GDS International - Next - Generation - Oil & Gas - Summit - Africa - 4


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LNG Regasification and Utilization

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GDS International - Next - Generation - Oil & Gas - Summit - Africa - 4

  1. 1. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005LNG Regasification and UtilizationArnie SmithExecutive Director, TechnologyJohn Y. MakTechnical Fellow Director, Process EngineeringEnergy and Chemicals Group, Fluor Enterprises, Inc., Aliso Viejo, CaliforniaAbstractThere are numerous environmental challenges and opportunities in today’s LNG receivingterminals. LNG receiving terminals, onshore and offshore, are typically designed for standaloneLNG 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 usedas a cold heat sink in power generation, which would increase power production efficiency andreplace the conventional regasification processes. There are also economic benefits ofextracting the heavier hydrocarbons from LNG as the liquid components can be sold at apremium price over natural gas. In the ever competitive energy markets, LNG importers mustalso be ready to accept LNG with heating values higher than North American gas pipelinespecifications. This paper describes two patent pending technologies, in power generation usingLNG cold and in LPG extraction from LNG. In addition to improving efficiencies and enhancingproject economics, these technologies will reduce environmental impacts, and produce qualitypipeline gas and liquid products for sales. The hydrocarbons content in the import LNG can alsobe used to supplement the North American liquid fuel markets.IntroductionThe demand of natural gas has been increasing significantly in the past few years, due to thereplacement of the older power plant with the more efficient and clean burning natural gasfueled combined cycle power plants. This trend will continue and LNG import is necessary tosupplement 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 havenot been fully appreciated in today’s LNG receiving terminals.LNG terminals can be constructed on-shore or offshore. There are over 50 LNG terminals inNorth America in various stages of development. About 10 of these regasification facilities areproposed to be installed offshore. The advantage of an offshore installation is the avoidance ofthe growing opposition to land-based LNG facilities, particularly in urban areas. The offshoreLNG 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 ofemissions and environmental concerns and import LNG heating value problems. 1
  2. 2. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005LNG has been recognized as a very cleaning fuel gas but it also contains other beneficialattributes. It is a cryogen that can be utilized in many ways. Considering the energy investmentin the LNG process, about 10% of the energy in natural gas is consumed in the liquefactionprocess and about 2% is consumed during LNG transport. Typically, LNG liquefaction requiresabout 230 kW of refrigeration power in order to liquefy one MMscfd of high-pressure naturalgas. 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 toelectric 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 heatsink for power generation. Waste heat from gas turbine exhaust is readily available as a heatsource for LNG regasification [1], [6].From a thermodynamic point of view, the most efficient use of LNG is in cooling and as arefrigerant in cryogenic separation processes. While locating cryogenic separation plants closeto a LNG regasification terminal are costly and unrealistic, a LPG separation unit integrated withLNG regasification for production of ethane, LPG and butane plus components may beeconomically attractive. The production methods vary between on-shore and offshoreinstallations which will be discussed in this paper.LNG RegasificationA typical LNG regasification terminal is depicted in Figure 1 which consists of severalsubsystems, including ship unloading, LNG storage, LNG low pressure pump, tank boil-off gascompression, vapor re-condensation, LNG high pressure pump and LNG regasification.Typically, vapors generated from LNG ship unloading and during normal operation arecompressed by the boiloff vapor compressor and re-condensed by mixing with sub-cooled LNGsendout. The condensed LNG is then pumped to gas pipeline pressure by the high pressuresendout pumps and then heated by the LNG vaporizers to about 40°F for pipeline gasdistribution.Alternatively, the LNG terminals can be constructed offshore. The designs of offshore LNGreceiving terminals are similar