Fluor-LNGRegasificationUtilization

FLUOR

5rd Annual Atlantic Canada Oil and Gas Halifax, Nova Scotia May 30-31, 2005

LNG Regasification and Utilization

LNG Regasification and Utilization Arnie Smith Executive Director, Technology John Y. Mak Technical Fellow Director, Process Engineering Energy and Chemicals Group, Fluor Enterprises, Inc., Aliso Viejo, California Abstract There are numerous environmental challenges and opportunities in today’s LNG receiving terminals. LNG receiving terminals, onshore and offshore, are typically designed for standalone LNG regasification, and have not taken advantages of the inherent cold energy from LNG. There are synergies between LNG regasification and power generation [1],[6]. LNG can be used as a cold heat sink in power generation, which would increase power production efficiency and replace the conventional regasification processes. There are also economic benefits of extracting the heavier hydrocarbons from LNG as the liquid components can be sold at a premium price over natural gas. In the ever competitive energy markets, LNG importers must also be ready to accept LNG with heating values higher than North American gas pipeline specifications. This paper describes two patent pending technologies, in power generation using LNG cold and in LPG extraction from LNG. In addition to improving efficiencies and enhancing project economics, these technologies will reduce environmental impacts, and produce quality pipeline gas and liquid products for sales. The hydrocarbons content in the import LNG can also be used to supplement the North American liquid fuel markets.

Introduction The demand of natural gas has been increasing significantly in the past few years, due to the replacement of the older power plant with the more efficient and clean burning natural gas fueled combined cycle power plants. plants. This trend will continue and LNG import is necessary necessary to supplement the energy requirement, as indigenous natural gas production continues to decline. There are other revenue opportunities in LNG, such as extraction of liquid products that have not been fully appreciated in today’s LNG receiving terminals. LNG terminals can be constructed on-shore or offshore. There are over 50 LNG terminals in North America in various stages of development. About 10 of these regasification facilities are proposed to be installed offshore. The advantage of an offshore installation is the avoidance of the growing opposition to land-based LNG facilities, particularly in urban areas. The offshore LNG terminals also do not require a deep-water port to offload LNG from supertankers. However, both onshore and offshore terminals will face the same challenges in terms of emissions and environmental concerns and import LNG heating value problems.

1

FLUOR



LNG has been recognized as a very cleaning fuel gas but it also contains other beneficial attributes. It is a cryogen that can be utilized in many ways. Considering the energy investment in the LNG process, about 10% of the energy in natural gas is consumed in the liquefaction process and about 2% is consumed during LNG LNG transport. Typically, LNG liquefaction liquefaction requires about 230 kW of refrigeration power in order to liquefy one MMscfd of high-pressure natural gas. A 1,200 MMscfd liquefaction plant will consume about 280 MW of power. Theoretically, some of the power consumed in LNG liquefaction can be recovered and converted back to electric power at the LNG receiving terminal. Therefore, there are significant synergies between power generation and LNG regasification. The low temperature refrigeration available during LNG regasification can be used for as a heat sink for power generation. Waste heat from gas turbine exhaust is readily available as a heat source for LNG regasification [1], [6]. From a thermodynamic point of view, the most efficient use of LNG is in cooling and as a refrigerant in cryogenic separation processes. While locating cryogenic separation separation plants close to a LNG regasification terminal are costly and unrealistic, a LPG separation unit integrated with LNG regasification for production of ethane, LPG and butane plus components may be economically attractive. The production methods vary between on-shore and offshore installations which will be discussed in this paper.

LNG Regasification A typical LNG regasification terminal is depicted in Figure 1 which consists of several subsystems, including ship unloading, LNG storage, LNG low pressure pump, tank boil-off gas compression, vapor re-condensation, LNG high pressure pump and LNG regasification. Typically, vapors generated from LNG ship unloading and during normal operation are compressed by the boiloff vapor compressor and re-condensed by mixing with sub-cooled LNG sendout. The condensed LNG is then pumped to gas pipeline pressure pressure by the high pressure sendout pumps and then heated by the LNG vaporizers to about 40°F 40°F for pipeline gas distribution. Alternatively, the LNG terminals can be constructed offshore. The designs of offshore LNG receiving terminals are similar to land-based terminals. However, offshore LNG terminals are significantly more expensive than onshore terminals since all processing equipment are located in a costly concrete gravity base structure (GBS), which provides a fixed platform for the ship unloading, LNG storage and regasification operation. LNG regasification is an energy intensive process. Typically, heating 1,200 MMscfd of LNG from -260°F -260°F to 40°F at 1200 psig pressure press ure requires requi res about 750 75 0 MM Btu/hr of heat absorbed ab sorbed duty. du ty. Over half of current regasification facilities use the open rack vaporizers (ORV) for LNG heating. Typically, this heat duty can be supplied by lowering the temperature of 100,000 gpm of seawater seawate r by 15°F, assuming seawater se awater is supplied sup plied at 80°F 80°F and can be returned retu rned to the ocean oce an at 65 F. °

