Power [kW] 462.83 475.37 576.92 598.72 741.23 777.46
Produced Electricity per month [MWh]
380.84 391.16 474.73 492.66 609.93 639.74
Produced Heat per month [MWh]
333.24 342.26 415.38 431.07 533.69 559.77
PES [MWh] 187.293 192.366 233.462 242.281 299.952 314.614
Avoided CO2 Emissions per month [Ton CO2 eq.]
37.83 38.85 47.15 48.93 60.58 63.54
Avoided CO2 Emissions [gCO2/kWh]
99.32
The different BOG scenarios enable the operation of a small/medium capacity cogeneration (1.3MW –
2.2MW), allowing the production of electricity on site, for self-consumption or to sell to the electric network,
while producing heat that can be sold to the adjacent industries or also be used internally.
Cogeneration is a method that allows energy conversion with reduced environmental impacts when
compared with other forms of producing energy through fossil fuels. The avoided CO2 emissions were calculated
in order to perceive the positive impact of such an installation, and a monthly estimated reduction of 38 to 64
tons of CO2 is expected. The avoided CO2 emissions per kWh are constant in all analysed scenarios as its
0,0000,5001,0001,5002,000
COP COP real
COP vs COPactual
Cycle A
Cycle B
77
calculation is based on the thermal and electric efficiencies, assumed equal in all cases.
It is also important to refer that natural gas should be compressed before the engine inlet (to around 5-
7bar, according to manufacturers) to ensure the correct fuel injection, and also the auxiliary systems such as
pumps and an eventual chiller for the production of chilled water, require additional energy consumption.
5.2.3 Emergency System
As described in section 4.4.2.3, despite being necessary, the flare is to be the last resource to manage BOG.
Table 23 shows the profit loss associated with burning the BOG produced in each considered scenario during a
certain period, as well as if a rollover phenomenon happens.
Table 23 – Flare Profit Loss
BOG Rate Scenario Profit Loss
€/h €/day €/month
0.039 %/day Best (Winter) 26.46 635.10 19 052.88
Worst (Summer) 27.18 652.30 19 568.90
0.050 %/day Best (Winter) 32.99 791.65 23 749.58
Worst (Summer) 34.23 821.56 24 646.65
0.067 %/day Best (Winter) 42.38 1 017.11 30 513.41
Worst (Summer) 44.45 1 066.83 32 004.97
€/h €/ 2h €/ 3h
Rollover Phenomenon
10 x BOG rate 264 – 342 529 – 684 793 – 1026
30 x BOG rate 793 – 1026 1587 – 2 053 2381 - 3080
The price of the LNG used was 7$/MMBTU [135], which is equivalent to 0.02€/kWh. Assuming a LHV of
10.85kWh/Nm3, the price of 1 Nm3 of BOG is 0.2171€. The presented ranges of value for the rollover
phenomenon are the best and worst case under study. For this event three scenarios were considered according
to the study on the behaviour of existing LNG installations during rollover performed by GIIGNL [136]: one, two
and three hours of excessive BOG, in the proportion of 10 to 30 times the expected value under normal
operation.
With the relevant differences found between the two analysed BOG rates, the insulation costs, and the
holding mode capacity of each scenario, it is important that the organization assesses more deeply and with
more detailed information in project phase, the cost vs benefit of choosing one BOG rate option or another.
Either way, the BOG management should be adequate to the chosen option and be as efficient as possible.
Simulations were performed to study a re-liquefaction system and a cogeneration plant burning BOG as fuel.
Regarding the re-liquefaction options simulated, Cycle B presents a COP value that is 24% higher than that
of Cycle A, while the real COP value is only 3% higher, accounting for the work produced by the turbine to drive
the second compressor. Also, the specific energy consumption of Cycle B is 24% smaller than that of Cycle A,
which represents a significant amount of energy saved while performing the same liquefaction work; these values
indicate Cycle B as the most energy efficient cycle, thus the most adequate to perform the BOG re-liquefaction.
With good results and without a great impact on the LNG storage in holding mode, the cogeneration plant
might also be a good option to recover BOG as, despite the inherent inefficiencies of any internal combustion
engine, the thermal and electrical energy produced can still be used for the benefit of the terminal, while avoiding
CO2 emissions – approximately 38 to 64 CO2 tons per month. The cogeneration can be a good method to process
the holding mode BOG, while having as backup (and capable of processing that and the BOG produced on loading
and unloading events) a re-liquefaction system, based on the most energy efficient cycle simulated - Cycle B.
78
6. Concluding Remarks
6.1 Conclusions
With the growth of primary energy demand, LNG is expected to represent an increasingly larger role as a
fuel - projections indicate that the LNG trade will have an annual growth of 3.9% until 2035. This progressively
bigger demand has boosted the development of LNG supply chains, and Portugal, due to its significant maritime
traffic, rises as a promising future for the development of a new SSLNG supply terminal at the entrance of the
port of Lisbon (Trafaria).
The several processes that comprise a regular regasification terminal (jetty, storage, regasification and boil-
off gas handling) are deeply linked, and the planning of such facilities and processes involving a profound
knowledge of the characteristics that each component can assume, as these are restrained by each other and by
the intrinsic characteristics of the terminal. Knowing the characteristics of the terminal of Trafaria and
considering regulatory political restrictions it is not possible to solve the BOG issue sending it to the pipelines of
the natural gas network; therefore two options are left as valid: either the BOG is used as fuel on an adjacent
facility or it is re-liquefied and stored back to the tank in its liquid state, awaiting to be supplied to the customers.