to land-based terminals. However, offshore LNG terminals aresignificantly more expensive than onshore terminals since all processing equipment are locatedin a costly concrete gravity base structure (GBS), which provides a fixed platform for the shipunloading, LNG storage and regasification operation.LNG regasification is an energy intensive process. Typically, heating 1,200 MMscfd of LNGfrom -260°F to 40°F at 1200 psig pressure requires about 750 MM Btu/hr of heat absorbed duty. Over half of current regasification facilities use the open rack vaporizers (ORV) for LNGheating. Typically, this heat duty can be supplied by lowering the temperature of 100,000 gpm ofseawater by 15°F, assuming seawater is supplied at 80°F and can be returned to the ocean at65°F.The seawater system must be designed in accordance with the Clean Water Act for minimizing 2
  3. 3. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005mortality of marine life. The impact on the ecosystem changes has to be adequately addressedand remediation developed to mitigate the loss of fish species and micro-organisms. The projectusing seawater as a heat source must evaluate the effects of cold water on the Ichthyoplanktonsystem. The current seawater system is generally designed to comply with the criteria forseawater effluent specified by the 1998 World Bank [5], which defines the seawater effluentshould result in a temperature change of no more than 5.4 °F at the edge of the zone whereinitial mixing and dilution take place.For terminals located in warm climate, such as along the US Gulf coast and the Caribbean, useof seawater for LNG regasification is an obvious choice, for conservation of fuel gas, minimizingLNG shrinkage. For terminals located in cold climate areas where the seawater is close tofreezing, 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 theterminal. The gaseous emissions (NOx and CO) from the combustion process must also bemitigated, and Selective Catalytic Reduction System (SCR) can be used to meet the stringentNOx 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 asethylene glycol, propylene glycol or methanol. Other innovative method is using thecondensation duty in a Rankine power cycle for LNG regasification. BOILOFF VAPOR OPEN RACK SEAWATER INTAKE COMPRESSOR RECONDENSER VAPORIZER UNDERSEA PIPELINE HP LNG SEAWATER PUMP OUTFALL LNG CARRIER LP LNG PUMP FUEL GBS LNG SUBMERGED STORAGE COMBUSTION VAPORIZER Figure 1 – Conventional LNG Regasification Plant 3
  4. 4. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005Rankine Cycle and Working FluidsPower can be generated using LNG as a cold heat sink using the classical Rankine cycleconfiguration as shown in Figure 2, where LNG is used for condensing a working fluidcirculating in a close loop fashion, similar to the Rankine cycle used in today’s steam powerplants. The ideal Rankine cycle efficiency (or Carnot Cycle efficiency) can be defined as: (T2-T1)/ T2T2 is the absolute temperature of the heat source and T1 is the absolute temperature of theheat sink. When LNG is used as the heat sink (T1), the temperature difference term (T1-T2) isincreased, resulting in higher power generation efficiency. The generation efficiency isproportional to the temperature difference for a constant heat source temperature. The selectedworking fluid must be thermally stable at high temperatures and condense at low temperatureswithout freezing problems. E- 3 HEATER EP-1 EXPANDER E-1 CONDENSER E-2 LNG FROM NATURAL GAS TO RECUPERATOR STORAGE PIPELINE P-1 LNG PUMP E-4 COMBUSTION AIR P- 2 COOLER PUMP Figure 2 – Rankine Cycle for LNG Power GenerationPer Figure 2, the working fluid is pumped by Pump P-2 to supercritical pressure, typically 1500psig. 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 besupplied by fired heaters or waste heat exhausted from a gas turbine generator. The hightemperature 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, andcondensed in the Condenser, E-1. LNG is vaporized in the condenser using the condensationduty from the working fluid.Pure components, such as butane or propane, have been used as a working fluid in powergeneration. The power generation efficiency using butane is fairly low due to its high 4