The seawater system must be designed in accordance with the Clean Water Act for minimizing

2

FLUOR



mortality of marine life. The impact on the ecosystem changes has to be adequately addressed and remediation developed to mitigate the loss of fish species and micro-organisms. The project using seawater as a heat source must evaluate the effects of cold water on the Ichthyoplankton system. The current seawater system is generally designed to comply with the criteria for seawater effluent specified by the 1998 World Bank [5], which defines the seawater effluent should result in a temperature change of no more than 5.4 °F at the edge of the zone where initial mixing and dilution take place. For terminals located in warm climate, such as along the US Gulf coast and the Caribbean, use of seawater for LNG regasification is an obvious choice, for conservation of fuel gas, minimizing LNG shrinkage. For terminals located in cold climate areas where the seawater is close to freezing, the fuel fired submerged combustion vaporizer (SCV) methods is the only choice. Operating a 1,200 MMscfd regasification terminal would require about 20 MMscfd of fuel gas (based on 1050 Btu/scf heating value) that must be factored into the life cycle cost of the terminal. The gaseous emissions (NOx and CO) from the combustion process must also be mitigated, and Selective Catalytic Reduction System (SCR) can be used to meet the stringent NOx environmental regulations. Other LNG regasification methods may also be suitable, including the ambient air vaporizers, fired heaters, or from waste heat from cooling towers using a heat transfer fluid such as ethylene glycol, propylene glycol or methanol. Other innovative method is using the condensation duty in a Rankine power cycle for LNG regasification. BOILOFF COMPRESSOR

VAPOR RECONDENSER

OPEN RACK VAPORIZER

SEAWATER INTAKE

UNDERSEA PIPELINE

HP LNG PUMP

SEAWATER OUTFALL

LNG CARRIER LP LNG PUMP GBS LNG STORAGE

FUEL SUBMERGED COMBUSTION VAPORIZER

Figure 1 – Conventional LNG Regasification Plant

3

FLUOR



\ Rankine Cycle and Working Fluids Power can be generated using LNG as a cold heat sink using the classical Rankine cycle configuration as shown in Figure 2, where LNG is used for condensing a working fluid circulating in a close loop fashion, similar to the Rankine cycle used in today’s steam power plants. The ideal Rankine cycle efficiency (or Carnot Cycle efficiency) can be defined as: (T2-T1)/ T2 T2 is the absolute temperature of the heat source and T1 is the absolute temperature of the heat sink. When LNG is used as the heat sink (T1), the temperature difference term (T1-T2) is increased, resulting in higher power generation efficiency. The generation efficiency is proportional to the temperature difference for a constant heat source temperature. The selected working fluid must be thermally stable at high temperatures and condense at low temperatures without freezing problems. E- 3 HEATER EP-1 EXPANDER E-1 CONDENSER

E-2 RECUPERATOR

LNG FROM STORAGE

P-1 LNG PUMP

NATURAL GAS TO PIPELINE

E-4 COMBUSTION AIR COOLER

P- 2 PUMP

Figure 2 – Rankine Cycle for LNG Power Generation Per Figure 2, the working fluid is pumped by Pump P-2 to supercritical pressure, typically 1500 psig. The high-pressure fluid is first heated with the hot expander discharge in the Recuperator, E-2. The high pressure fluid is further heated in Heater, E-3, to about 600 °F. Heat can be supplied by fired heaters or waste heat exhausted from a gas turbine generator. The high temperature supercritical fluid is then expanded to atmospheric pressure in the Expander, EP-1, generating power. The low pressure vapor is then cooled in the Recuperator, E-2, and condensed in the Condenser, E-1. LNG is vaporized in the condenser using the condensation duty from the working fluid. Pure components, such as butane or propane, have been used as a working fluid in power generation. The power generation efficiency using butane is fairly low due to its high

4

FLUOR



condensation temperature. Butane condenses at 30°F under atmospheric pressure. Therefore, with butane as the working fluid, the very low temperature of LNG cannot be effectively utilized. Propane is a more efficient working fluid as it condenses at a much lower temperature (e.g., 44°F at atmospheric pressure). Other lower boiling fluids, such as ethane or ethylene, are not suitable for LNG vaporization, as their condensation temperatures are too low to heat the LNG to the required pipeline temperature. Multi-component working fluid is commonly used in refrigeration cycle for LNG liquefaction due to its high thermal efficiency. The same principle can be applied to power generation cycle where LNG is used as the heat sink. The advantage of a multi-component working fluid is that it condenses at varying temperatures and its composition can be tailored to match the LNG vaporization curve. In today’s plate and fin exchanger or spiral wound exchanger, a very close temperature approach is economically feasible. The shape of the working fluid condensation curve can be fine-tuned by adjusting the mixed fluid composition to parallel the LNG vaporization curve, avoiding the temperature pinch of a pure component system. There is an optimum mixed fluid composition for each LNG composition. An optimum mixed fluid composition and a corresponding LNG composition are shown in Table 1.