BOG is quite dependent on the tank location. One advantage found in operating an in-ground tank is that,
while the heat ingress is performed mainly through the dome and the remaining areas of the tank have a very
constant and predictable heat ingress, this type of tank construction minimizes the heat ingress into the tank,
resulting in small variations of the BOG production during the day. This type of tank also presents structural
advantages, especially important in the Trafaria terminal, which is located on a hillside in a steep slope. For a
tank with the same insulation characteristics, in spite of having a higher initial investment due to the need of
building deeper foundations, an in-ground tank has the advantage of having a reduced heat ingress, as the effect
of convection and irradiation are minimized; this will also result in BOG management solutions with smaller
power and consequent energy consumption, as the BOG production is smaller, paying-off throughout the project
life.
After determining the production rate of BOG, the insulation of the in-ground tank was conceived in order
to assure the heat ingress would not overcome the defined rate. The used model allowed to define the daily BOG
rate as 0.067%, which was then compared with the value 0.050% found in the literature, and a lower value for
comparison – 0.039%. The heat ingress in the LNG system was calculated for different operation modes, and for
different seasons of the year, namely the ingress through the tank structure, and through pipelines and pumping
system during loading and unloading processes.
As for the loading and unloading processes, these produce significantly more BOG, despite the fact that
these actions do not happen very often (depending on the frequency of the terminal bunkering processes),
contributing to the BOG production through the heat ingress into pipelines and pumping system. Independently
the BOG management method chosen, the method is to be prepared to process the total amount of BOG
79
production in the LNG system, from the tank, piping, and pumping system.
The addressed methods for BOG management include a system of BOG re-liquefaction and a cogeneration.
The BOG re-liquefaction system studied and applied to the present SSLNG case-study is a nitrogen single
expander cycle, as this technology was found the most adequate to the type and size of the terminal. Both
options were studied for the different seasons and the two BOG rates considered.
The re-liquefaction cycle was studied with two different cycle configurations, namely two different inlet
pressures at the first compression stage. The specific energy consumption and COP were calculated for both
cycles, pointing out Cycle B, with lower inlet pressure at the first compression stage, as the most efficient cycle.
Although the present study indicates some small-scale re-liquefaction plant issues, namely, specific needs
in terms of BOG and re-liquefaction control system, the re-liquefaction system can be further improved, namely
by adding a pre-cooling cycle to the BOG stream or studying other configurations of the cycle such as the dual
expander cycle, although more expensive in terms of investment.
Cogeneration has also been proved an alternative, since the BOG produced is sufficient to power a small
cogeneration (between 1.3 MW - scenario of lower BOG production - and 2.2 MW - scenario of higher BOG
production). In addition, cogeneration enables primary energy savings to be made while producing electricity, as
well as avoiding GHG emissions (CO2). It shall be a decision of the operator of the terminal to decide whether the
electric and thermal energy produced can be consumed in the terminal or exported to any facility nearby the
terminal.
One possibility of using the heat produced by a cogeneration in the terminal is replacing the electric
resistances tracing in the bottom of the tank by a piping system on which heated fluid, capable of preventing the
frost heave, circulates; nonetheless, the feasibility of such opportunity requires further study.
It is also important to understand whether the investment in a cogeneration plant shall be of interest to the
organization or if, on the contrary, the installation of a sole BOG re-liquefaction system is preferable; by choosing
the re-liquefaction system, it is possible to maintain a largest amount of LNG available, considering the potential
long periods of operation in holding mode, thus guaranteeing the availability of the maximum LNG load possible
at all times. However, and knowing that the tank can endure long periods of time without losing a very significant
volume of LNG, cogeneration might be an interesting solution for the terminal BOG management.
Still, it is important that, even if a cogeneration plant is installed in the terminal, the re-liquefaction system
is still present as backup, and can process the BOG from the tank and from the loading and unloading lines. This
should reassure that even if the cogeneration plant fails or stops for maintenance, there is an efficient and
reliable way of managing the BOG. In any case, the use of the flare should be avoided, as it is only an emergency
system as it does represent a large profit loss to the terminal owner, as described in this work.
80
6.2 Future Work
The present thesis was performed as a preliminary work for a possible SSLNG terminal project at Trafaria
(Lisbon port). It serves to identify the different available technologies that constitute one such SSLNG terminal.
This study identified scenarios for the chosen location and capacities regarding the energy consumption related
to the energy-consuming processes that an SSLNG receiving terminal entails, addressing the issue of the BOG
management.
This work may be used as a starting ground of the final SSLNG project at Trafaria, as it points out specific
requirements of the BOG management system. Whether the project will move forward or not, this work is
intended to help the project engineers with guidelines and a dedicated study of the conditions of the terminal.
It is also intended to deliver the OZ Energia company information concerning what to expect from this SSLNG
terminal in the studied location, in particular regarding the energy behaviour of the whole system.
Regarding the tank, it might be interesting to simulate the tank design as a completely underground tank,
i.e., the dome totally covered by earth, to assess the effect of protecting the tank from the direct effect of
convection and irradiation, studying the respective energy efficiency improvement.
As future work regarding the re-liquefaction cycle, the calculations and methodology applied in this thesis
may be used to study equipment supplier solutions and respective costs, i.e., a realistic project budget. In order
to better understand the operational aspects of this SSLNG terminal, the present simulations should be
complemented by performing detailed dynamic simulations regarding the loading and unloading processes of
the tank, in order to perceive, conceive, and optimize the adequate solutions for the terminal. Necessarily, the
project must follow the natural engineering project spiral.
81
References [1] Direcção Geral de Energia e Geologia, “Energia em Portugal: 2014,” DGEG, Lisboa, 2016.