  5. 5. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005condensation 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 notsuitable for LNG vaporization, as their condensation temperatures are too low to heat the LNGto the required pipeline temperature.Multi-component working fluid is commonly used in refrigeration cycle for LNG liquefaction dueto its high thermal efficiency. The same principle can be applied to power generation cyclewhere LNG is used as the heat sink. The advantage of a multi-component working fluid is that itcondenses at varying temperatures and its composition can be tailored to match the LNGvaporization curve. In today’s plate and fin exchanger or spiral wound exchanger, a very closetemperature approach is economically feasible. The shape of the working fluid condensationcurve can be fine-tuned by adjusting the mixed fluid composition to parallel the LNGvaporization curve, avoiding the temperature pinch of a pure component system.There is an optimum mixed fluid composition for each LNG composition. An optimum mixedfluid composition and a corresponding LNG composition are shown in Table 1. Mole % Import LNG Mixed Fluid C1 90 18 C2 5 24 C3 3 33 C4 2 24 Table 1 – Mixed Fluid CompositionRankine Power Cycle PerformanceTable 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 FluidPower cycle has the highest power output of 107.1 MW achieving a power generation efficiencyof 37.8%.To compare the thermodynamic efficiencies of the different working fluids, the LNG vaporizationcurve 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 inorder to avoid a temperature pinch in the condenser. On the other hand, the mixed fluid at thecondenser inlet is in a two-phase region, thus avoiding the temperature pinch. The mixed fluidcomposition can be tailored to condense at a close temperature approach to LNG, resulting inhigher power cycle efficiency. 5
  6. 6. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005 Butane Propane Mixed Fluid Expander Inlet Temp, °F 600 600 600 Expander Inlet Pressure, psig 1,450 1,450 1,450 Expander, MW 62.5 96.6 115.0 Pump MW 6.8 7.9 7.8 Net Power, kW 55.7 88.6 107.1 Heat Input, MM Btu/h 791 903 967 Condensing Temperature, °F 31 -44 - 10 to -220 Power Generation Efficiency,% 24.1 33.5 37.8 Table 2 –Rankine Power Cycle Performance with Butane, Propane and Mixed Fluid 440 Butane Temperature, °F 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 CurvesGas Turbine Inlet CoolingGas turbine inlet cooling with refrigeration to overcome the power loss during summer operationis a common practice in the power industries. The colder air temperature allows a higher massflow through the gas turbine, resulting in a higher gas turbine power output with improvedefficiency. Figure 4 shows the impact of ambient air temperature on power generation for apower plant. Typically, power output of a gas turbine can be increased by about 1% when theinlet 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 powerplant such as 1600 MW, the heat content in the inlet air can be sufficient to regasify a small 6
  7. 7. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005LNG receiving terminal, as explained in the subsequent section. One of the first plants usingthis concept with LNG for gas turbine inlet cooling is the Dominican Republic LNG receivingterminal. This plant uses a glycol-water solution that circulates between the LNG regasificationplant and a chiller coil at the gas turbine inlet. 125 120 Power Output, % 115 110 105 100 100 90 80 70 60 50 40 Ambient Temperature, ° F Figure 4 - Combined Cycle Power Plant Outputs vs Ambient TemperaturesThe other advantage of gas turbine inlet air-cooling is that it decouples power generationcapacity from changes in ambient temperature and relative humidity. Power plants typicallyexperience a drop in power output during summer when ambient temperature increases abovedesign. 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 maintainedthroughout the year. This power increase is gained without external refrigeration. Theincremental cost per kW installed power is significantly less than a conventional unit. The aircooler system design would include the air cooling coils and the glycol circulation system. It istherefore preferred to have the power plant located in close proximity to the regasificationterminal to further reduce the installation cost.Depending on the heat balance between the LNG regasification duty and the chilled airrequirement, excessive chilled glycol-water may be also available. In this case, the excessiverefrigeration can be used to chill the cooling water supply temperature to the combined cyclepower plant. This will effectively lower the steam turbine surface condenser pressure which inturns lowers the steam turbine back-pressure, resulting in a higher steam turbine output andpower generation efficiency.Integrated LNG Regasification/Power GenerationThe conceptual design of an integrated plant for a gas turbine simple cycle power plant isdepicted in Figure 5. Power is produced in a combination of three separation steps: 7
