Integrated NGL Recovery and LNG Liquefaction

Cairo University Faculty of Engineering Chemical Engineering Department Chemical Engineering Department

INTEGRATED NGL RECOVERY AND LNG LIQUEFACTION Graduation project technical report

2009/2010

Integrated NGL Recovery And LNG liquefaction

Authors

Name

Section

Ahmed Mohsen Khedr

1

15

Ahmed Hesham Rezk

1

21

Serag El Dine Magdi Mohamed

2

29

Abd El Rahman Magdi Ali

2

38

Ali Ahmed Sadek Nada

2

41

Ali Baiuomy Ali Mahmoud

3

1

Karim Mohamed Reda Abd El Hamid

3

8

Mohamed Osama Ahmed Kamal

3

18

Mohamed Hassan Mohamed Morsy

3

21

Mohanad Mohie El Dine Ismael

4

15

Youssef Alaa El Din Hassanein

4

40

B.N.

Project Supervisor Dr. Ahmed Soliman

Date Monday, February 22, 2010

i


Authors

Name

Section

Ahmed Mohsen Khedr

1

15

Ahmed Hesham Rezk

1

21

Serag El Dine Magdi Mohamed

2

29

Abd El Rahman Magdi Ali

2

38

Ali Ahmed Sadek Nada

2

41

Ali Baiuomy Ali Mahmoud

3

1

Karim Mohamed Reda Abd El Hamid

3

8

Mohamed Osama Ahmed Kamal

3

18

Mohamed Hassan Mohamed Morsy

3

21

Mohanad Mohie El Dine Ismael

4

15

Youssef Alaa El Din Hassanein

4

40

B.N.

Project Supervisor Dr. Ahmed Soliman

Date Monday, February 22, 2010

i


Table of Contents Pagee Pag 1. Introduction………………………………………………………………………….. 1 1.1. A brief history of LNG & NGL production ………….………………… ………….………………………….. ………..

1

1.2. Properties of raw natural gas……………………… gas………………………..…………………................. ..………………….................

3

1.2.1 Viscosity…………………………………………………………..……………….. 3 1.2.2 Gas hydrates…………………..… hydrates…………………..……..………………………… …..…………………………………………….. ………………….. 5 1.2.3 Calorific value of natural gas………………………… gas…………………………..…………….................... ..……………....................

5

1.3. Some properties of liquefied natural gas…………………… gas…………………………..……………... ……..……………...

6

1.4. Abundance of natural gas in egypt……………………… egypt……………………………...………………... ……...………………...

6

1.5. Safety & health aspects………………….…………………… aspects………………….……………………………………........ ………………........

7

1.5.1. Primary containment…………………...… containment…………………...……………………………… ……………………………..………. ..……….

8

1.5.2. Secondary containment……………… containment………………….……………………… ….………………………………………. ……………….

9

1.5.3. Safeguard systems……………………….……………… systems……………………….……………………………………….. ……………………….. 9 1.5.4. Separation distance……………… distance………………………………………… ……………………………………………….. …………………….. 9 1.6. Markets……………………….…………………………………………………..... 10 1.6.1. Global markets……………………..……………… markets……………………..…………………………………………… …………………………….. .. 10 1.6.2. Local markets………………… markets…………………….……………………… ….……………………………………………….. ……………………….. 13 1.6.3. Cost…………..……………...… Cost…………..……………...……………………………… ………………………………………………….. …………………….. 14

ii


Page 1.6.3.1. LNG value chain………………………… chain…………………………………………………… …………………………………….. ………….. 14 1.6.3.2. Linkage between markets……………..………..…………………… markets……………..………..……………………………… ………… 15 1.6.3.3. LNG prices……………..……………………………… prices……………..……………………………………………………….. ……………………….. 15 1.6.3.4. NGL prices…….………………….…………………… prices…….………………….…………………………………………….. ……………………….. 15 2. Natural gas processing processing from well till production of LNG………………….……... LNG………………….……... 16 3. Pre-treatment Pre-treatment of natural gas………………………………..……… gas………………………………..………………………. ………………. 17 3.1. Objectives of natural gas treating………………… treating…………………………………………… ………………………………. ……. 18 3.2. Sweetening………………………………………………………………………...... 18 3.3. Dehydration…………………… Dehydration………………………………………………… ………………………………………………..….. …………………..….. 20 3.3.1 Cryogenic dehydration……………..……… d ehydration……………..……………………….…………… ……………….…………………….. ……….. 20 3.3.2 Dehydration by absorption a bsorption processes……………..………………….…… processes……………..………………….………….. …….. 21 3.3.3 Adsorptive dehydration……………….……..………………...…… dehydration……………….……..………………...…………………. ……………. 22 3.4. Removal of mercury……………… mercury……………………..…..…………………… ……..…..…………………………………….. ……………….. 23 4. Available technologies technologies for LNG-NGL production……………..………………… production……………..………………….. .. 24 4.1. Traditional stand-alone gas plant upstream of liquefaction plant ……………... 24 4.2. Process schemes schemes for lng train in the downstream downstream of a liquefaction liquefaction plant..…….. 25 4.2.1 The most commonly utilized utilized lng technologies…………………………………... technologies…………………………………... 26 4.2.1.1 APCI propane pre-cooled mixed refrigerant refrigerant process……….………………... process……….………………... 26 sm

4.2.1.2 COP LNG

process……………………………………………… process………………… ………………………………..………… …..………… 27

iii


Page 4.3. Integrated NGL and LNG plants…………………………………….………… plants…………………………………….…………… … 28 4.3.1 Introduction….……………… Introduction….………………………………………… …………………………………………………….. ………………………….. 28 4.3.2 Available techniques………………..……… techniques………………..…………………………………… …………………………………….. ……….. 29 4.3.2.1 LNG facility with integrated NGL extraction technology for enhanced NGL recovery and product p roduct flexibility…………….................................... flexibility…………….................................... 29 FIRST CONFIGURATION ……………………… ………………………………………..…………… ………………..……………………….. …………..

30 SECOND CONFIGURATION ……………………………..………………………………. 32 THIRD CONFIGURATION ….……………………………………………………………. 34 4.3.2.2 Intermediate pressure LNG refluxed NGL recovery process……………….. process……………….. 36 4.3.2.3 Configurations and methods of integrated NGL recovery and LNG liquefaction……………………………………………………………………………... 38 4.3.2.4 Integrated Integrated NGL recovery and LNG liquefaction………………………..… liquefaction………………………..… 40 5. Storage & transportation…………………… transportation…………………………………………..……… ……………………..……………….. ……….. 41 5.1. Storage…….……………………...………………………………………………… 41 5.1.1. Methods of operation in tanks…………….…………… tanks…………….…………………………………….. ……………………….. 42 5.2. Transportation…….……………………………………………………………….. 42 6. Regasification...……………… Regasification...…………………………………………… ……………………………………………………… ………………………….. .. 44 7. Proposed technology………………………………………………… technology…………………………………………………………………. ………………. 45 7.1. Precooling of feed feed gas…………………………..……….……………… gas…………………………..……….…………………………. …………. 46 7.2. Separation of C2+ from feed gas………………………………………… gas………………………………………………….. ……….. 46 7.3. Liquefaction unit…………………………………...………………… unit…………………………………...………………………………. ……………. 47

iv


Page 7.4. C2 liquid recovery……………………………………………….……...………….. 48 7.5. C3 liquid recovery……………………………………………………………..….... 48 7.6. C4 liquid recovery………………………………………………………….…….… 48 7.7. Refrigeration cycles……………………………………………..……………….… 49 8. References ………………………………………………………………………………….... 50

v


List of Figures Page Figure 1: Viscosity of paraffin hydrocarbon gases at 1 atm as a function of molar mass……………...…………………………………………………………………….… 4 Figure 2: Viscosity ratio as a function of pseudoreduced temperature.……….……. 4 Figure 3: Natural gas & oil fields in Egypt ……………………...…………………… 7 Figure 4: World natural gas reserves by country as of January 2009…………....… 10 Figure 5: Country share of world LNG production 2008…….…………...……….... 11 Figure 6: LNG projects in Egypt……………………………………………………… 14 Figure 7: LNG value chain……………………………………………………….…… 14 Figure 8: LNG process....…………….…………………………………………..…....