[2] J. Amador, “Produção e Consumo de Energia em Portugal: Factos Estilizados,” Boletim Económico, Banco de Portugal, p. 72, 2010.
[3] P. M. F. Rocha, Estratégia Nacional para a Energia em Portugal em 2020 - Eixo da Eficiência Energética (MSc thesis), Faculdade de Ciências Sociais e Humanas, 2013.
[4] Resolução do Conselho de Ministros n.º 29/2010, “Estratégia Nacional para a Energia,” Diário da República, 1.ª série — N.º 73, pp. 1289-1296, 15 April 2010.
[5] Oxford Institute for Energy Studies, “The Outlook for Natural Gas Demand in Europe,” OIES Papers, June 2014.
[6] International Energy Agency; OECD, “Energy Policies of IEA Countries - Portugal,” 2016 Review, pp. 15-17, 2016.
[7] S. Fankhausera, C. Gennaiolia and M. Collins, “The political economy of passing climate change legislation: Evidence from a survey,” Global Environmental Change, vol. 35, pp. 52-61, 14 August 2015.
[8] N. Rivers and M. Jaccard, “Combining top-down and bottom-up approaches to energy-economy modeling using discrete choice methods.,” Energy Journal, vol. 26 (1), pp. 83 - 106, 2005.
[9] M. Abdelaal and A. Hegab, “Combustion and emission characteristics of a natural gas-fueled diesel engine with EGR,” Energy Conversion and Management, vol. 64, pp. 301-312, 2012.
[10] BP, “BP Energy Outlook 2035 (Report),” BP, 2015.
[11] J. T. Jensen, “The LNG Revolution,” Energy Journal of the International Association for Energy Economics, vol. 21 (2), pp. 1-45, 2003.
[12] S. Kumar, H.-T. Kwon, K.-H. Choi, W. Lim, J. H. Cho and K. Tak, “LNG: An eco-friendly cryogenic fuel for sustainable development,” Applied Energy, vol. 88, no. 12, pp. 4264-4273, 21 June 2011.
[13] F. Burel, R. Taccani and N. Zuliani, “Improving sustainability of maritime transport through utilization of Liquefied Natural Gas (LNG) for propulsion,” Energy, vol. 57, pp. 412-420, 30 April 2013.
[14] International Maritime Organization, “Third IMO GHG Study 2014: Executive Summary and Final Report,” Micropress Printers, Suffolk, UK, 2015.
[15] S. Brynolf, E. Fridell and K. Andersson, “Environmental assessment of marine fuels: liquefied natural gas, liquefied biogas, methanol and bio-methanol,” Journal of Cleaner Production, vol. 74, pp. 86-95, 15 March 2014.
[16] E. Dodge, “Growth of LNG Fuel in Maritime Shipping,” 20 January 2014. [Online]. Available: http://www.theenergycollective.com/ed-dodge/329406/growth-lng-fuel-maritime-shipping.
[17] DNV, “Marpol 73/78 Annex VI - Regulations for the Prevention of Air Pollution from Ships: Technical and Operational implications (Technical Guide),” Det Norske Veritas, Høvik, Norway, 2009.
[18] Danish Maritime Authority, “North European LNG Infrastructure Project - a Feasibility Study for an LNG Filling Station Infrastructure and test of Recomendations (Report),” DMA, Copenhagen, 2012.
[19] M. Acciaro, “Real option analysis for environmental compliance: LNG and emission control areas,” Transportation Research Part D: Transport and Environment, vol. 28, pp. 41-50, 2013.
[20] Marintek, “Emissions Factors for CH4, NOx, particulates and black carbon for domestic shipping in Norway.,” Marintek Report, 2010.
[21] International Gas Union, “Life Cycle Assessment of LNG,” IGU, WCG Paris 2015, Paris, France, 2015.
[22] S. Rüster and A. Neumann, “Economics of the LNG Value Chain and Corporate Strategies: An Empirical Analysis of the Determinants of Vertical Integration,” in 26th USAEE International Conference, Ann Arbor, Michigan, U.S., 2006.
[23] British Chamber of Commerce, “LNG 50 - A Celebration Of The First Commercial Shipment Of LNG: A Brief Story of LNG,” BCCS, Singapore, 2014.
[24] J. P. Beale, “The Facts About Lng (document: RPT-06903-01),” CH-IV International, Millersville; Houston, 2006.
[25] A. Bernatik, P. Senovsky and M. Pitt, “LNG as a potential alternative fuel e Safety and security of storage facilities,” Journal of Loss Prevention in the Process Industries, vol. 24(1), pp. 19-24, 10 August 2010.
[26] H. S. Tira, J. Herreros, A. Tsolakis and M. L. Wyszynski, “Characteristics of LPG-diesel dual fuelled engine operated with rapeseed methyl ester and gas-to-liquid diesel fuels,” Energy, vol. 47, pp. 620-629, 2012.
[28] U.S. Department of Energy, “Liquefied Natural Gas Research - Report to Congress,” United States Department of Energy, Washington, DC 20585, 2012.
[29] M. M. Foss, “LNG Safety and Security,” University of Texas at Austin, Sugar Land, Texas, 2006.
[30] Energy Charter Secretariat, “LNG and Natural Gas Quality Standards,” Energy Charter Secretariat, Brussels, Belgium, 2004.
82
[31] Bristol, “The Wobbe Index and Natural Gas Interchangeability (Application Data Document 1660AD-5a),” Emerson, 2007.
[32] World Energy Council, “World Energy Perspective: Cost of Energy Technologies,” World Energy Council, London, 2013.