  8. 8. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005 • Mixed Fluid Power cycle • Gas turbine combustion air cooling • Fuel gas saturator using condensate recovered from the gas turbine inlet FUEL GAS AIR SATURATOR PRECOOLER STACK E-6 X-1 V-1 V-2 AIR FUEL GAS E-5 P- 6 GT-1 P- 4 E- 3 P- 5 EP-1 E-2 NATURAL GAS LNG FROM E-1 E-4 TO PIPELINE STORAGE MIXED FLUID P-1 POWER CYCLE P- 3 P- 2 Figure 5 – Integration of LNG Regasification to a Gas Turbine Power PlantThe use of the mixed fluid power cycle and air chilling using the refrigeration released from LNGregasification, described in the previous sections, are sequentially applied in this integratedprocess.A thermally stable heat transfer fluid, such as Dowtherm, can be used to transfer waste heatfrom the gas turbine exhaust to the Rankine power cycle. Per Figure 5, the heat mediumpump, P-5, is used to transfer heat from the heat recovery exchanger, E-6, to the heatexchanger, E-3. In a similar manner, LNG indirectly cools the gas turbine inlet air with the useof a heat transfer fluid which can be an ethylene glycol water mixture, propylene glycol watermixture or methanol. The glycol mixture is pumped by the glycol pump, P-3, circulating betweenthe 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. Thecondensate can be used as makeup water to a combined cycle power plant, reducing itsdemineralized water makeup requirement. 8
  9. 9. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005When a simple gas turbine cycle is used, the condensate from the air cooler can be vaporizedinto the fuel gas to the gas turbine, thereby further increasing the mass flow, and power outputfrom the gas turbine. This can be achieved by circulating a hot water loop using pump P-2 andwith a saturator column V-2 for heat and mass transfer. The low level heat from the gas turbinedischarge is transfer to vaporize the water to the fuel gas prior to the combustor X-1 of the gasturbine.Beside additional power generation due to the high mass flow to the gas turbine, fuel gasmoisturization can effectively lower the flame temperature at the combustion chamber of the gasturbine, 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 LNGregasification is of primary importance in an integrated facility. Typically, power generationvaries with consumer demands that in turns results in fluctuation of the available waste heat. Onthe other hand, the heat input to a base-load LNG regasification plant is constant. For thisreason, backup heat sources, such as duct firing in the gas turbine, or steam boiler must beused to ensure the total availability of the heat source to the LNG regasification facility.Integration to a 140 MW Gas Turbine Simple Cycle Power PlantTable 3 compares the previously described integrated plant to the standalone plants for a 1,200MMscfd LNG regasification terminal. Both seawater regasification and submerged combustiontype regasification plants are compared. Power from the integrated plant is compared to aconventional combined cycle power plant based on a 141 MW gas turbine and a 68.4 MWsteam turbine generator. Seawater LNG Combustion LNG Integrated LNG Regas. (ORV) + Regas. (SCR) + Power Standalone CCU Standalone CCU Generation LNG Regasification: Seawater Flow rate, GPM 100,000 None None LNG Pumps, MW 8.0 8.0 8.0 Seawater Pumps, MW 6.0 0.0 0.0 Fuel fired, MM Btu/hr 0.0 800.0 0.0 Mixed Fluid Cycle, MW 0.0 0.0 111.0 Power Production, MW -14.0 -8.0 103.0 Power Plant: Combustion Air Inlet, °F 90 90 40 Gas Turbine, MW 141.0 141.0 191.8 Steam Cycle MW 68.4 68.4 None Cooling Water, GPM 40,000 40,000 None Total Power Plant, MW 209 209 191.8 Power Plant Fuel, MM Btu/hr LHV 1,463 1,463 1,808 Total Fuel Gas, MM Btu/hr LHV 1,463 2,263 1,808 Net Power Output, MW 195.5 201.5 294.8 Power Generation Efficiency, Btu/kW-hr 7,487 11,235 6,133 Table 3 – Comparison of Power Generation of Integrated to Standalone LNG Plant 9