Mole % C1 C2 C3 C4

Import LNG 90 5 3 2

Mixed Fluid 18 24 33 24

Table 1 – Mixed Fluid Composition

Rankine Power Cycle Performance Table 2 compares the power cycle performance for three different working fluids: butane, propane and a mixed fluid. The power cycle output for the butane working fluid is 55.7 MW. With a propane working fluid, the power output is increased to 88.6 MW. The Mixed Fluid Power cycle has the highest power output of 107.1 MW achieving a power generation efficiency of 37.8%. To compare the thermodynamic efficiencies of the different working fluids, the LNG vaporization curve is plotted against the condensation curves as shown in Figure 3. Butane and propane, due to their higher condensation temperatures, must be superheated at the condenser inlet in order to avoid a temperature pinch in the condenser. On the other hand, the mixed fluid at the condenser inlet is in a two-phase region, thus avoiding the temperature pinch. The mixed fluid composition can be tailored to condense at a close temperature approach to LNG, resulting in higher power cycle efficiency.

5

FLUOR



Butane 600 1,450 62.5 6.8 55.7 791 31 24.1

Expander Inlet Temp, °F Expander Inlet Pressure, psig Expander, MW Pump MW Net Power, kW Heat Input, MM Btu/h Condensing Temperature, °F Power Generation Efficiency,%

Propane 600 1,450 96.6 7.9 88.6 903 -44 33.5

Mixed Fluid 600 1,450 115.0 7.8 107.1 967 - 10 to -220 37.8

Table 2 –Rankine Power Cycle Performance with Butane, Propane and Mixed Fluid

Butane

440

F ° , e r u t a r e p m e T

340

Propane

240 140

Mixed Fluid

40 -60 -160 -260 0

100

200

300

400

500

600

Duty, MM Btu/hr

Figure 3 –LNG Regasification Curve and Working Fluid Condensation Curves

Gas Turbine Inlet Cooling Gas turbine inlet cooling with refrigeration to overcome the power loss during summer operation is a common practice in the power industries. The colder air temperature allows a higher mass flow through the gas turbine, resulting in a higher gas turbine power output with improved efficiency. Figure 4 shows the impact of ambient air temperature on power generation for a power plant. Typically, power output of a gas turbine can be increased by about 1% when the inlet air temperature is lowered by 3 to 4 °F. LNG cold can be advantageously utilized for chilling the gas turbine inlet air. For a large power plant such as 1600 MW, the heat content in the inlet air can be sufficient to regasify a small

6

FLUOR



LNG receiving terminal, as explained in the subsequent section. One of the first plants using this concept with LNG for gas turbine inlet cooling is the Dominican Republic LNG receiving terminal. This plant uses a glycol-water solution that circulates between the LNG regasification plant and a chiller coil at the gas turbine inlet.

125 % 120 , t u p 115 t u O r 110 e w o P 105

100 100

90

80

70

60

50

40

Ambient Temperature, ° F

Figure 4 - Combined Cycle Power Plant Outputs vs Ambient Temperatures

The other advantage of gas turbine inlet air-cooling is that it decouples power generation capacity from changes in ambient temperature and relative humidity. Power plants typically experience a drop in power output during summer when ambient temperature increases above design. In many cases this drop in power output coincides with an increase in power demand. Using LNG to cool the gas turbine inlet air, a constantly high power output can be maintained throughout the year. This power increase is gained without external refrigeration. The incremental cost per kW installed power is significantly less than a conventional unit. The air cooler system design would include the air cooling coils and the glycol circulation system. It is therefore preferred to have the power plant located in close proximity to the regasification terminal to further reduce the installation cost. Depending on the heat balance between the LNG regasification duty and the chilled air requirement, excessive chilled glycol-water may be also available. In this case, the excessive refrigeration can be used to chill the cooling water supply temperature to the combined cycle power plant. This will effectively lower the steam turbine surface condenser pressure which in turns lowers the steam turbine back-pressure, resulting in a higher steam turbine output and power generation efficiency.