16

Figure 9: Flow diagram of the amine process for gas sweetening................................ 19 Figure 10: Dehydration with a hydrate inhibitor and cooling at a high-pressure well………………………………………………………………………………………

21

Figure 11: Glycol dehydration…………….………………………………………...... 21 Figure 12: Hydrocarbon removal with adsorption and regeneration under pressure…………………………………………………………………………………

22

Figure 13: Block diagram for typical ngl extraction plant………………………..... 24 Figure 14: Flow diagram for APCI propane pre-cooled mixed refrigerant process. 26 Figure 15: Flow diagram for Phillips optimized cascade process............................... 27 Figure 16: Block diagram showing the integrated NGL and LNG process..…….… 28

vi


Page Figure 17: A flow diagram showing integrated heavies removal/NGL recovery system…………………………………………………………………………………….. 30 Figure 18: A simplified flow diagram of a cascaded refrigeration process for producing LNG……………...……………………………………………………...…… 31 Figure 19: A flow diagram showing integrated heavies removal/NGL recovery system connected to the LNG facility of fig 20...……………………………. 32 Figure 20: A simplified flow diagram of a cascaded refrigeration process for producing LNG……………...……………………………………………………...…… 33 Figure 21: A flow diagram showing integrated heavies removal/NGL recovery system…………………………….…………………………………………………..…... 34 Figure 22: A simplified flow diagram of a cascaded refrigeration process for producing LNG…………………………………………...………………………...…… 35 Figure 23: Simplified schematic flow diagram of an LNG facility that employs an intermediate pressure distillation column…………………………………………….

36

Figure 24: Simplified schematic flow diagram of an LNG facility that employs an intermediate pressure distillation column…………………………………………….

37

Figure 25: A schematic of one exemplary plant configuration using a twin column configuration for production of cold compressed overhead product and separation of C2 and C3……………………….…….............................................................. ............ 38 Figure 26: A more detailed schematic of an exemplary plant according to figure 25 with two cascade refrigeration cycles and one mixed refrigerant cycles for NGL recovery and LNG liquefaction……………………….………………………………… 39 Figure 27: A schematic flow diagram of an exemplary plant Configuration…..…… 40 Figure 28: LNG ship types……………………………………………………..……… 43 Figure 29: Cross-section of LNG tanker………………………………..…..………… 43 Figure 30: Simplified flow diagram of a typical LNG regasification system……...... 44

vii


Page Figure 31: Proposed technology process flow diagram…………………….…..……..… 45

List of Tables

Table 1: Physical properties of natural gas components at STP………………….....

3

Table 2: Calorific values of natural gas components at STP……………………….... 5 Table 3: LNG exporting countries and startup date of earliest liquefaction terminals………………………………………………………………………………..... 12 Table 4: LNG importing countries and startup date of earliest regasification terminals………………………………………………………………..……………….. 12

viii


Abstract

The combination of changing global markets for natural gas liquids (NGL) with the simultaneous increase in global demand for liquefied natural gas (LNG) has stimulated an interest in the integration of NGL recovery technology with LNG liquefaction technologies.

Historically, the removal of heavy hydrocarbons from the feed to LNG plants has been characterized as “gas conditioning” and achieved using one or more distillation columns. While some attempts to provide reflux to the distillation columns marginally enhanced NGL recovery, little emphasis was placed on maximizing NGL recovery as a product from the LNG process. As such, the integration of the two processes was not a priority.

Integrating NGL recovery technology within the LNG Process, results in a significant reduction in the specific power required to produce LNG, while maximizing NGL recovery. This corresponds to a production increase in both LNG and NGL for comparable compression schemes as compared to stand-alone LNG liquefaction and NGL extraction facilities. In addition, there are potential enhancements to the overall facility availability and project economics using the integrated concept.

ix


1. Introduction Due to clean burning characteristics and the ability to meet stringent environmental requirements, the demand for natural gas has increased considerably over the past few years. Projections reflect a continued increase for the next several years. However, it is a clean burning methane rich gas that is in demand as opposed to the typical raw gas that exists in nature, which often includes additional components such as heavier hydrocarbons and other impurities. The heavier hydrocarbons, once separated from natural gas, are referred to as Natural Gas Liquids (NGL).

Natural gas must be conditioned prior to liquefaction to remove undesired components. This conditioning normally takes place in separate or stand-alone facilities and typically includes the extraction of heavier hydrocarbons (NGL). The conditioned gas is then typically fed to pipelines for distribution. However, transportation to distant markets through gas pipelines is not always economically or technically feasible. As such, natural gas liquefaction has become a viable and widely accepted alternative.

Therefore, LNG is a natural alternative for gas pipelines when transporting natural gas to distant places and it should be emphasized that LNG is natural gas (mainly methane) that has been cooled to the point that it condenses to a liquid, which occurs at a temperature of approximately -256o F (-161o C) at atmospheric pressure. Liquefaction reduces the volume of gas by approximately 600 times.

Also NGL is a liquid hydrocarbon mixture which is gaseous at reservoir temperatures and pressures, but recoverable by condensation or absorption. It consists mainly of the higher hydrocarbons in natural gas (ethane and above).

1.1. A Brief History of LNG & NGL Production Natural gas liquefaction dates back to the 19th century when British chemist and physicist Michael Faraday experimented with liquefying different types of gases,

1


including natural gas. German engineer Karl Von Linde built the first practical compressor refrigeration machine in Munich in 1873. The first LNG plant was built in West Virginia in 1912 and began operation in 1917. The first commercial liquefaction plant was built in Cleveland, Ohio, in 1941. The LNG was stored in tanks at atmospheric pressure. The liquefaction of natural gas raised the possibility of its transportation to distant destinations. In January 1959, the world's first LNG tanker (The Methane Pioneer) containing 7,000 barrel equivalent aluminum prismatic tanks with balsa wood supports and insulation of plywood and urethane carried an LNG cargo from Lake Charles, Louisiana to Canvey Island, United Kingdom. This event demonstrated that large quantities of liquefied natural gas could be transported safely across the ocean.

Over the next 14 months, seven additional cargoes were delivered with only minor problems. Following the successful performance of The Methane Pioneer, the British Gas Council proceeded with plans to implement a commercial project to import LNG from Venezuela to Canvey Island.