  10. 10. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005Conventional LNG regasification requires about 100,000 gpm of seawater or 800 MM Btu/hr offuel gas consumption for a 1,200 MMscfd sendout flow. The integrated facility has eliminatedthese requirements with the use of the condensation duty from the mixed fluid Rankine cycle asa source of heat. The Mixed Fluid Rankine cycle produces a gross 111 MW and a portion ofthis 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 notrequired, and hence the associated cooling water system can be eliminated, which significantlyreduces the capital, operating and maintenance costs of the power plant. The power outputfrom the gas turbine is increased from 141 MW to 192 MW, which is a result of the newconfigurations 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 fuelgas consumed in the ORV combined cycle option, mainly to the significantly higher poweroutput of the integrated design. When compared to the SCV combined cycle option, theintegrated plant consumes significantly less fuel gas while producing more power. The plantperformances should be compared for their power generation efficiencies. The integrated facilityachieves 6,133 Btu/kW-hr which is significantly higher than conventional standalone designs.Integration to a 1,600 MW Combined Cycle Power PlantWhen a large power plant is considered, the heat content in the gas turbine inlet air can besufficient to supply the heating requirement of a LNG regasification terminal. The design of thisintegrated system would use a glycol water solution or methanol to transfer the cooling dutyfrom the LNG regasification plant to the air chillers in the power plant. The process flowconfiguration 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 LNGterminal and a 1,600 MW combined cycle power plant. The site is located in a mildly climateregion 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 tobelow freezing. The case study was to evaluate if this site is suitable for thermal integrated to anLNG plant.Due to the large power plant capacity, the gas turbine inlet air during summer would providemore than adequate heating to the LNG regasification terminal. However, during the few wintermonths, when the ambient drops below 50°F, there is not sufficient heat that is needed to meetthe regasification duty of the 500 MMscfd LNG sendout rate. Additional heat source must bemade available. To circumvent the heat balance problem, the cooling water to the power plant isused to for heating the glycol water solution. The heat rejection of a 1,600 MW combined cyclepower plant can easily accommodate the additional heating duty. Additionally, this operationhas a side benefit, as the lower cooling water temperature will effectively lower the steamturbine surface condenser pressure of the steam power plant. This, in turns, will lower thesteam turbine back-pressure, resulting in a higher steam turbine output and power generationefficiency. 10
  11. 11. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005 STEAM TURBINES 1,600 MW CCU AIR PRECOOLER CWR HRSG GAS TURBINES WINTER OPERATION CWS GLYCOL 500 MMSCFD LNG LNG SECONDARY VAPORIZERS PUMPS 300 MMBtu/h Figure 6 – Integration of LNG Regasification to a 1600 MW Combined Cycle Power PlantPower Output from 1600 MW Combined Cycle Power PlantThe result of the power increases from a 1600 MW combined cycle power plant using gasturbine air chilling for the mildly climate site is shown in Figure 7. The Y-axis of this graphshows the number of hours and the corresponding ambient temperatures and is graphedagainst 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 poweroutput of the 1600 MW power plant by about 80 to 100 MW. The increase in power outputduring summer is particularly important as the consumer power demands during this period arealso higher. For the standalone non-integrated power plant, its power output would drop toabout 1450 MW due to the high ambient temperature. With the integrated system, the poweroutput during summer can be increased to about 1550 MW, a 100 MW increase over thestandalone non-integrated case. Additionally, the water condensed from the gas turbine inlet aircan be utilized to supply the boiler feed water makeup requirement in the combined cycle powerplant which reduces the requirement of the demineralization system. 11
  12. 12. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005 102 Integrated with 5 95 Air Chilling 30 Number of hours Ambient Temperature, deg F 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 1,750 Power Output, MW Figure 7 – Power output from a 1600 MW Combined Cycle Power PlantLNG Heating Values and CompositionsOne of the problems in LNG receiving terminals is accepting rich LNG with non-compliantheating values. As the LNG import market grows, spot LNG trades will become common, as intoday’s crude oil trade market. With increasing LNG trading traffics between the different LNGproducers and the North America regasification sites, the LNG terminals must be ready toaccept LNG carriers from different sources with various compositions and heating values. Insome markets, the rich LNG can be made profitable as its propane content can be sold as LPGand the butane plus liquid can be used for gasoline blending. Additionally, processing steps