Integrated LNG Regasification/Power Generation The conceptual design of an integrated plant for a gas turbine simple cycle power plant is depicted in Figure 5. Power is produced in a combination of three separation steps:

7

FLUOR



• • •

Mixed Fluid Power cycle Gas turbine combustion air cooling Fuel gas saturator using condensate recovered from the gas turbine inlet

AIR PRECOOLER

FUEL GAS SATURATOR STACK

E-6 FUEL GAS

V-1

X-1

V-2

AIR E-5

GT-1

P- 6

E- 3

EP-1

P- 5

LNG FROM STORAGE

P- 4

E-2

E-1

E-4

NATURAL GAS TO PIPELINE

MIXED FLUID POWER CYCLE

P-1 P- 2

P- 3

Figure 5 – Integration of LNG Regasification to a Gas Turbine Power Plant The use of the mixed fluid power cycle and air chilling using the refrigeration released from LNG regasification, described in the previous sections, are sequentially applied in this integrated process. A thermally stable heat transfer fluid, such as Dowtherm, can be used to transfer waste heat from the gas turbine exhaust to the Rankine power cycle. Per Figure 5, the heat medium pump, P-5, is used to transfer heat from the heat recovery exchanger, E-6, to the heat exchanger, E-3. In a similar manner, LNG indirectly cools the gas turbine inlet air with the use of a heat transfer fluid which can be an ethylene glycol water mixture, propylene glycol water mixture or methanol. The glycol mixture is pumped by the glycol pump, P-3, circulating between the LNG vaporizer, E-4, and the gas turbine inlet chiller, E-5. When ambient air is chilled to 40°F, almost all of its moisture content is condensed. The condensate can be used as makeup water to a combined cycle power plant, reducing its demineralized water makeup requirement.

8

FLUOR



When a simple gas turbine cycle is used, the condensate from the air cooler can be vaporized into the fuel gas to the gas turbine, thereby further increasing the mass flow, and power output from the gas turbine. This can be achieved by circulating a hot water loop using pump P-2 and with a saturator column V-2 for heat and mass transfer. The low level heat from the gas turbine discharge is transfer to vaporize the water to the fuel gas prior to the combustor X-1 of the gas turbine. Beside additional power generation due to the high mass flow to the gas turbine, fuel gas moisturization can effectively lower the flame temperature at the combustion chamber of the gas turbine, which has the benefit of reducing NOx and CO emissions from the gas turbines. Reliability and availability of sufficient waste heat from the gas turbine exhaust for LNG regasification is of primary importance in an integrated facility. Typically, power generation varies with consumer demands that in turns results in fluctuation of the available waste heat. On the other hand, the heat input to a base-load LNG regasification plant is constant. For this reason, backup heat sources, such as duct firing in the gas turbine, or steam boiler must be used to ensure the total availability of the heat source to the LNG regasification facility.

Integration to a 140 MW Gas Turbine Simple Cycle Power Plant Table 3 compares the previously described integrated plant to the standalone plants for a 1,200 MMscfd LNG regasification terminal. Both seawater regasification and submerged combustion type regasification plants are compared. Power from the integrated plant is compared to a conventional combined cycle power plant based on a 141 MW gas turbine and a 68.4 MW steam turbine generator.

Seawater LNG Regas. (ORV) + Standalone CCU

Combustion LNG Regas. (SCR) + Standalone CCU

Integrated LNG Power Generation

100,000 8.0 6.0 0.0 0.0 -14.0

None 8.0 0.0 800.0 0.0 -8.0

None 8.0 0.0 0.0 111.0 103.0

90 141.0 68.4 40,000 209 1,463 1,463 195.5 7,487

90 141.0 68.4 40,000 209 1,463 2,263 201.5 11,235

40 191.8 None None 191.8 1,808 1,808 294.8 6,133

LNG Regasification: Seawater Flow rate, GPM LNG Pumps, MW Seawater Pumps, MW Fuel fired, MM Btu/hr Mixed Fluid Cycle, MW Power Production, MW Power Plant: Combustion Air Inlet, °F Gas Turbine, MW Steam Cycle MW Cooling Water, GPM Total Power Plant, MW Power Plant Fuel, MM Btu/hr LHV Total Fuel Gas, MM Btu/hr LHV Net Power Output, MW Power Generation Efficiency, Btu/kW-hr

Table 3 – Comparison of Power Generation of Integrated to Standalone LNG Plant

9

FLUOR



Conventional LNG regasification requires about 100,000 gpm of seawater or 800 MM Btu/hr of fuel gas consumption for a 1,200 MMscfd sendout flow. The integrated facility has eliminated these requirements with the use of the condensation duty from the mixed fluid Rankine cycle as a source of heat. The Mixed Fluid Rankine cycle produces a gross 111 MW and a portion of this power can be used to supply the power requirement of the facility. In the integrated configuration using the Rankine cycle, the steam bottoming cycle is not required, and hence the associated cooling water system can be eliminated, which significantly reduces the capital, operating and maintenance costs of the power plant. The power output from the gas turbine is increased from 141 MW to 192 MW, which is a result of the new configurations using gas turbine inlet air cooling and fuel gas moisturization. The fuel gas required by the integrated plant is 1,808 MM Btu/hr which is higher than the fuel gas consumed in the ORV combined cycle option, mainly to the significantly higher power output of the integrated design. When compared to the SCV combined cycle option, the integrated plant consumes significantly less fuel gas while producing more power. The plant performances should be compared for their power generation efficiencies. The integrated facility achieves 6,133 Btu/kW-hr which is significantly higher than conventional standalone designs.