After the concept was shown to work in the United Kingdom, additional liquefaction plants and import terminals were constructed in both the Atlantic and Pacific regions. Four marine terminals were built in the United States between 1971 and 1980. The LNG market in both Europe and Asia continued to grow rapidly from that point on.

On the other hand, the NGL industry started after the early 1960s in conjunction with liquefaction of natural gas, since before this date, it was considered as one of the steps of conditioning of natural gas before liquefaction, and gas produced was routinely flared as a useless by-product.

The start of the NGL industry was due to the awareness of the major oil producers in the world of energy conservation, and consequently at this point in time, most of the associated gas (gas produced in conjunction with crude oil) was being gathered with the heavies produced from natural gas and used for NGL and fuel-gas production.

2


1.2. Properties of Raw Natural Gas •

It is colorless and odorless.

•

It is lighter than air with a specific gravity of about 0.6-0.8. If leaks, it disperses upward and dissipates into the air quickly.

•

It is inflamed during a range of 5-15% by volume of gas in air. The self-ignition temperature of natural gas is 537-540 Celsius degrees.

•

As it is a clean fuel with cleaner burning nature, natural gas has lower environmental impact when compared with other types of fuel.

•

It is hydrocarbon component with methane as a major component. Table 1: Physical properties of natural gas components at STP

Compound

Molar mass, kg/kmol

Molar volume, m3/kmol

Density, Relative kg/m3 density, (air = 1)

Methane Ethane Propane n-Butane Isobutane n-Pentane Isopentane n-Hexane n-Heptane Nitrogen Carbon Dioxide Hydrogen Sulfide Helium

16.043 30.069 44.096 58.123 58.123 72.150* 72.150* 86.177* 100.203* 28.0134 44.0098 34.076

22.360 22.191 21.928 21.461 21.550 20.90* 21.06* 20.10* 18.3* 22.403 22.261 22.192

0.7175 1.355 2.011 2.708 2.697 3.452* 3.426* 4.29* 5.48* 1.2504 1.9770 1.5355

0.5549 1.048 1.555 2.094 2.086 2.670* 2.650* 3.315* 4.235* 0.9671 1.5290 1.1875

4.0026

22.426

0.17848

0.1380

* Compound in liquid state at STP

1.2.1 Viscosity For an ideal gas, the pressure and temperature dependence of viscosity is opposite to that of liquids; the viscosity of an ideal gas increases with increasing temperature and is independent of pressure. Actual hydrocarbon gases, however, deviate from ideal behavior and approach that of liquids; their viscosity increases with increasing

3


pressure, and decreases with increasing temperature at intermediate or high pressure. Figure 1 is employed for estimating the dynamic viscosity µ gas of natural gases composed primarily of hydrocarbons at atmospheric pressure. The presence of carbon dioxide, hydrogen sulfide, and nitrogen increases the viscosity. The viscosity µ g at any desired temperature and pressure can be obtained from Figure 2, where the

ratio µ g / µ ga is plotted as a function of the pseudoreduced temperature and pressure. The pseudocritical pressure and temperature are then used to determine the pseudoreduced conditions: ppr =

  

, ppc=∑yipci

Tpr =

 

, Tpc=∑yiTci

Where Tc and pc are the critical point conditions, and T and p are the values of the system, respectively.

Figure 1: Viscosity of paraffin hydrocarbon gases at 1 atm as a function of molar mass

Figure 2: Viscosity ratio as a function of pseudoreduced temperature

4


1.2.2 Gas Hydrates Gas hydrates are ice like solids composed of water and hydrocarbons. Hydrocarbons ranging from methane to cyclopentane are known to form hydrates. The formation of hydrates depends on pressure, temperature, molecular size, and concentration of the component. Generally, hydrates form at high pressure and low temperature, but they can occur as high as 30 0C and below 0.7 MPa. Hydrate formation can be predicted from empirical vapor – solid equilibrium ratios, empirical correlations, and laboratory measurements. To avoid the formation of gas hydrates in pipelines, the water vapor content of natural gas is commonly reduced by dehydration before transport. Lowering the water dew point to −5 to −8 0C in relation to the maximum transmission pressure is a common tipulation in gas specifications.

1.2.3 Calorific Value of Natural Gas H=∑yiHi, where Hi is the gross or net calorific value. Table 2: Calorific values of natural gas components at STP

Compound

Gross calorific value Net calorific value 3 3 MJ/m MJ/m

Methane Ethane Propane n-Butane Isobutane n-Pentane Isopentane n-Hexane n-Heptane Hydrogen sulfide

39.819 70.293 101.242 134.061 133.119 169.19* 167.53* 208.70* 265.22* 25.336

35.883 64.345 93.215 123.810 122.910 156.56* 154.99* 193.38* 245.99* 23.353

* Compound in liquid state at STP

5


1.3. Some Properties of Liquefied Natural Gas

•

LNG is predominantly methane (CH4) converted to liquid for ease of storage and transportation by cooling it to -260 0F or -160 0C. th

•

LNG takes up 1/600 the volume of natural gas in the gaseous form.

•

LNG density is approximately 26.5 lb/cu ft which is lighter than water (65 lb/cu ft)

•

LNG is an odorless, non-toxic and non-corrosive liquid, if spilled would not result in slick. Absent an ignition source LNG evaporates quickly and disperses leaving no residue.

•

No environmental cleanup needed for LNG spills on water or land

•

LNG offers an energy density comparable to petrol and diesel fuels simultaneously producing less pollution.

1.4. Abundance of Natural Gas in Egypt Most current exploration and production are sourced in the Nile Delta region and in the Western Desert. The Abu Madi, Badreddin and Abu Qir fields in the Nile Delta account for approximately one-half of Egypt's gas production, and are non-associated and mature fields. Other offshore developments include Port Fouad, South Temsah, Wakah, Rosetta, the Scarab/Saffron fields and the newly discovered Satis field found by BP and Eni in early 2008. In the Western Desert, the Obeiyed and Khalda fields are the most important natural gas areas, these fields have lower development and operating costs than fields in the Mediterranean region due to an expanding network of pipelines and processing plants that allow for quick transport upstream to Alexandria via a 180-mile pipeline.

6


Figure 3: Natural Gas & Oil Fields in Egypt

1.5. Safety & Health Aspects Liquefied natural gas may be viewed as a creation of the modern era, and as such, it has been subjected to more thorough scrutiny than traditional fuels such as gasoline and fuel oil. The hazards associated with LNG are that it is a low-temperature fluid, is flammable, and can create vapor clouds dense enough to cause asphyxiation. Because none of these is a problem when LNG is contained in properly designed storage tanks or piping and equipment, safety studies have generally focused on LNG spills. In LNG facilities, extensive safety systems exist to detect gas leaks, to detect and counter fires, and to detect smoke. Spill prevention and containment are implicit in the design of plant facilities, particularly of storage tanks because they contain the greatest quantity of LNG.

If an LNG spill is ignited soon after it occurs, a pool fire results. This fire is certainly a problem, but it is contained in a facility staffed and equipped to deal with such

7


emergencies. A greater concern is that the same spill may be given sufficient time to evaporate and form a vapor cloud that can travel for some distance before ignition.