forextraction of the heavier components from the rich LNG are necessary to meet the stringentNorth America pipeline heating value specification.In upstream LNG liquefaction plants, removal of the pentane, hexane and heavier hydrocarbonsis required only to avoid wax formation inside the cryogenic liquefaction exchanger. The LPGcomponents (C2, C3 and C4+) are not removed and liquefied together with the methanecomponent, resulting in LNG with a fairly high gross heating value. The heating values of LNGfrom a number of LNG export plants in the Atlantic, Pacific Ocean and Middle East LNG plantsare shown in Figure 8. The higher heating values indicate a higher proportion of the non-methane components. The compositions of the ethane, propane, and butane and heaviercomponents for these LNG are shown in Figure 9. 12
  13. 13. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005In North America, many pipeline operators require very lean gas for transmission, and in somemid-west regions, natural gas gross heating value ranges between 960 and 1050 Btu/scf. InCalifornia, the acceptable gross heating value is between 970 and 1150 Btu/scf. California alsoimposes constraints on specific gas components for compressed natural gas consumption.Currently, acceptable LNG that meets the California specification is limited to sources such asthe Kenai, Alaska LNG [4], or the Atlantic LNG from Trinidad.To meet the North American natural gas specifications, these regasification terminals must havefacilities that are capable of processing these non-compliant LNG [3]. The common method ofcontrolling the LNG heating value and Wobbe Index is by dilution with nitrogen or blending witha leaner natural gas. However, there are also limits on the maximum amount of nitrogen andinerts that can be introduced to the pipeline gas. The dilution with nitrogen would require an airseparation plant which is costly and produces no benefit for the facility. A lean gas source ismostly likely not available for blending in a large LNG regasification facility. 1200Higher Heating Value, Btu/Scf 1150 1100 1050 1000 950 Arun LNG Ras Laffan Abu Dhabi Indonesia Trinidad Northwest Kenai Brunei Oman Shelf Figure 8- LNG Energy Content for Selected Atlantic, Pacific and Middle East Plants [4] 13
  14. 14. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005 18 16 Hexane + 14 Ethane Propane to Pentane Component, % 12 10 8 6 4 2 0 Malaysia Trinidad Brunei Indonesia Kenai Oman Arun LNG Figure 9– Non-Methane Constituents for Selected Atlantic, Pacific and Middle East Plants [4]Onshore LNG BTU Reduction and LPG ProductionThe LPG components in LNG are of high quality as all the contaminants, water and heavyhydrocarbons have been removed in the liquefaction process. LPG from LNG can be sold as aclean 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 operatingcosts than conventional NGL recovery processes. Costly gas treating, conditioning andprocessing units, such as gas treating, dehydration, turbo-expander, refrigeration and residuegas compression are not required. Typically, the power requirement to process 1,200 MMscfdfeed gas is 60,000 HP or 44.7 MW, which is mainly used for chilling the feed gas andrecompressing the residue lean gas. The LPG fractionation process shown in Figure 10eliminates these units and their energy consumption. This process can achieve 99% propanerecovery without gas chilling and recompressing requirements. 14
  15. 15. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005 LEAN RESIDUE GAS E-4 (1050 BTU/SCF) LNG REGASIFICATION USING RANKINE POWER CYCLE P- 5 RICH LNG E-4 V-3 V-2 P-1 EP- 2 V-1 E-5 C2, C3 and C4 + P-3 P-4 Figure 10 – Onshore LNG BTU ReductionPer Figure 10, LNG send-out rate of 1,200 MMscfd is pressurized by LNG pump P-1 to about500 psig and fed to the LPG fractionation unit. The LNG cold is utilized in the brazed aluminumtype exchanger E-4. This exchanger serves dual functions. First, this exchanger uses LNGcold to condense the deethanizer, V-3 overhead to produce an ethane rich cold reflux to thedeethanizer. Secondly, the exchanger condenses the lean residue gas, allowing the condensedliquid to be pumped to the gas pipeline pressure. This eliminates costly gas compressionsystems.After heat exchange in E-4, LNG is heated to about -90°F and is partially vaporized. The two-phase stream is separated in vessel V-2. The flashed vapor is fed to the upper rectificationtrays 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 exchangerE-5 to about 600°F. The high-pressure high-temperature vapor is expanded in expander EP-2to 460 psig, generating power. The expander discharge vapor, which is quite warm, typically at300°F, is used as a stripping vapor in the fractionator. The stripping vapor can supply most ofthe 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 overheadvapor is cooled to about -105°F in exchanger E-4 and partially condensed. The condensedliquid is separated in reflux drum, V-1 and is returned to the deethanizer as reflux using thereflux 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 pumpedby pump P-5 to about 1100 psig as required for pipeline transmission. This re-condensationand pumping operation is more energy efficient and less costly than the residual gas re- 15