Integration to a 1,600 MW Combined Cycle Power Plant When a large power plant is considered, the heat content in the gas turbine inlet air can be sufficient to supply the heating requirement of a LNG regasification terminal. The design of this integrated system would use a glycol water solution or methanol to transfer the cooling duty from the LNG regasification plant to the air chillers in the power plant. The process flow configuration of the integrated system is shown in Figure 6. A case study was carried out to evaluate the thermal integration potential of a 500 MMscfd LNG terminal and a 1,600 MW combined cycle power plant. The site is located in a mildly climate region of the world, with an average ambient temperature 60°F and about 80% relative humidity. Summer temperature higher than 80°F is infrequent, and the winter temperature can drop to below freezing. The case study was to evaluate if this site is suitable for thermal integrated to an LNG plant. Due to the large power plant capacity, the gas turbine inlet air during summer would provide more than adequate heating to the LNG regasification terminal. However, during the few winter months, when the ambient drops below 50°F, there is not sufficient heat that is needed to meet the regasification duty of the 500 MMscfd LNG sendout rate. Additional heat source must be made available. To circumvent the heat balance problem, the cooling water to the power plant is used to for heating the glycol water solution. The heat rejection of a 1,600 MW combined cycle power plant can easily accommodate the additional heating duty. Additionally, this operation has a side benefit, as the lower cooling water temperature will effectively lower the steam turbine surface condenser pressure of the steam power plant. This, in turns, will lower the steam turbine back-pressure, resulting in a higher steam turbine output and power generation efficiency.

10

FLUOR



STEAM TURBINES

1,600 MW CCU AIR PRECOOLER

CWR

HRSG GAS TURBINES WINTER OPERATION

CWS GLYCOL

500 MMSCFD LNG LNG VAPORIZERS 300 MMBtu/h

SECONDARY PUMPS

Figure 6 – Integration of LNG Regasification to a 1600 MW Combined Cycle Power Plant

Power Output from 1600 MW Combined Cycle Power Plant The result of the power increases from a 1600 MW combined cycle power plant using gas turbine air chilling for the mildly climate site is shown in Figure 7. The Y-axis of this graph shows the number of hours and the corresponding ambient temperatures and is graphed against the power output for the standalone (non-integrated) power plant and the air chilled (LNG integrated) power plant. As shown in the figure, the power output using air chilling with LNG can increase the power output of the 1600 MW power plant by about 80 to 100 MW. The increase in power output during summer is particularly important as the consumer power demands during this period are also higher. For the standalone non-integrated power plant, its power output would drop to about 1450 MW due to the high ambient temperature. With the integrated system, the power output during summer can be increased to about 1550 MW, a 100 MW increase over the standalone non-integrated case. Additionally, the water condensed from the gas turbine inlet air can be utilized to supply the boiler feed water makeup requirement in the combined cycle power plant which reduces the requirement of the demineralization system.

11

FLUOR



102

Integrated with Air Chilling

95 F g e d , e r u t a r e p m e T t n e i b m A

5 30

88

120

81

250

73

580

Non- Integrated

66

950

59

1370

52

680

45

280

37

50

1,300

1,350

1,400

1,450

1,500

1,550

1,600

1,650

1,700

N u m b e r o f h o u r s

1,750

Power Output, MW

Figure 7 – Power output from a 1600 MW Combined Cycle Power Plant

LNG Heating Values and Compositions One of the problems in LNG receiving terminals is accepting rich LNG with non-compliant heating values. As the LNG import market grows, spot LNG trades will become common, as in today’s crude oil trade market. With increasing LNG trading traffics between the different LNG producers and the North America regasification sites, the LNG terminals must be ready to accept LNG carriers from different sources with various compositions and heating values. In some markets, the rich LNG can be made profitable as its propane content can be sold as LPG and the butane plus liquid can be used for gasoline blending. Additionally, processing steps for extraction of the heavier components from the rich LNG are necessary to meet the stringent North America pipeline heating value specification. In upstream LNG liquefaction plants, removal of the pentane, hexane and heavier hydrocarbons is required only to avoid wax formation inside the cryogenic liquefaction exchanger. The LPG components (C2, C3 and C4+) are not removed and liquefied together with the methane component, resulting in LNG with a fairly high gross heating value. The heating values of LNG from a number of LNG export plants in the Atlantic, Pacific Ocean and Middle East LNG plants are shown in Figure 8. The higher heating values indicate a higher proportion of the nonmethane components. The compositions of the ethane, propane, and butane and heavier components for these LNG are shown in Figure 9.