[33] United States Energy Information Administration, “Annual Energy Outlook 2015 with projections for 2040,” Office of Integrated and International Energy Analysis, U.S. Department of Energy, Washington DC, 2015.
[34] OPEC, “Annual Report 2014,” Organization of the Petroleum Exporting Countries, Austria, 2014.
[35] I. Tamura, T. Tanaka, T. Kagajo, S. Kuwabara, T. Yoshioka, T. Nagata, K. Kurahashi and H. Ishitani, “Life cycle CO2 analysis of LNG and city gas,” Applied Energy, vol. 68, pp. 301-319, 2001.
[36] N. Zhanga and N. Lior, “A novel near-zero CO2 emission thermal cycle with LNG cryogenic exergy utilization,” Energy, vol. 31, p. 1666–1679, 2006.
[37] A. Feller, D. Shunk and T. Callarman, “Value Chains Versus Supply Chains,” BP Trends, March 2006.
[38] C. v. Hirschhausen, A. Neumann, S. Ruester and D. Auerswald, “Advice on the Opportunity to Set up an Action Plan for the Promotion of LNG Chain Investments - Economic, Market, and Financial Point of View (Study for the European Commission, DG-TREN),” Dresden University of Technology, Dresden, 2008.
[39] S. Dorigoni, C. Graziano and F. Pontoni, “Can LNG increase competitiveness in the natural gas market?,” Energy Policy, vol. 38, no. 12, pp. 7653-7664, 5 August 2010.
[40] Đ. Dobrota, B. Lalić and I. Komar, “Problem of Boil - off in LNG Supply Chain,” Transactions On Maritime Science - Regular Papers, vol. 02, pp. 91-100, February 2013.
[41] S. Cornot-Gandolphe, “LNG Cost Reductions And Flexibility In LNG Trade Add To Security Of Gas Supply,” ENERGY PRICES & TAXES, 1st Quarter 2005 - International Energy Agency, pp. xxix - xxxvi, 1st quarter 2005.
[42] S. Kumar, H.-T. Kwon, K.-H. Choi, J. H. Cho, W. Lim and I. Moon, “Current status and future projections o fLNG demand and supplies: A global prospective,” Energy Policy, vol. 39, no. 7, pp. 4097-4104, 13 May 2011.
[43] Redes Energéticas Nacionais, “Technical Data 2016: National Natural Gas System (Technical Report),” Redes Energéticas Nacionais, Lisboa, 2016.
[44] REN, “RNTIAT – Existências e Reservas Operacionais (Period: 01-10-2015 to 30-09-2016) (Report),” RNTIAT, Redes Energéticas Nacionais, Lisboa, 2015.
[45] Marine Traffic, “Marine Traffic - Density Map - 2017,” 2018. [Online]. Available: https://www.marinetraffic.com/en/ais/home/centerx:3.0/centery:-2.6/zoom:2. [Accessed 04 March 2018].
[46] Porto de Lisboa, “Porto de Lisboa / Instalações Portuárias / Terminais de Carga,” 1 January 2016. [Online]. Available: http://www.portodelisboa.pt/portal/page/portal/PORTAL_PORTO_LISBOA/PORTO_LISBOA/INSTALACOES_PORTUARIAS/TERMINAIS_CARGA.
[47] Porto de Lisboa, “Publicação Estatística,” Terminais Portuários e Logística, 2016.
[48] J. Antunes, “O Shipping, o Ambiente e a Poluição Atmosférica da Costa Portuguesa,” Revista de Marinha N980, July/August 2014.
[49] Worley Parsons, “CCS Learning from the LNG Sector: A Report for the Global CCS Institute,” Global Carbon Capture and Storage Institute, Melbourne, 2013.
[51] Roche, “LNG receiving Terminal on the Saint-Laurent: Pre-Feasibility of the Jetty Component of the Project - LNG Carrier ships characteristics,” Gaz Metro – Enbridge – Gaz de France, Saint-Laurent, 2004.
[52] Instituto Hidrográfico da Marinha Portuguesa, “Instituto Hidrográfico da Marinha Portuguesa / Simoc,” 2 January 2016. [Online]. Available: http://www.hidrografico.pt/simoc.php.
[53] G. Lloyd, “Rules for Classification and Construction: Ship Technology - Seagoing Ships: 6) Liquefied Gas Carriers,” Germanischer Lloyd SE, Hamburg, 2008.
[54] DGPM, “National Ocean Strategy 2013-2020,” DGPM, Direcção-Geral de Política do Mar - Governo de Portugal, 2013.
[55] Município de Almada, “SIGMA - Sistema de Informação Geográfica do Município de Almada,” 2017. [Online]. Available: http://websig.smasalmada.pt/websicas/framesetup.asp. [Accessed May 2017].
[56] A.Takagi and K.Maruyama, “Advanced construction technologies for LNG in-ground storage tanks,” Tunnelling and Underground Space Technology, vol. 7, pp. 347-353, 1992.
[57] Magalog, “The general design of a LNG-terminal,” European Comission: Executive Agency for Competitiveness and Innovation, 2011.
[58] BSI, “BS EN 1473:2007 - Installation and equipment for liquefied natural gas - Design of onshore installations,” British Standard, 28 February 2007.
83
[59] REN Atlântico, “Ship to Shore Sines Port and LNG Jetty Data (4th Edition) (Technical Report),” REN Atlântico, Terminal de LNG, Sines, Portugal, 2013.
[60] SIGTTO, “Site Selection and Design for LNG Ports and Jetties - With views on Risk Limitation during Port navigation and cargo operations,” Worldwide Marine Technology, Wales, United Kingdom, 2000.