  16. 16. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005compression in a conventional NGL recovery plant.The lean LNG at -140°F still contains a significant amount of cold energy that can be furtherutilized. The cold energy can be used in the LNG regasification exchanger E-4, for combustionair cooling to increase power output from a gas turbine or for power generation using the MixedFluid power cycle, as previously described. When used in a Rankine cycle, due to the leanerLNG composition, the composition of the multi-component fluid must be adjusted to match theheat curve of the leaner LNG.The hot and cold composite curves of the integration scheme are shown in Figure 11. Theclose matches between the LNG regasification curve and the utilization curve result in highefficiency of the integrated process.The overall balance for a 1,200 MMscfd Integrated LPG Fractionation/LNG RegasificationFacility is shown in Table 4. This facility produces 40,700 BPD of propane plus product, 31,200BPD of ethane and 1,094 MMscfd of 1,021 Btu/SCF HHV pipeline gas. The propane plusproduct can be separated into a LPG liquid fuel for the local market and butane plus used forgasoline blending at local refineries.Ethane production would require a second column, the deethanizer, to fractionate the ethanefrom the C3 LPG product. The first column would operate as a demethanizer producing anethane and heavier bottoms product to be processed in the second column which furtherfractionates into the ethane and the C3 LPG fraction. In the integrated scheme, the cold fromLNG can be effectively utilized in refluxing the columns, eliminating external refrigeration andcompression requirements. Component, LNG Feed LPG Fraction Ethane Pipeline Gas Mol Fraction N2 0.0034 0.0000 0.0000 0.0036 C1 0.8976 0.0000 0.0215 0.9439 C2 0.0501 0.0100 0.9585 0.0517 C3 0.0316 0.6277 0.0200 0.0009 IC4 0.0069 0.1442 0.0000 0 NC4 0.0103 0.2160 0.0000 0 NC5 0.0001 0.0021 0.0000 0 Gross Heat Value, Btu/SCF 1,137 2,850 1,787 1,021 MMscfd 1,200 57 49 1,094 Barrels per day NA 40,700 31,200 NA Table 4 – C2, and LPG Production Overall Balance 16
  17. 17. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005 Power Production 150 100 E-1 Temperature, °F 50 LPG Production 0 -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 ProcessOffshore LNG BTU Reduction and LPG ProductionBuilding offshore LNG terminals is significantly more expensive than building onshore terminals.Installation of an LPG fractionation facility in the offshore gravity based structure is particularlyexpensive. Liquid product storage, liquid handling and liquid product loading facilities wouldfurther add to the cost of the facilities. Operating these facilities with limited offshore staffingmay also be difficult. Therefore, current offshore terminals are limited to the essential facilitiessuch as LNG unloading, pumping and regasification. LPG extraction facilities are better to bedeferred until the natural gas reaches onshore.The following describes a new process (patent pending) that is suitable for extracting the LPGcomponents in an offshore LNG terminal to meet the heating value content of the sales gaspipeline specifications. This process consists of an offshore regasification plant and an onshoreLPG extraction plant, as shown in Figure 12.The offshore plant uses the Rankine power cycle (previously described) to supply heat for LNGregasification while generating power for the offshore facility. The Rankine power cycle canproduce about 80 MW of electric power using the waste heat from the gas turbine exhaust. 17
  18. 18. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005The onshore plant can recover 97% of the propane, virtually all the butane plus components. Ifnecessary, about 70% of the ethane can be recovered from the LNG. Unlike most conventionalNGL extraction process, this process does not require external refrigeration and gascompression and can be operated at various levels of ethane recovery to meet the ethanemarket demands. ONSHORE BTU-REDUCTION UNIT SALES GAS -127°F E-1B C2 C-2 EP-1 E-2 -106°F E-1A 1150 psig, 450 psig 230 psig -35°F -70°F V-1 V-2 V-3 DEC1 DEC2 -11°F E-1A/B C-1 EP-2 E-4 E-3 C3 + 1600 psig, 119°F UNDERSEA PIPELINE 0°F OFFSHORE LNG REGASIFICATION 1650 PSIG POWER LNG EXPORT REGASIFICATION/ POWER CYCLE HP LNG PUMP LNG CARRIER -260°F GBS LNG LP LNG STORAGE PUMP Figure 12 – Offshore LNG Regasification Process with Onshore BTU Reduction UnitPer Figure 12, LNG from the storage tank is pumped by the low pressure LNG pump to anintermediate pressure such as 100 psig, and then pumped by the high pressure LNG pump tosupercritical pressure, typically 1650 or higher depending on the length of the undersea pipeline 18
  19. 19. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005and the LNG composition. LNG is then heated and partially regasified to about 0°F using thecondensation duty from Rankine power cycle.It is important to note that the LNG is only partially regasified to 0°F instead of completelyregasified to 40°F. Also the operating pressure of 1600 psig is higher that the final gas pipelinepressure requirement. The high pressure and low temperature of the semi-regasified LNGeffectively preserves the refrigeration content in LNG that is needed in the offshore fractionationfacility. Also the regasification duty at 1650 psig and 0°F is significantly less than that of thetypical conventional design at 800 psig and 40°F.The supercritical fluid arrives onshore at about 1650 psig and is letdown in pressure to about1100 psig in the first stage turbo-expander, EP-1, which generates power to operate the secondstage 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, E-1A, 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 vaporare separately fed to the demethanizer, V-2. To improve NGL recovery levels, vapor from V-1 issplit into two portions with one portion routed to the reflux condenser, E-2, for refluxing thedemethanizer column. The remaining portion is letdown in pressure in the second stage turbo-expander, EP-2, which generates sufficient power to operate the first stage residue gascompressor, C-1. This expansion process chills the gas to about -70°F, supplying thedemethanizer cooling requirements.The reflux stream is chilled to about -106°F by heat exchange with the demethanizer overheadin E-2. This stream is then letdown in pressure in a JT valve and fed to the top of thedemethanizer as reflux. The flow to this exchanger is lowered when a lower ethane recovery isdesired. The process can also operate in an ethane rejection mode, that is, only propane plusrecovery, to meet fluctuations in the ethane and energy markets.The demethanizer operates at about 450 psig, producing a lean overhead gas and a NGLbottom product. The NGL product methane content is minimized with heat supplied by thereboiler, 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 thedemethanizer bottoms into an ethane overhead vapor and a propane plus LPG product.With the two stage turboexpander/compressor system, the demethanizer overhead gas can becompressed to about 800 psig. If higher delivery pressure is required, a booster compressorcan be added. 19
  20. 20. FLUOR 5rd Annual Atlantic Canada Oil and GasLNG Regasification and Utilization Halifax, Nova Scotia May 30-31, 2005ConclusionsCurrent LNG regasification plants under construction have not taken the advantage of theinherent cold energy in LNG and many are facing the emissions and environmental problemsassociated with conventional LNG regasification. While permitting these facilities takes time,efforts must be devoted to include LNG cold utilization and improve the current LNGregasification practices.Future LNG regasification terminals must therefore be designed to accommodate the ever-changing landscape of the environmental and regulation requirements and advances intechnologies. Life cycle costs of the regasification facilities must be evaluated against initialcapital costs in a competitive LNG market. Thermal integration with a power plant, in a Rankinecycle or a combined cycle configuration is a natural progression, which would reduce thecombined plant cost and increase in overall thermal efficiency.The LNG receiving terminals, onshore or offshore, must be designed to receive the rich LNGthat must be re-conditioned for reduction of its BTU value to meet the North American pipelinespecifications. The extraction of LPG and butane and heavier components from LNG willprovide additional revenues, and will improve the overall economics of the LNG receivingterminals.References Cited1. 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