12

FLUOR



In North America, many pipeline operators require very lean gas for transmission, and in some mid-west regions, natural gas gross heating value ranges between 960 and 1050 Btu/scf. In California, the acceptable gross heating value is between 970 and 1150 Btu/scf. California also imposes constraints on specific gas components for compressed natural gas consumption. Currently, acceptable LNG that meets the California specification is limited to sources such as the Kenai, Alaska LNG [4], or the Atlantic LNG from Trinidad. To meet the North American natural gas specifications, these regasification terminals must have facilities that are capable of processing these non-compliant LNG [3]. The common method of controlling the LNG heating value and Wobbe Index is by dilution with nitrogen or blending with a leaner natural gas. However, there are also limits on the maximum amount of nitrogen and inerts that can be introduced to the pipeline gas. The dilution with nitrogen would require an air separation plant which is costly and produces no benefit for the facility. A lean gas source is mostly likely not available for blending in a large LNG regasification facility.

f c S / u t B , e u l a V g n i t a e H r e h g i H

1200 1150 1100 1050 1000 950 i a n e K

d a d i n i r T

G N L n u r A

a i s e n o d n I

t s e f l w e h h t r S o N

n a f f a L s a R

i e n u r B

n a m O

Figure 8- LNG Energy Content for Selected Atlantic, Pacific and Middle East Plants

13

i b a h D u b A

[4]

FLUOR



18 16

Hexane + Propane to Pentane

Ethane

14

% , 12 t n e 10 n o p 8 m o 6 C 4 2 0

i a n e K

d a d i n i r T

a i s y a l a M

i e n u r B

a i s e n o d n I

G N L n u r A

n a m O

Figure 9 – Non-Methane Constituents for Selected Atlantic, Pacific and Middle East Plants [4]

Onshore LNG BTU Reduction and LPG Production The LPG components in LNG are of high quality as all the contaminants, water and heavy hydrocarbons have been removed in the liquefaction process. LPG from LNG can be sold as a clean liquid fuel and can command a higher price than natural gas. The use of LNG cold to recover LPG requires significantly less capital and has lower operating costs than conventional NGL recovery processes. Costly gas treating, conditioning and processing units, such as gas treating, dehydration, turbo-expander, refrigeration and residue gas compression are not required. Typically, the power requirement to process 1,200 MMscfd feed gas is 60,000 HP or 44.7 MW, which is mainly used for chilling the feed gas and recompressing the residue lean gas. The LPG fractionation process shown in Figure 10 eliminates these units and their energy consumption. This process can achieve 99% propane recovery without gas chilling and recompressing requirements.

14

FLUOR



E-4 LNG REGASIFICATION USING RANKINE POWER CYCLE

LEAN RESIDUE GAS (1050 BTU/SCF)

P- 5

RICH LNG

E-4 V-3 V-2 EP- 2

P-1

V-1 E-5

P-3

C2, C3 and C4 +

P-4

Figure 10 – Onshore LNG BTU Reduction Per Figure 10, LNG send-out rate of 1,200 MMscfd is pressurized by LNG pump P-1 to about 500 psig and fed to the LPG fractionation unit. The LNG cold is utilized in the brazed aluminum type exchanger E-4. This exchanger serves dual functions. First, this exchanger uses LNG cold to condense the deethanizer, V-3 overhead to produce an ethane rich cold reflux to the deethanizer. Secondly, the exchanger condenses the lean residue gas, allowing the condensed liquid to be pumped to the gas pipeline pressure. This eliminates costly gas compression systems. After heat exchange in E-4, LNG is heated to about -90°F and is partially vaporized. The twophase stream is separated in vessel V-2. The flashed vapor is fed to the upper rectification trays in the deethanizer, V-3, and the flashed liquid is used for power generation and stripping. The flashed liquid is pumped by pump P-4 to about 1500 psig and is then heated in exchanger E-5 to about 600°F. The high-pressure high-temperature vapor is expanded in expander EP-2 to 460 psig, generating power. The expander discharge vapor, which is quite warm, typically at 300°F, is used as a stripping vapor in the fractionator. The stripping vapor can supply most of the reboiler requirement and can be trim-heated with a bottom reboiler as required. The deethanizer operates at 450 psig with an overhead temperature of -65°F. The overhead vapor is cooled to about -105°F in exchanger E-4 and partially condensed. The condensed liquid is separated in reflux drum, V-1 and is returned to the deethanizer as reflux using the reflux pump, P-3. The lean residual vapor from V-1 is further cooled and condensed in E-4. The lean residue gas is re-condensed as a lean LNG at -140°F. The lean LNG is then pumped by pump P-5 to about 1100 psig as required for pipeline transmission. This re-condensation and pumping operation is more energy efficient and less costly than the residual gas re-