[61] H. Sugiyama, H. Mochizuki and E. Kanao, “Caracteristiques de la Conception et du Fonctionnement d’un Terminal de GNL de Sodeshi,” NKK Corporation; Shizuoka Gas Corporation; Shimizu LNG Corporation.
[62] P. Quist, “LNG Jetties as a standard product (MSc. Thesis),” Ballast Nedam Engineering, Delft University of Technology, Delft, 2001.
[63] C. Andrieu, “Small Scale LNG Import Terminal: Not as Simple as a Reduced One,” Tractebel Engineering, Houston, Texas, USA, 2013.
[64] M. D. Tusiani and G. Shearer, LNG: A Nontechnical Guide, Tulsa, Oklahoma: Pennwell, 2007.
[65] American Petroleum Institute, “Oil-and-Natural-Gas-Overview/Exploration-and-Production/Natural-Gas/LNG-Storage,” 28 December 2015. [Online]. Available: http://www.api.org/Oil-and-Natural-Gas-Overview/Exploration-and-Production/Natural-Gas/LNG-Storage.
[66] B. Long and B. Garner, Guide to Storage Tanks & Equipment, Bury St Edmunds and London UK: Professional Engineering Publishing, 2004.
[67] M. Tanabe and A. Miyake, “Approach enhancing inherent safety application in onshore LNG plant design,” Journal of Loss Prevention in the Process Industries, vol. 25, no. 5, pp. 809-819, 12 April 2012.
[68] A. Ezzarhouni, “Opportunities in Capex Saving For Onshore LNG Storage Tanks,” in 7th Annual LNG Tech Global Summit, Rotterdam, 2012.
[69] Center for Energy Economics, “Offshore LNG Receiving Terminals - Guide to Commercial Frameworks for LNG in North America (Technical Guide),” Center for Energy Economics; Bureau of Economic Geology; The University of Texas, Austin, 2006.
[70] EIA, “EIA / Today in Energy,” 27 April 2015. [Online]. Available: https://www.eia.gov/todayinenergy/detail.cfm?id=20972. [Accessed 2 January 2016].
[71] J. E. Fesmire and S. D. Augustynowicz, “Cryogenic Thermal Insulation Systems - 16th Thermal and Fluids Analysis Workshop,” Orlando, Florida, 2005.
[72] Voestalpine Grobblech GmbH, Nickel Steel Plates for LNG and LPG industry (Technical Catalog), Austria: Voestalpine, 2011.
[73] F. J. Powell and S. L. Matthews, Thermal Insulation: Materials and Systems, vol. ASTM Special Technical Publication 992, Dallas: ASTM, 1984.
[75] Pittsburgh Corning, Foamglas® High Load Bearing Cellular Glass Insulation (Technical Brochure), United States of America: Pittsburgh Corning, 2017.
[76] Perlite Institute, “Why Perlite Works - Genesis in Fire (Informative Brochure),” Perlite Institute, Harrisburg, 2009.
[77] Perlite Institute, “Perlite for Non-Evacuated Cryogenic and Low Temperature Service (Informative Brochure),” Perlite Institute, Harrisburg, 2013.
[78] CTS, Suspended Aluminum LNG Decks - Lightweight Alternative to Welden Nickel Decks (Technical Catalog), Netherlands: CTS Netherlands B.V., 2017.
[79] L. Lue, Chemical Thermodynamics, Leo Lue & Ventus Publishing ApS, 2009.
[80] IELE, “LNG Frequently Asked Questions (Report),” University of Houston Law Center - Institute for Energy, Law & Enterprise, Houston, 2005.
[81] R. Sedlaczek, “Diploma Thesis: Boil-Off In Large-and Small-Scale LNG Chains,” Faculty of Engineering Science and Technology - Department of Petroleum Engineering and Applied Geophysics, Trondheim, 2008.
[82] M. M. F. Hasan, A. M. Zheng and I. A. Karimi, “Minimizing Boil-Off Losses in Liquefied Natural Gas Transportation,” Industrial & Engineering Chemistry Research, vol. 48, no. 21, p. 9571–9580, 28 January 2009.
[83] Y. Li, Z. Li and W. Wang, “Simulating on rollover phenomenon in LNG storage tanks and determination of the rollover threshold,” Journal of Loss Prevention in the Process Industries, vol. 37, pp. 132-142, 25 July 2015.
[84] A. Acton and V. Meerbeke, “Rollover in LNG storage e an industry view.,” in LNG8 Conference, LA, USA, 1972.
[85] British Petrol and International Gas Union, “Guidebook to Gas Interchangeability and Gas Quality,” IGU, 2011.
[86] GL, “Study on Standards and Rules for Bunkering of Gas-Fuelled Ships - Final Report for the European Maritime Safety Agency,” Germanischer Lloyd, Lisbon, Portugal, 2012.
[87] C. Park, K. Song, S. Lee, Y. Lim and C. Han, “Retrofit design of a boil-off gas handling process in liquefied natural gas receiving terminals,” Energy, vol. 44, no. 1, pp. 69-78, 23 February 2012.
84
[88] E. Querol, B. Gonzalez-Regueral, J. García-Torrent and M. J. García-Martínez, “Boil off gas (BOG) management in Spanish liquid natural gas (LNG) terminals,” Applied Energy, vol. 87, no. 11, p. 3384–3392, 24 April 2010.
[89] IPCC, “IPCC Fourth Assessment Report: Climate Change 2007,” International Panel on Climate Change, 2007.
[90] S. Huang, J. Hartono and P. Shah, “BOG recovery from long jetties during LNG ship-loading,” in 15th International Conference & Exhibition on Liquefied Natural Gas, Barcelona, Spain, 2007.