A number of variables such as the nature of the surface underneath the spill, the wind velocity, and the presence of obstructions to the cloud act to shape and direct it. Mechanically, the cloud is formed as LNG boils from the surface of the spill. The evolving vapors are much colder than air and initially form a dense, low-lying cloud. As the cloud mixes with air and is warmed by its surroundings, it begins to rise. Wind serves to add a horizontal component to the cloud’s motion. As air mixes with the natural gas, the mixture becomes flammable (i.e., local compositions are between the lower and upper flammability limits of LNG). The flammability limits vary with LNG composition, particularly the proportion of propane. This cloud is then potentially hazardous to areas beyond the battery limits of the LNG facility.

A number of large-scale tests have demonstrated certain characteristics of LNG vapor cloud fires. These fires are deflagrations-rapid combustions in which the flame front that moves through the cloud is preceded by a weak, decoupled shock wave. An accompanying radiation hazard exists, but not the pressure damage of a shock wave that occurs when mixtures of other hydrocarbons and air are detonated.

The four requirements for safety – primary containment, secondary containment, safeguard systems and separation distance – apply across the LNG value chain, from production, liquefaction and shipping, to storage an d re-gasification.

1.5.1. Primary Containment The first and most important safety requirement for the industry is to contain LNG. This is accomplished by employing suitable materials for storage tanks and other equipment, and by appropriate engineering design throughout the value chain.

8


1.5.2. Secondary Containment This second layer of protection ensures that if leaks or spills occur, the LNG can be contained and isolated. For onshore installations dikes and berms surround liquid storage tanks to capture the product in case of a spill. In some installations a reinforced concrete tank surrounds the inner tank that normally holds the LNG. Secondary containment systems are designed to exceed the volume of the storage tank. As will be explained later, double and full containment systems for onshore storage tanks can eliminate the need for dikes.

1.5.3. Safeguard Systems In the third layer of protection, the goal is to minimize the release of LNG and mitigate the effects of a release. For this level of safety protection, LNG operations use systems such as gas, liquid and fire detection to rapidly identify any breach in containment and remote and automatic shut off systems to minimize leaks and spills in the case of failures. Operational systems (procedures, training and emergency response) also help prevent/mitigate hazards. Regular maintenance of these systems is vital to ensure their reliability.

1.5.4. Separation Distance Regulations have always required that LNG facilities be sited at a safe distance from adjacent industrial communities and other public areas. Also, safety zones are established around LNG ships. The safe distances or exclusion zones are based on LNG vapour dispersion data, and thermal radiation contours and other considerations as specified in regulations.

9


1.6. Markets

1.6.1. Global Markets Historically, world natural gas reserves have generally trended upward. As of January 1, 2009, proved world natural gas reserves were estimated at 6,254 trillion cubic feet, 69 trillion cubic feet higher than the estimate of 6,186 trillion cubic feet for 2008.

Algeria Saudi Arabia 4% Venezuela 3% 3% Russia 27%

Qatar 14% Egypt 1%

Others 22%

Iran 16%

United Arab Emirates 3%

Nigeria United States 3% 4%

Figure 4: World Natural Gas Reserves by Country as of January 2009

The share of LNG in global gas production is increasing. In recent years the share of LNG in worldwide gas production has grown to 8%, whereas it was still 6% in 2004.

10


Figure 5: Country Share of World LNG Production 2008

Global LNG market is characterized by excess demand relative to available supplies. This situation is only expected to aggravate as several countries have made high investments in LNG trains in the past and now want to wait before increasing investment, or they have put a stop on export development as domestic demand is increasing.

The global LNG market is characterised by an overcapacity of regasification compared to liquefaction. There are 26 existing export, or liquefaction, marine terminals, located on or off shore, in 15 countries. In contrast, there are 60 existing import, or regasification, marine terminals, on or off shore, spread across 18 different countries. In addition to these existing terminals, there are approximately 65 liquefaction marine terminal projects and approximately 181 regasification terminal projects that have been either proposed or are under construction all around the world. It is not expected that all of the proposed terminals will be constructed.

11


Table 3: LNG Exporting Countries and Startup date of earliest Liquefaction terminals

Countries that Export LNG

Startup date of earliest liquefaction terminal

Algeria

1971

Australia

1989

Nigeria

1999

Brunei

1972

Norway

2007

Equatorial Guinea

2007

Oman

2000

Egypt

2004

Qatar

1997

Indonesia

1977

Trinidad and Tobago

1999

Libya

1970

United Arab Emirates

1977

Malaysia

1983

United States of America

1969

Table 4: LNG Importing Countries and Startup date of earliest Regasification terminals

Countries that Import LNG

Startup date of earliest regasification terminal

Belgium

1987

China

2006

Portugal

2003

Dominican Republic

2003

Puerto Rico

2000

France

1972

South Korea

1986

Greece

2000

Spain

1969

India

2004

Taiwan

1990

Italy

1971

Turkey

1992

Japan

1969

United Kingdom

2005

Mexico

2006

United States of America

1971

12


1.6.2. Local Markets Egypt's proven natural gas reserves have reached 76 trillion cubic feet. Gas exports during 2008/09 have contributed some $3.3 billion. Thirty per cent of gas production is exported while the remaining 70 per cent is consumed domestically. Electricity production, industry and petrochemicals are the three sectors that receive the lion's share of almost 85 % of the locally consumed gas. Currently, there are two LNG projects in Egypt at an advanced stage: i. Idku (Egyptian LNG, ELNG): Consists of two trains with a capacity of 3.6 mtpa each. The first train was first operated by the third quarter 2005 with exports to Gaz de France under a 20-year contract signed in 2002, whereas the second train is has came on stream at 2006 supplied LNG to Lake Charles, Louisiana, US. The project is tied into natural gas reserves from BG’s Simian/Sienna offshore fields. A third train may be built by The Malaysian Company Petronas is partner in the project, after buying Edison’s stake. ii. Damietta (SEGAS LNG): The other project, Damietta, is built by the Spanish power group, Union Fenosa. In 2002, Eni became involved in the project after it purchased a 50% stake in Union Fenosa’s gas business. The $1.3 billion LNG plant was completed at end of 2004. Initial capacity of the first train is 4.8 mtpa. Unlike other LNG projects, this one is not tied to upstream gas development Instead, Union Fenosa has signed a 25-year gas supply contract with EGPC. Union Fenosa will take 60% (2.9 mtpa) of SEGAS LNG.

13


Figure 6: LNG Projects in Egypt

1.6.3. Cost LNG is one of the fastest-growing energy markets. But although there has been movement towards a global reference price, the costs involved along the value chain suggest the commoditization achieved in the oil sector is unlikely.

1.6.3.1. LNG value Chain The LNG value chain represents $7 to $14 billion dollars of investment from start to finish.

Exploration & Production

I

Liquefaction

Transport

Regasification

Sales

Figure 7: LNG Value Chain

14


Investment costs within the five stages vary significantly with the largest share required by the liquefaction project. Exploration and production account for 15-20% of the total costs of the LNG value chain; liquefaction for 30-45%; shipping for 1030%; and regasification for 15-25%.

1.6.3.2. Linkage between markets Two indicators suggest the market is moving towards a global reference price: Geographical connections: since 1970, LNG trading has evolved regionally, in the

Atlantic and Pacific basins, with hardly any interaction between the two markets. But recently, links between the regions have grown as a result of variations in demand and supply.