15

FLUOR



compression in a conventional NGL recovery plant. The lean LNG at -140°F still contains a significant amount of cold energy that can be further utilized. The cold energy can be used in the LNG regasification exchanger E-4, for combustion air cooling to increase power output from a gas turbine or for power generation using the Mixed Fluid power cycle, as previously described. When used in a Rankine cycle, due to the leaner LNG composition, the composition of the multi-component fluid must be adjusted to match the heat curve of the leaner LNG. The hot and cold composite curves of the integration scheme are shown in Figure 11. The close matches between the LNG regasification curve and the utilization curve result in high efficiency of the integrated process. The overall balance for a 1,200 MMscfd Integrated LPG Fractionation/LNG Regasification Facility is shown in Table 4. This facility produces 40,700 BPD of propane plus product, 31,200 BPD of ethane and 1,094 MMscfd of 1,021 Btu/SCF HHV pipeline gas. The propane plus product can be separated into a LPG liquid fuel for the local market and butane plus used for gasoline blending at local refineries. Ethane production would require a second column, the deethanizer, to fractionate the ethane from the C3 LPG product. The first column would operate as a demethanizer producing an ethane and heavier bottoms product to be processed in the second column which further fractionates into the ethane and the C3 LPG fraction. In the integrated scheme, the cold from LNG can be effectively utilized in refluxing the columns, eliminating external refrigeration and compression requirements.

Component, Mol Fraction N2 C1 C2 C3 IC4 NC4 NC5 Gross Heat Value, Btu/SCF MMscfd Barrels per day

LNG Feed

LPG Fraction

Ethane

Pipeline Gas

0.0034 0.8976 0.0501 0.0316 0.0069 0.0103 0.0001 1,137 1,200 NA

0.0000 0.0000 0.0100 0.6277 0.1442 0.2160 0.0021 2,850 57 40,700

0.0000 0.0215 0.9585 0.0200 0.0000 0.0000 0.0000 1,787 49 31,200

0.0036 0.9439 0.0517 0.0009 0 0 0 1,021 1,094 NA

Table 4 – C2, and LPG Production Overall Balance

16

FLUOR



Power Production 150 100

F ° , e r u t a r e p m e T

50 0

E-1 LPG Production

-50

E-4

-100 -150 -200 -250 -300 0

100

200

300

400

500

600

700

800

900

1000

Duty, MM Btu/hr Figure 11 – Composite Curves of LNG Regasification Integrated Process

Offshore LNG BTU Reduction and LPG Production Building offshore LNG terminals is significantly more expensive than building onshore terminals. Installation of an LPG fractionation facility in the offshore gravity based structure is particularly expensive. Liquid product storage, liquid handling and liquid product loading facilities would further add to the cost of the facilities. Operating these facilities with limited offshore staffing may also be difficult. Therefore, current offshore terminals are limited to the essential facilities such as LNG unloading, pumping and regasification. LPG extraction facilities are better to be deferred until the natural gas reaches onshore. The following describes a new process (patent pending) that is suitable for extracting the LPG components in an offshore LNG terminal to meet the heating value content of the sales gas pipeline specifications. This process consists of an offshore regasification plant and an onshore LPG extraction plant, as shown in Figure 12. The offshore plant uses the Rankine power cycle (previously described) to supply heat for LNG regasification while generating power for the offshore facility. The Rankine power cycle can produce about 80 MW of electric power using the waste heat from the gas turbine exhaust.

17

FLUOR



The onshore plant can recover 97% of the propane, virtually all the butane plus components. If necessary, about 70% of the ethane can be recovered from the LNG. Unlike most conventional NGL extraction process, this process does not require external refrigeration and gas compression and can be operated at various levels of ethane recovery to meet the ethane market demands. ONSHORE BTU-REDUCTION UNIT SALES GAS -127°F

E-1B C-2

EP-1

E-2

-106°F

E-1A 450 psig

1150 psig, -35°F

230 psig

-70°F

V-1

E-1A/B

C2

V-2 DEC1

-11°F C-1

V-3 DEC2

EP-2

E-4 E-3

1600 psig,

C3 +

119°F

UNDERSEA PIPELINE

OFFSHORE LNG REGASIFICATION

0°F

1650 PSIG LNG REGASIFICATION/ POWER CYCLE

POWER EXPORT

HP LNG PUMP

LNG CARRIER

-260°F LP LNG PUMP

GBS LNG STORAGE

Figure 12 – Offshore LNG Regasification Process with Onshore BTU Reduction Unit Per