[91] J. Y. Mak, S. Mokhatab, J. V. Valappil and D. A. Wood, Handbook of Liquefied Natural Gas, First ed., Oxford: Elsevier, 2014.
[92] H.-M. Chang, “A thermodynamic review of cryogenic refrigeration cycles for liquefaction of natural gas,” Cryogenics, vol. 72, no. 2, pp. 127-147, 5 October 2015.
[93] NASA, “Figure of Merit Characteristics Compared to Engineering Parameters,” National Aeronautics and Space Administration, Marshall Space Flight Center - MSFC, Alabama, 2010.
[94] Y. A. Çengel and M. A. Boles, Termodinâmica, Third ed., McGraw-Hill, 2001.
[95] A. Trigilio, A. Bouza and S. D. Scipio, “Modelling and Simulation of Natural Gas Liquefaction Process,” in Advances in Natural Gas Technology, Intech, 2012, pp. 213 - 234.
[96] J.-i. Yoon, H.-s. Lee, S.-t. Oh, S.-g. Lee and K.-h. Choi, “Characteristics of Cascade and C3MR Cycle on Natural Gas Liquefaction Process,” International Journal of Chemical and Molecular Engineering, vol. 3, p. No.11, 2009.
[97] Chart Energy & Chemicals, Brazed Aluminum Heat Exchangers, La Crosse, Wisconsin, USA: Chart.
[98] International Gas Union, “IGU World LNG Report,” IGU, Barcelona, Spain, 2017.
[99] T. B. He and Y. Ju, “Performance improvement of nitrogen expansion liquefaction process for small-scale LNG plant,” Cryogenics, vol. 61, pp. 111-119, 2014.
[100] A. J. Finn, G. Johnson and T. Tomlinson, “Developments in natural gas liquefaction,” Hydrocarbon Processing, vol. 78, no. 4, pp. 47-59, March 1999.
[101] T.-V. Nguyen, E. D. Rothuizen, W. B. Markussen and B. Elmegaard, “Thermodynamic comparison of three small-scale gas liquefaction systems,” Applied Thermal Engineering, vol. 128, pp. 712-724, 2018.
[102] H. Sayyaadi and M. Babaelahi, “Thermoeconomic optimization of a cryogenic refrigeration cycle for re-liquefaction of the LNG boil-off gas,” Internation Journal of Refrigeration, vol. 33, no. 6, pp. 1197-1207, 2010.
[103] S. Mokhatab, W. A.Poe and J. G. Speight, Handbook of Natural Gas Transmission and Processing, 1st ed., Oxford: Elsevier, 2006.
[104] B. Austbø and T. Gundersen, “Optimization of a single expander LNG process,” Energy Procedia, vol. 64, pp. 63-72, 2015.
[105] L. Castillo and C. Dorao, “Influence of the plot area in an economical analysis for selecting small scale LNG technologies for remote gas production,” Journal of Natural Gas Science and Engineering, vol. 2, no. 6, pp. 302-309, 2010.
[106] A. R. Jha, Cyogenic Technology and Applications, Oxford, UK: Butterworth-Heinemann (Elsevier), 2006.
[107] J. W. Moon, Y. P. Lee, Y. W. Jin, E. S. Hong and H. M. Chang, “Cryogenic Refrigeration Cycle for Re-Liquefaction of LNG Boil-Off Gas,” in Cryocoolers 14, Boulder, Colorado, 2007.
[108] T. He and Y. Ju, “Optimal synthesis of expansion liquefaction cycle for distributed-scale LNG (liquefied natural gas) plant,” Energy, vol. 88, pp. 268-280, 2015.
[109] Z. Yuan, M. Cui, Y. Xie and C. Li, “Design and analysis of a small-scale natural gas liquefaction process adopting single nitrogen expansion with carbon dioxide pre-cooling,” Applied Thermal Engineering, vol. 64, pp. 139-146, 2014.
[110] D.-H. Kwak, J.-H. Heo, S.-H. Park, S.-J. Seo and J.-K. Kim, “Energy-efficient design and optimization of boil-off gas (BOG) Re-liquefaction process for LNG-fuelled ship,” Energy, vol. 148, pp. 915-919, 2018.
[111] W. L. Luyben, Process Modelling, Simulation and Control for Chemical Engineers, McGraw-Hill International, 1996.
[112] C. W. d. Silva, Modeling and Control of Engineering Systems, CRC Press - Taylor & Francis Group, 2009.
[113] REN Atlântico, “Regras Técnicas de Uso do Terminal de Gás Natural Liquefeito de Sines (Technical Guide),” REN Atlântico, Terminal de GNL, S.A., 2013.
[114] Air Liquide, “Gas Encyclopedia,” Air Liquide, 2018. [Online]. Available: https://encyclopedia.airliquide.com/methane. [Accessed 12 February 2018].
[115] Agência Portuguesa do Ambiente, “SNIRH - Sistema Nacional de Informação de Recursos Hídricos,” 2017. [Online]. Available: http://snirh.apambiente.pt/index.php?idMain=2&idItem=1&objCover=920123704&objSite=920685506. [Accessed 12 Outubro 2017].
[116] Município de Almada, “Plano Municipal de Defessa da Floresta contra Incêndios (Report),” CMA, Almada, 2011.
[117] M. Badache, P. Eslami-Nejad, M. Ouzzane, Z. Aidoun and L. Lamarche, “A new modeling approach for improved ground temperature profile determination,” Renewable Energy, vol. 85, pp. 436-444, 2016.