Oil-price indexation: the price of imported gas, whether by pipeline or as LNG, has

traditionally been linked to competing fuels in importing countries. For example, contracts in Japan are indexed to the Japanese Crude Cocktail (JCC) and in Europe to fuel oil and gasoil, which are the principal substitute fuels for gas main use in those markets (power and heat generation).

1.6.3.3. LNG Prices The average global price of LNG at 2009 was $11/MMBTU.

1.6.3.4. NGL Prices Global NGL components average prices at 2009: Propane: $53 per barrel Butane: $77.63 per barrel Pentane: $101.95 per barrel • • •

15


2. Natural gas processing from well till production of LNG

Figure 8: LNG process

A typical LNG process, where natural gas is first extracted and transported to processing plants, then purified by removing condensates such as water, oil, mud, as well as other gases like CO2 and H2S and sometimes mercury by amine treatment. Afterwards, gas heavies are removed, before it is cooled down in stages until it is liquefied. LNG is finally stored in storage tanks and can be loaded and shipped to its end-user destination, where finally regasification of liquefied gas occurs before usage.

In the next sections of this document, we will handle the technical information about the liquefaction plant with large emphasis on the integration of natural gas liquids recovery and liquefaction parts of the process. However, brief information will be given on the rest of the process, along with some information about LNG storage, tankers, and regasification. Then a technology for our project will be proposed in the final section.

16


3. Pre-treatment of Natural Gas Natural gas is produced at the well site in compositions of considerable variety; therefore, natural gas is essentially pretreated before liquefaction to avoid varying problems during production and transportation, such as the following:

Water: Condensed water forms solid hydrates with hydrocarbons or hydrogen sulfide, or in

addition leads to liquid slugs in pipelines and to corrosion.

Hydrogen Sulfide: Hydrogen sulfide together with free water can cause corrosion,

particularly stress corrosion and hydrogen-induced cracking. Removal of hydrogen sulfide is performed almost exclusively in centralized treatment plants.

Carbon Dioxide: Carbon dioxide together with free water causes pitting corrosion in carbon

and low-alloy steels. Some natural gases that contain significant amounts of CO 2 must be treated to increase the methane concentration prior to sales.

Sulfur: Gases containing hydrogen sulfide can also contain elementary sulfur as vapor.

Some gas fields, primarily in Canada, Germany, and the United States, contain such high quantities that the sulfur, depending on pressure, temperature, and gas composition, can precipitate and plug the production pipe, which then becomes blocked. Furthermore, elemental sulfur and free water are corrosive.

Mercury: Natural gas can contain mercury in concentrations up to several milligrams per

cubic meter, the bulk of which exists in elemental form. Separated liquid mercury causes mercury-induced corrosion in pipes and fittings, corrosion damage to aluminum heat exchangers in cryogenic plants, and damage to measuring and control valves containing nonferrous metals by amalgam formation. Mercury must also be removed because of its toxicity.

17


3.1.

Objectives of Natural Gas Treating

Two objectives must be met in treating natural gas: •

Adjustment to the required quality standards

•

Recovery of by products

The main objective worldwide is production of a sales gas of pipeline standard. In this respect, both the extent of removal of undesirable components and the range of conditioning measures are predetermined.

Natural gas treating can take place both directly at the well and in centralized plants. Treating at the well is always necessary when the gas cannot be transported to a processing plant by pipeline without hazard. To avoid corrosion, sour gas is often dehydrated at the well so that free water can no longer condense in the pipeline. The recovery of sulfur and the separation of nitrogen, carbon dioxide, or helium are carried out in centralized plants, to which streams of different wells are fed. The same holds true for liquefaction of natural gas, recovery of LPG, and removal of higher hydrocarbons.

3.2.

Sweetening

Many natural gases contain hydrogen sulfide (H2S) in concentration ranging from barely detectable quantities to over 30 mole percent. Gases containing H2S or CO2 are classified as sour, and gases free from H 2S and CO2 are called sweet. With increasing demands to natural gas, natural gases containing H2S are also being tapped for utilization after purification. Natural gas that is transported to the fuel market must meet legal requirements, which specify a maximum H2S content less than 4 ppm in the gas.

18


Many chemical processes are available for sweetening natural gas. At present, the amine process, is the most widely used method for H2S removal. The process is summarized in one reaction: 2 RNH2 + H2S → (RNH3)2S Where: R = mono, di, or tri-ethanol, N = nitrogen, H = hydrogen, S = sulfur.

Figure 9: Flow diagram of the amine process for gas sweetening

The recovered hydrogen sulfide gas stream may be: (1) vented, (2) flared in waste gas flares or modern smokeless flares, (3) incinerated, or (4) utilized for the production of elemental sulfur or sulfuric acid.

If the recovered H2S gas stream is not to be utilized as a feedstock for commercial applications, the gas is usually passed to a tail gas incinerator in which the H 2S is oxidized to SO2 and is then passed to the atmosphere out a stack.

19


3.3.

Dehydration

Dehydration of natural gas is the removal of the water that is associated with natural gases in vapor form.

The natural gas industry has recognized that dehydration is necessary to ensure smooth operation of gas transmission lines. Dehydration prevents the formation of gas hydrates and reduces corrosion. Unless gases are dehydrated, liquid water may condense in pipelines and accumulate at low points along the line, reducing its flow capacity. Several methods have been developed to dehydrate gases on an industrial scale.

The three major methods of dehydration are: 1. Direct cooling (Cryogenic) 2. Absorption. 3. Adsorption.

3.3.1 Cryogenic Dehydration To decrease the higher hydrocarbon content in addition to maintaining a specific water dew point, cryogenic dehydration of natural gas is often employed.

The wet gas is cooled until the components to be removed precipitate by condensation or formation of hydrates. Methanol, glycol, or a paraffin solvent is often also injected. The reduction in temperature can be achieved by Joule–Thomson expansion. This route is employed particularly in the first phase of production in high-pressure wells. When the production pressure is close to that of the transportation system, external cryogenic units are used.

20


a) High pressure separator (free water knockout); b) Heater; c) Air cooler; d) Separator; e) Joule – Thomson valve; f ) Gas-gas heat exchanger; g) External cooling system for low-pressure wells Figure 10: Dehydration with a hydrate inhibitor and cooling at a high-pressure well

3.3.2 Dehydration by Absorption Processes Standardized dehydration plants using glycol absorption are employed most widely. Triethylene glycol (TEG) is used in preference to other glycols (mono- and diethylene glycols) because of its high absorption capacity for water vapor, its low vapor pressure (small losses from evaporation), and its high thermal stability. This type of dehydration plant is shown in Figure 11.

a) Well head; b) Corrosion inhibitor – sulfur solvent injection pump; c) High-pressure separator (free water knockout); d) Heater; e) Flow control valve; f ) Air cooler; g ) Separator; h) Glycol absorber; i) Demister; j) Glycol – gas heat exchanger; k) Glycol pump; l) Glycol reboiler; m) Hig h-concentration stripper; n) Glycol storage tank; o) Glycol stripper; p) Water – solvent stripper; q ) Glycol filter; r) Produced liquids storage tank; s) Flare Figure 11: Glycol dehydration

21


3.3.3 Adsorptive Dehydration In adsorptive dehydration the gas is brought in contact with molecular sieves, silica gel, or Sorbead (i.e., Na2O containing SiO2). Plants with only two adsorbers, working alternately, are possible. Dew points < −70°C are attainable with adsorption plants. This is particularly necessary for cryogenic plants and LNG plants, where traces of water and carbon dioxide can lead to blockage by ice formation.