Figure 12, LNG from the storage tank is pumped by the low pressure LNG pump to an intermediate pressure such as 100 psig, and then pumped by the high pressure LNG pump to supercritical pressure, typically 1650 or higher depending on the length of the undersea pipeline

18

FLUOR



and the LNG composition. LNG is then heated and partially regasified to about 0°F using the condensation duty from Rankine power cycle. It is important to note that the LNG is only partially regasified to 0°F instead of completely regasified to 40°F. Also the operating pressure of 1600 psig is higher that the final gas pipeline pressure requirement. The high pressure and low temperature of the semi-regasified LNG effectively preserves the refrigeration content in LNG that is needed in the offshore fractionation facility. Also the regasification duty at 1650 psig and 0°F is significantly less than that of the typical conventional design at 800 psig and 40°F. The supercritical fluid arrives onshore at about 1650 psig and is letdown in pressure to about 1100 psig in the first stage turbo-expander, EP-1, which generates power to operate the second stage residue gas compressor, C-2. The expansion process also chills the feed gas to about 35°F. The refrigeration content of this stream is utilized in the deethanizer reflux condenser, E1A, and the residue gas compressor discharge cooler, E-1B. The heated stream from E-1A/B is separated in separator V-1. The separator liquid and vapor are separately fed to the demethanizer, V-2. To improve NGL recovery levels, vapor from V-1 is split into two portions with one portion routed to the reflux condenser, E-2, for refluxing the demethanizer column. The remaining portion is letdown in pressure in the second stage turboexpander, EP-2, which generates sufficient power to operate the first stage residue gas compressor, C-1. This expansion process chills the gas to about -70°F, supplying the demethanizer cooling requirements. The reflux stream is chilled to about -106°F by heat exchange with the demethanizer overhead in E-2. This stream is then letdown in pressure in a JT valve and fed to the top of the demethanizer as reflux. The flow to this exchanger is lowered when a lower ethane recovery is desired. The process can also operate in an ethane rejection mode, that is, only propane plus recovery, to meet fluctuations in the ethane and energy markets. The demethanizer operates at about 450 psig, producing a lean overhead gas and a NGL bottom product. The NGL product methane content is minimized with heat supplied by the reboiler, E-3. The demethanizer bottom product is further processed in the deethanizer, V-3. The deethanizer uses the reflux condenser, E-1A, and the reboiler, E-4, to fractionate the demethanizer bottoms into an ethane overhead vapor and a propane plus LPG product. With the two stage turboexpander/compressor system, the demethanizer overhead gas can be compressed to about 800 psig. If higher delivery pressure is required, a booster compressor can be added.

19

FLUOR



Conclusions Current LNG regasification plants under construction have not taken the advantage of the inherent cold energy in LNG and many are facing the emissions and environmental problems associated with conventional LNG regasification. While permitting these facilities takes time, efforts must be devoted to include LNG cold utilization and improve the current LNG regasification practices. Future LNG regasification terminals must therefore be designed to accommodate the everchanging landscape of the environmental and regulation requirements and advances in technologies. Life cycle costs of the regasification facilities must be evaluated against initial capital costs in a competitive LNG market. Thermal integration with a power plant, in a Rankine cycle or a combined cycle configuration is a natural progression, which would reduce the combined plant cost and increase in overall thermal efficiency. The LNG receiving terminals, onshore or offshore, must be designed to receive the rich LNG that must be re-conditioned for reduction of its BTU value to meet the North American pipeline specifications. The extraction of LPG and butane and heavier components from LNG will provide additional revenues, and will improve the overall economics of the LNG receiving terminals.

References Cited

1.

Mak, J., “Power and LPG Production with LNG Import” 2nd Annual Atlantic Canada Power Summit, November 2004, Saint John, New Brunswick, Canada.

2. Mak, J., Nielsen, D., Schulte D., and Graham C., “LNG Flexibility”, October 2003, Hydrocarbon Engineering. 3. Mak, J., Nielsen, D., Schulte D., and Graham C., “A New and Flexible LNG Regasification Plant”, Gas Processors Association, March 2004, New Orleans, Louisiana. 4. Zeus Development Corporation, “LNG-West East Meet West,” June 2003, Long Beach, California. 5. World Bank Group, “Pollution Prevention and Abatement Handbook,” Effective July 1998. 6.

Mak, J., “Mixed Fluid Power Rankine Cycle using LNG as Heat Sink with LPG Extraction” AIChE 2005 Spring Meeting, LNG I – Plant & Operation, April 10–14, 2005, Atlanta, GA.

20

Fluor-LNGRegasificationUtilization

Recommend Documents