85
[118] G. Florides and S. Kalogirou, “Annual Ground Temperature Measurements at Various Depths (technical paper),” Higher Technical Institute, Nicosia, Cyprus, 2005.
[119] Instituto Português do Mar e da Atmosfera, “Boletim meteorológico para a agricultura (Periodic Report),” IPMA, 2016/2017.
[120] American Petroleum Institute, “API RECOMMENDED PRACTICE 2350 - Overfill Protection for Storage Tanks in Petroleum Facilities,” American Petroleum Institute, Washington, D.C., 2005.
[121] ABS, “LNG Bunkering: Technical and Operational Advisory,” Houston, TX, USA, 2017.
[122] E. Adom, S. Z. Islam and X. Ji, “Modelling of Boil-Off Gas in LNG Tanks: A Case Study,” International Journal of Engineering and Technology, vol. 2, no. 4, pp. 292-296, 2010.
[123] A. Shitzer, “Wind-chill-equivalent temperatures: regarding the impact due to the variability of the environmental convective heat transfer coefficient,” International Journal of Biometeorology, vol. 50, pp. 224-232, 2006.
[124] P. Tikuisis and R. J. Osczevski, “Dynamic model of facial cooling,” Journal of Applied Meteorology, vol. 12, p. 1241–1246, 2002.
[125] M. J.Moran, H. N. Shapiro, D. D. Boettner and M. B. Bailey, Fundamentals of Engineering Thermodynamics, 7th ed., United States of America: John Wiley & Sons,Inc., 2011.
[127] A. Wordu and B. Peterside, “Estimation of Boil-off-Gas BOG from Refrigerated Vessels in Liquefied Natural Gas Plant,” International Journal of Engineering & Technology, vol. 3, no. 1, pp. 44-49, 2013.
[128] K-D.Gerdsmeyer and W.H.Isalski, “ON-BOARD RELIQUEFACTION FOR LNG SHIPS,” Tractebel Gas Engineering, 2005.
[129] A. Vorkapić, P. Kralj and D. Bernečić, “Ship systems for natural gas liquefaction,” Multidisciplinary Scientific Journal of Maritime Research, vol. 30, pp. 105-112, 2016.
[130] J. R. Gómez, M. R. Gómez, R. F. Garcia and A. D. M. Catoira, “On board LNG reliquefaction technology: a comparative study,” Polish Maritime Reasearch, vol. 21, pp. 77-88, 2014.
[131] Ministério da Economia, da Inovação e do Desenvolvimento, “Decreto-Lei n.º 23/2010,” Diário da República, 1ªSérie, no. 59, pp. 934-946, 25 Março 2010.
[132] “Directiva 2004/8/CE do Parlamento Europeu e do Conselho,” Jornal Oficial da União Europeia, no. Promoção da cogeração com base na procura de calor útil no mercado interno da energia, 11 Fevereiro 2004.
[133] International Panel for Climate Change, “IPCC Guidelines for National Greenhouse Gas Inventories, Vol.2: Stationary Combustion,” IPCC, 2006.
[134] Michael Baker Jr., Inc, “BASIS OF ESTIMATE: Interior Gas Utility, Fairbanks Gas Distribution, Advancement Project - Task 3: LNG Storage Tank Cost Analysis,” Michael Baker Jr., Inc., Anchorage, AK, 2013.
[135] S&P Global, “S&P Global Platts - Natural Gas - LNG,” 2018. [Online]. Available: https://www.platts.com/commodity/natural-gas/natural-gas-lng. [Accessed 20 April 2018].
[136] International Group of Liquefied Natural Gas Importers, “Rollover in LNG Storage Tanks,” GIIGNL, Neuilly-sur-Seine (France), 2015.
[137] Gas Infrastructure Europe, “GIE LNG Map - information by entry point (Informative Map),” GIE, 2018.
[138] REN - Redes Energéticas Nacionais, “Natural Gas National Transport Grid Map 2017 (Informative Map),” REN, 2017.
[139] Toho Gas Co., Ltd. and Mitsubishi Heavy Industries, Ltd., “Construction Of The World’s Largest Lng In-Ground Storage Tank (Project Report),” THG and MHI, Nagoya, Japan; Yokohama, Japan, 2000.
[140] ARUP, “Gas and LNG Storage | The Future of Modular LNG Tanks (Project Report),” Arup, 2017.
[141] H. Lun, F. Filippone, D. C. Roger and M. Poser, “Design and Construction Aspects of Post-Tensioned LNG Storage Tanks in Europe and Australasia,” in Concrete Industry Conference, New Zealand, 2006.
[142] Ishikawajima-Harima Heavy Industries Co., Ltd. and Kajima Corporation, “Design and Erection of Temporary Steel Roof for Under-Ground LNG Storage Tank,” in 13th International Conference and Exhibition on Liquefied Natural Gas, Korea, 2001.
[144] M. F. M Fahmy, H. I. Nabih and T. A. El-Rasoul, “Optimization and comparative analysis of LNG regasification processes,” Energy, vol. 91, pp. 371-385, 14 August 2015.
[145] International Gas Union, “IGU world LNG report - 1st Edition,” IGU, 2014.
[146] J. Mak, “Integration of LNG Regasification with Refinery and Power Generation”. Santa Ana, CA (US) Patent US 8316665 B2, 27 November 2012.
86
[147] H. Dong, L. Zhao, S. Zhang, A. Wang and J. Cai, “Using cryogenic exergy of liquefied natural gas for electricity production with the Stirling cycle,” Energy, vol. 63, pp. 10-18, 20 October 2013.