For regeneration, 5% purge gas is drawn from the main gas flow and fed through the laden adsorber at plant pressure and 200–330°C. Removed water vapor from purging of the fixed bed is condensed so that the purge gas, which is at plant pressure, can be recycled. Regeneration by depressurization is seldom employed in natural gas treating.

a) – c) Adsorbers; d) Heater; e) Cooler; f ) Chiller; g) Separator; h) Phase separator Figure 12: Hydrocarbon removal with adsorption and regeneration under pressure

22


Under the normal requirements of natural gas treating dehydration units of this type are economically less attractive than glycol and cryogenic dehydration plants described above. However, they are nevertheless employed when, in addition to simply removing water, adjustment to a specific hydrocarbon dew point is required, removal of hydrogen sulfide or carbon dioxide is necessary, or an extremely low dew point is required.

3.4.

Removal of Mercury

Natural gas from reservoirs often contains mercury in vapor and/or aerosol form. Mercury has not resulted in any problems in production from sour gas fields. To avoid health hazards during treatment and use, the mercury content is lowered in separate mercury-removal plants from 5 mg/m3 to < 10 µg/m3.

A considerable portion of the mercury has often already been removed by lowtemperature separation (LTS) in the dehydration unit at the well. Mercury levels of < 5 µg/m3 are attained in downstream chemisorption fixed-bed reactors with, for example, sulfur-impregnated activated carbon. Condensable components, such as water or hydrocarbons, reduce the loading ability for mercury or even deactivate the adsorbent. The reactors are not regenerated; rather, the laden adsorbent is fed to an external treatment plant. Regenerative amalgamation processes are currently being tested.

23


4. Available Technologies for LNG-NGL Production

4.1. Traditional Stand-Alone Gas Plant Upstream of Liquefaction Plant A number of NGL recovery processes have been developed for natural gas and other gas streams. Among various NGL recovery processes, the cryogenic expansion process has become the preferred process for deep hydrocarbon liquid recovery from natural gas streams.

Figure 13: Block diagram for typical NGL extraction plant

In the conventional turbo-expander process, feed gas at elevated pressure is pretreated for removal of acid gases, water, mercury and other contaminants to produce a purified gas suitable for cryogenic temperatures. The treated gas is typically partially condensed utilizing heat exchange with other process streams and/or external propane refrigeration, depending upon the gas composition. The resulting condensed liquid, containing the less volatile components, is then separated and fed to a medium or lowpressure fractionation column for recovery of the heavy hydrocarbon components. The remaining non-condensed vapor, containing the more volatile components, is expanded to the lower pressure of the column using a turbo expander, resulting in further cooling and additional liquid condensation. With the expander discharge 24


pressure essentially the same as the column pressure, the resulting two-phase stream is fed to the top section of the fractionation column. The cold liquid portion acts as reflux, enhancing recovery of heavier hydrocarbon components. The vapor portion combines with the gas in the overhead of the column. The combined gas exits the column overhead as a residue gas. After recovery of available refrigeration, the residue gas is then recompressed to a higher pressure, suitable for pipeline delivery or for LNG liquefaction.

4.2. Process Schemes for LNG Train in the Downstream of a Liquefaction Plant Because LNG liquefaction requires a significant amount of refrigeration energy, the refrigeration system(s) represent a large portion of a LNG facility. A number of liquefaction processes have been developed with the differences mainly residing on the type of refrigeration cycles employed. The technology selection of LNG process will mainly based on: •

Technical consideration includes process and equipment experience,

reliability, process efficiency, site conditions and environmental impact. •

Economic issues include capital cost, operating cost and lifecycle costing.

•

Technical risks associated with a process relate to the track record of the

process in operation. •

Other selections include deciding heating and cooling medium, compressors

and drivers and equipments.

25


4.2.1 The Most Commonly Utilized LNG Technologies: 4.2.1.1

APCI Propane pre-cooled mixed refrigerant process

APCI accounts for about 81% of the world’s base load LNG production capacity. This mixed refrigerant process provides an efficient process utilizing a multicomponent mixture of hydrocarbons typically comprising propane, ethane, methane, and optionally other light components in one cycle. A large spiral wound exchanger is utilized for the majority of heat transfer area. Two main refrigerant cycles are used in this process: i.

Propane Precooling cycle: It uses propane at four different pressure level and cool process gas to -40 0C & also partially liquefies the MR.

ii.

Mixed refrigerant liquefaction and sub-cooling cycle: It is used in main cryogenic exchanger(MCHE) & the partially liquefied refrigerant is separated into vapour and liquid and sub-cool the process stream form -35 0C to -160 0C.

Figure 14: Flow diagram for APCI Propane pre-cooled mixed refrigerant

26


4.2.1.2

CoP LNGSM Process

This process, formerly known as the Phillips Optimized Cascade LNG Process, utilizes essentially pure refrigerant components in an integrated cascade arrangement. The process offers high efficiency and reliability. Also it easily shifted from LNG recovery to LPG recovery to ethane recovery. Brazed aluminum exchangers are largely used for heat transfer area, providing for a robust facility that is easy to operate and maintain. Refrigerants typically employed are propane, ethylene and methane.

Figure 15: Flow diagram for Phillips Optimized Cascade Process

27


4.3.

Integrated NGL and LNG Plants

4.3.1 Introduction A block diagram for an integrated LNG and NGL process is presented in the below figure in which its the simplest embodiment of NGL integration, where the Heavies Removal Column is not refluxed other than with condensed liquids contained within the column feed.

Figure 16: Block diagram showing the integrated NGL and LNG process

NGL recovery integration not only reduces capital investment through reutilizing essentially all equipment in the NGL facility for LNG production, but also improves overall thermodynamic efficiency. There are significant advantages in the following aspects: •

The overall integrated process reduces combined capital and operating costs.

•

The integrated process reduces combined CO2 and NOX emissions by improving the thermodynamic efficiency of the overall process.

•

Higher recovery of propane (and ethane) is achievable.

•

Most NGL process equipment is already utilized in LNG liquefaction plants.

28


4.3.2 Available Techniques Some techniques for the integration between NGL and LNG are available, however, we focused on two main techniques that are currently established in industry, one owned by ConocoPhillips Company and the other by Flour Technologies Corporation, and we will simply describe each technology with its new modifications.

4.3.2.1

LNG Facility with Integrated NGL Extraction Technology for Enhanced NGL Recovery and Product Flexibility 1

A process for efficiently operating a natural gas liquefaction system with integrated heavies removal/natural gas liquids recovery to produce liquefied natural gas (LNG) and natural gas liquids (NGL) products varying characteristics, such as, for example higher heating value or propane content. Resulting LNG and NGL products are capable of meeting the significantly different specifications of two or more markets.

A liquefaction methodology that is preferably applicable to one or more of the following embodiments of the present technology employs three refrigeration cycles in which the first 2 cycles use propane and ethane respectively, while an open methane cycle is employed for the final refrigeration cycle wherein a pressurized LNG-bearing stream is flashed and the flash vapors are subsequently employed as cooling agents, recompressed, cooled, combined with the processed natural gas feed stream, and liquefied, thereby producing the pressurized LNGbearing stream.

Next, some configurations for operational flexibility and different products requirements are shown.

1

Patent owned by ConocoPhilips Company under a publication number of US 2007/0012072

29


•

First Configuration

In the following figures we illustrate an embodiment of the LNG facility that can be operated to maximize C2+ recovery in the final NGL product. Figure 17 illustrates one embodiment of the heavies removal/LNG recovery system of the present technology. Lines H, D, B, F, E, and G show how the liquefaction section shown in figure 18 is integrated with the heavies removal/NGL recovery system.

Figure 17: A flow diagram showing integrated heavies removal/NGL recovery system

30


Figure 18: A simplified flow diagram of a cascaded refrigeration process for producing LNG

31


•

Second Configuration

In the following figures we illustrate one embodiment of the LNG facility which can be operated in such a way to maximize propane and heavier component recovery in the NGL product.

Figure 19 illustrates one embodiment of heavies removal/NGL recovery system. Lines A, B, and C show how the heavies removal/NGL recovery system is integrated into the LNG facility.

Figure 19: A flow diagram showing integrated heavies removal/NGL recovery system connected to the LNG facility of Fig 20

32


Figure 20 illustrates the system in which how we can cool natural gas to its liquefaction temperature via three mechanical refrigeration stages in combination with an expansion type cooling section.


33


•

Third Configuration

In the following figures we illustrate another embodiment of the LNG facility capable of operating to maximize C5+ recovery in the NGL product.

Figure 21 it illustrates one embodiment of the heavies removal/LNG recovery system of the present technology. Lines D, B, F, E, and G show how the liquefaction section shown in figure 22 is integrated with the heavies removal/NGL recovery system.

Figure 21: A flow diagram showing integrated heavies removal/NGL recovery system

34



35


4.3.2.2

Intermediate Pressure LNG Refluxed NGL Recovery Process2

Liquefied natural gas (LNG) facility employing an intermediate pressure distillation column for recovery of ethane and heavier components from the processed natural gas stream in a way that increases operational stability and minimizes capital and operating costs. In the following figure a simplified schematic flow diagram of one embodiment of an LNG facility that employs an intermediate pressure distillation column, particularly illustrating the use of heated side draw and a turbo expander that drives a compressor downstream of the column.

Figure 23: Simplified schematic flow diagram of an LNG facility that employs an intermediate ressure distillation column 2

Patent owned by ConocoPhilips Company under a publication number of US 2008/0098770

36


In the following figure another simplified schematic flow diagram of one embodiment of an LNG facility that employs an intermediate pressure distillation column, particularly illustrating the use of a methane rich reflux and a turbo expander that drives a compressor upstream of the column.

Figure 24: Simplified schematic flow diagram of an LNG facility that employs an intermediate pressure distillation column.

37


4.3.2.3

Configurations and Methods of Integrated NGL Recovery and LNG Liquefaction 3

Contemplated plants include a NGL recovery portion and a LNG liquefaction portion, wherein the NGL recovery portion provides a low temperatures and high pressure overhead product directly to the LNG liquefaction portion. Feed gas cooling and condensation are most preferably performed using 3 refrigeration cycles that employ refrigerants other than the demethanizer/absorber overhead product. Thus, cold demethanizer/absorber overhead product is compressed with the turbo expander and delivered to a liquefaction portion at significantly lower temperature and higher pressure without net compression energy expenditure. The present technology is directed to configurations, plants, and methods for natural gas processing and liquefaction in which a cold separator overhead product is directly compressed in a compressor that is driven by a feed gas vapor expander, and wherein the compressed cold separator overhead product is then

Figure 25: A schematic of one exemplary plant configuration using a twin column configuration for production of cold compressed overhead product and separation of C2 and C3. 3

Patent owned by Fluor Technologies Corporation under a publication number of US 2007/0157663

38


liquefied in a liquefaction unit. Most advantageously, such plants integrate NGL processing and LNG liquefaction in an efficient, cost effective, and technically simple manner, specifically when feed gas pressure is higher than 800 psi. It should be appreciated that contemplated configuration and methods allow for an integrated NGL recovery and LNG liquefaction process in which 99% propane and up to 85% ethane can be recovered from a natural gas feed.

Figure 26: A more detailed schematic of an exemplary plant according to figure 2.1-1 with two cascade refrigeration cycles and one mixed refrigerant cycles for NGL recovery and LNG liquefaction.

39


4.3.2.4

Integrated NGL Recovery and LNG Liquefaction 4

Contemplated plants include a refluxed absorber is operated at a higher pressure than the distillation column to thereby produce a cryogenic pressurized lean gas. The lean gas is further compressed to a pressure suitable for liquefaction using energy from feed gas vapor expansion. Desired separation of C2 products is ensured by temperature control of the absorber and distillation column using flow ratios of various streams within the plant, and by dividing the separation process into two portions at different pressures.

Figure 27: A schematic flow diagram of an exemplary plant configuration

4

Patent owned by Fluor Technologies Corporation under a publication number of US 200 8/0271480

40


The present technology is directed to configurations and methods of NGL recovery when coupled to an LNG liquefaction process, in which recovery of C2 components can be adjusted using flow ratios of selected process streams. Most preferably, the absorber in such configurations and methods is operated at significantly higher pressure than the distillation column provide a cryogenic pressurized gas, while the absorber and distillation column temperatures are adjusted to such that desired quantities of C2 and C3+ products are recovered in the NGL. Cryogenic absorber overhead product is then compressed to a pressure suitable for liquefaction using energy derived from expansion of a vapor portion of the feed gas which is expected to have pressure higher than 800 psi.

5. Storage & Transportation 5.1.

Storage

Once the gas becomes liquid, it flows into large insulated storage tanks. This storage tank is a specialized type of storage tank which can keep the LNG at low temperature of -162°C. The temperature within the tank will remain constant if the pressure is kept constant by allowing the boil off gas to escape from the tank. This is known as autorefrigeration.

LNG storage tanks have double containers, where the inner contains LNG and the outer container contains insulation materials. The most common tank type is the full containment tank. Tanks are roughly 180 feet high and 250 feet in diameter.

Cylindrical tanks with formed heads are the most widely used tanks for storing LNG. Also NGL are stored in the same type of tanks, but when in gaseous form, pressure vessels, most commonly spherical tanks are the most appropriate. As the requirement came to store ever larger quantities of NGL products, the pressure storage option

41


became increasingly expensive and unattractive from a practical and safety point of view, therefore low pressure storage in refrigerated liquid form became the normal for large quantities.

5.1.1. Methods of Operation in Tanks: •

Single containment tanks: Our single containment tanks typically feature a

primary liquid containment open-top inner tank, a carbon steel primary vapor containing outer tank and an earthen dike for secondary liquid containment. •

Full containment tanks: Full-containment tanks typically feature a primary

liquid containment open-top inner tank and a concrete outer tank. The outer tank provides primary vapor containment and secondary liquid containment. In the unlikely event of a leak, the outer tank contains the liquid and provides controlled release of the vapor.

5.2.

Transportation

Transportation and supply is an important aspect of the gas business, since LNG reserves are normally quite distant from consumer market. LNG is transported in specially designed ships with double hulls protecting the cargo systems from damage or leaks which are called LNG carriers. LNG will be sometimes taken to cryogenic temperatures to increase the tanker capacity. Recently ship-to-ship transfer (STS) transfers have been carried out which involved the transfer of LNG from a conventional LNG carrier to an LNG regasification vessel (LNGR). A typical modern LNG ship, or LNG carrier, is approximately 300m long, 43m wide and has a draft of 12m. Cargo capacities range from 1,000 cubic meters up to 267,000 cubic meters. Sailing speeds approach 21 knots. There are around 151 LNG tankers in the world. Their total capacity is 25.1 million cubic meters of liquid. The boil-off is used as fuel for the ship’s main propulsion

42


during Sea where the LNG is the only cargo which is permitted to be used as fuel in this manner.

Figure 28: LNG Ship Types

Figure 29: Cross Section of LNG Tanker

43


6. Regasification Regasification of the stored LNG is the final setup in the operation of LNG process, it’s simpler than liquification, and it is purely physical and not chemical. The regasification is accomplished by addition of heat from ambient air, ambient water, or remote fired vaporizers. The Cost of regasification system generally represents only a small fraction of the cost of the storage plant; however, reliability of the system is most important because failure or breakdown would defeat the purpose of the facility. Assuming LNG to be pure methane, the energy required to gasify the liquid is almost 40% of the gross heating v alue. Figure is a simplified flow diagram of a typical LNG regasification system. Liquid is pumped from the storage container to the vaporizer. The pump discharge pressure must be high enough to provide the desired gas pressure for entry into the transmission or distribution system. Heat is added to vaporize the high pressure LNG and to superheat the gas. Gas leaving the vaporizer must be odorized because the liquefaction process removes any odorant originally in the gas.

Figure 30: Simplified flow diagram of a typical LNG regasification system.

44


7. Proposed technology

Figure 31: proposed technology process flow diagram

45


7.1.

Precooling of feed gas

Contaminants-free and dried feed gas stream enters the plant at about 800 psig and 120° F, and is precooled in exchanger 51 to typically 10° F to -30° F, forming stream 2, using multiple cooling streams including liquid stream 5 from separator 52, side reboiler stream 22 from demethanizer 61, flash vapor 70 from LNG storage tank 69, external refrigerant 74, and letdown absorber bottoms stream 15. The chilled feed gas stream 2 is separated in separator 52, forming a gaseous portion 3 and a liquid portion 4. The liquid portion 4 is letdown in pressure in JT valve 53 forming stream 5, and optionally heated to stream 6 with the heat content from the feed gas prior to entering the demethanizer 61. The gaseous portion 3 from separator 52 is split into two portions. One portion (stream 7) is routed to the exchanger 54 to provide reflux to the absorber, and the other portion (stream 8) is expanded in turboexpander 64 to produce a chilled vapor stream 10, typically at -80° F to -100° F and to generate power to drive the residue gas compressor 65.

7.2.

Separation of C2+ from feed gas

The chilled vapor 10 is fed to absorber 58 (which act as a C 1 /C2+ separator), which operates at a pressure well above 450 psig, typically at between 500 psig to 700 psig, and most typically at 600 psig. Absorber 58 is refluxed with two cold streams, wherein the first reflux (top reflux) is supplied by stream 11 (via 56 and 27) from the demethanizer 61, wherein the second reflux is supplied by stream 12 (via 9 and 55) from exchanger 54. The reflux streams are chilled to about -125° F to -155° F. Using twin reflux streams and suitable flow ratios between streams 7 and 8; high C3 recovery can be maintained for the various levels of ethane recovery. The absorber produces an overhead vapor stream 28 (mainly methane) at about -100° F to -110° F and a bottoms stream 14 (mainly C2+) at about -90° F to -100° F.

46


A portion of the absorber bottoms stream 14 is letdown in pressure in JT valve 59 to about 460 psig, and is chilled to about -100° F, forming stream 15. During C3 recovery, this cold stream is used to provide at least a portion of the cooling duty of feed exchanger 51 and the reflux duty in condenser 62 to form streams 17 and 18, respectively.

During C2 recovery, at least a portion of absorber bottom stream 14 is routed directly to the top of the demethanizer. In this operation, JT valve 59 is partially, and more typically entirely closed and JT valve 60 is partially, and more typically entirely open forming stream 20 at a pressure that is about 50-350 psig less than absorber pressure. This stream enters the demethanizer at a temperature of between about -90° F to -130° F. The demethanizer is reboiled using reboiler 201 and produces bottom product 25, which is then fed to deethanizer 62. Demethanizer overhead product 24 is then routed back to the absorber as reflux stream 11. To that end, the overhead product 24 is recompressed to form stream 26 (to a pressure above absorber pressure) by compressor 66 and chilled in exchanger 54 to form stream 27, which is expanded to reflux stream 11.

7.3.

Liquefaction unit

The overhead vapor from the absorber is compressed by residue gas compressor 65 using power generated by turbo expander 64 forming a discharge stream 29, typically at about 900 psig and -70° F to -80° F. The residue gas is chilled and condensed in exchanger 67 to about -255° F to -265° F using refrigerant 79 operating at -180° F to 270° F that is produced by the mixed refrigeration system 102, after the compressed stream 76 is chilled in exchangers 54, 67, and JT’d via valve 92. The liquefied residue gas is further letdown in pressure to stream 82 at about 16.0 psig via JT valve 90, and the flashed liquid is stored in LNG storage tank 69. LNG product is withdrawn as stream 30 and withdrawn to storage or transport.

47


In some cases, depending on the natural gas composition and the temperature from the liquefier exchanger, a significant quantity of light gas 70 is evolved which can be recovered as fuel gas after its refrigerant content is recovered. Where desired, a portion of the ethane product stream 15 can be directed from deethanizer 59 to LNG storage or transport. In this way, lean LNG can be converted to a heavier and richer LNG.

7.4.

C2 liquid recovery

Deethanizer 62 is configured as reboiled column using reboiler 202 to separate C2 from C3+ components, wherein the C3+ components are drawn from the column as stream 23. The C2 overhead product is condensed in overhead condenser 302 and separated in drum 402. One portion 18 of the C2 product is pumped back by pump 59 to the column as reflux while another portion 19 is withdrawn for LNG blending or storage/transport via stream 17.

7.5.

C3 liquid recovery

Depropanizer 63 is configured as reboiled column using reboiler 203 to separate C3 from C4+ components, wherein the C4+ components are drawn from the column as stream 47. The C2 overhead product is condensed in overhead condenser 303 and separated in drum 403. One portion 45 of the C3 product is pumped back to the column as reflux while another portion 46 is withdrawn as a final product.

7.6.

C4 liquid recovery

Similarly, Debutanizer 64 is configured as reboiled column using reboiler 204 to separate C4 from C5+ components, wherein the C5+ components are drawn from the column as stream 57 as a final product or it can be further processed. The C2 overhead

48

Integrated NGL Recovery and LNG Liquefaction

Recommend Documents