[148] J. Mak, “Configurations and Methods for Offshore LNG Regasification and Heating Value Conditioning”. Patent US 20100126187 A1, 2010.
[149] API Energy, “Liquefied Natural Gas (LNG) Operations: Consistent Methodology for Estimating the Greenhouse Gas Emissions,” American Petroleum Institute, Washington DC, 2015.
[150] B. Eisentrout, S. Wintercorn and B. Weber, “Study focuses on six LNG regassification systems,” LNG Journal, pp. 21-22, July/August 2006.
[151] D. Patel, J. Mak, D. Rivera and J. Angtuaco, “LNG Vaporizer Selection Based On Site Ambient Conditions,” International Gas Union (IGU); Gas Technology Institute (GTI); and International Institute of Refrigeration (IIR), 2013.
[152] T. Dendy and R. Nanda, “Utilization of Atmospheric Heat Exchangers in LNG Vaporization Processes: A comparison of systems and methods (Technical Report),” American Institute of Chemical Engineers (AIChE), USA, 2008.
[154] R. Agarwal, “LNG Regasification — Technology Evaluation And Cold Energy Utilisation (Technical Report),” Queensland University of Technology, Australia, 2013.
[155] Y. W. Chin, “Cycle analysis on LNG Boil-off Gas Reliquefaction Plant,” Journal of the Korea Institute of Applied Superconductivity and Cryogenics, vol. 8, pp. 34-38, 2006.
[156] V. S. Bisht, “Thermodynamic Analysis of Kapitza Cycle based on Nitrogen Liquefaction,” IOSR Journal of Engineering (IOSRJEN), vol. 4, no. 5, pp. 38-44, May 2014.
[157] IHI, “LNG Storage Solutions: A Key Consideration and Element in LNG Terminal Operation,” IHI, 2015.
[158] Chevron Energy Technology Company, “COMPOSITE CONCRETE CRYOGENIC TANK (C3T): A PRECAST CONCRETE ALTERNATIVE FOR LNG STORAGE (Technical Report),” CETC, 2016.
[162] SIGTTO, “LNG Transfer Arms and Manifold Draining, Purging and Disconnection Procedure,” Witherby Seamanship International, London , 2012.
[163] British Standards, “BS EN 1473:2007 - Installation and Equipment for Liquefied Natural Gas - Design of Onshore Installations,” Standards Policy and Strategy Committee, 2007.
[164] Ê. C. d. Costa, Refrigeração, São Paulo, Brasil: Edgard Blücher, 1986.
[165] T. M. Flynn, Cryogenic Engineering: Second Edition Revised and Expanded, New York: Marcel Dekker, 2005.
[166] A. Benito, “Accurate determination of LNG quality unloaded in Receiving Terminals: An Innovative Approach,” GERG Academic Network Event, Brussels, Belgium , 2009.
[167] Orçamentos 2009-2017, “Orçamentos e Orçamentação na Construção Civil,” 2014. [Online]. Available: http://orcamentos.eu/precos-de-betao-pronto/. [Accessed 21 September 2017].
[174] A. Shitzer, “Wind-chill-equivalent temperatures: regarding the impact due to the variability of the environmental convective heat transfer coefficient,” International Journal of Biometeorology, vol. 50, p. 224–232, 2005.
[175] J. M. Pfotenhauer, Refrigeration & Liquefaction (Technical Report), Madison: University of Wisconsin, 2010.
[176] G. Chicco and P. Mancarella, “Distributed multi-generation: a comprehensive view,” Renewable and Sustainable Energy Reviews, vol. 13, p. 535–551, 2007.
87
[177] A. Arteconi, D. Brandoni, D. Evangelista and F. Polonara, “Life cycle green house gas analysis of LNG as a heavy vehicle fuel in Europe,” Applied Energy , vol. 87, p. 2005–2013, 13 November 2009.
[178] X. Wang and M. J. Economides, “Purposefully built underground natural gas storage,” Journal of Natural Gas Science and Engineering, vol. 9, pp. 130 - 137, 11 June 2012.
[179] U. Lee, K. Kim and C. Han, “Design and optimization of multi-component organic Rankine cycle using liquefied natural gas cryogenic exergy,” Energy, vol. 77, p. 520–532, 12 September 2014.
[180] D. W. Plachta and M. C. Guzik, “Cryogenic Boil-Off Reduction System,” Cryogenics, vol. 60, pp. 62-67, 16 December 2013.
[181] Y. Li, X. Chena and M.-H. Cheinb, “Flexible and cost-effective optimization of BOG (boil-off gas) recondensation process at LNG receiving terminals,” Chemical Engineering Research and Design, vol. 90, no. 10, pp. 1500-1505, 25 January 2012.
88
ANNEXES
89
I. Gas Infrastructure: Europe’s LNG Map of 2018
Figure 65 – Europe’s LNG Map of 2018 [137]
90
II. Gas Infrastructure: Portugal
Figure 66 – Portuguese Gas Infrastructure [138]
91
III. Trafaria’s Terminal – Plant and General View
Figure 67 – Europe’s LNG Map of 2018
92
IV. Tank Projects and Examples – Determining the Dome Height and Characteristics
The design and methodology for the construction of LNG tanks varies largely with the techniques used by
each constructor, and are also disclosure-sensitive due to the industrial secrecy associated. Also, it is difficult to
find standard design procedures specifically for the design of LNG in-ground tanks, as this type of tanks is the
least common to build. As a method to overcome this difficulties, the available tank projects and drawings were
analysed in order to reach a conclusion especially regarding the ratios used for the design of the height of the
dome and radius of the spherical cap.
Below, it is possible to find the project drawings consulted and their dimensions: