WO2008063732A2

WO2008063732A2 - Liquefied natural gas plant with enhanced operating flexibility

Info

Publication number: WO2008063732A2
Application number: PCT/US2007/077624
Authority: WO
Inventors: Weldon L. Ransbarger; Jon M. Mock; Cyrus B. Meher-Homji
Original assignee: Conocophillips Company
Priority date: 2006-11-16
Filing date: 2007-09-05
Publication date: 2008-05-29
Also published as: US20080115529A1; AR062870A1; WO2008063732A3; PE20081108A1; CL2007002675A1

Abstract

A method of increasing the production rate and operational flexibility of an LNG facility by overfiring one or more modular gas turbines employed to drive one or more refrigerant compressors in the LNG facility.

Description

LIQUEFIED NATURAL GAS PLANT WITH ENHANCED OPERATING FLEXIBILITY

BACKGROUND OF THE INVENTION 1. Field of the Invention

This invention relates to a method for liquefying natural gas. In another aspect, the invention concerns a method of improving the operational flexibility of a liquefied natural gas (LNG) facility employing one or more modular gas turbines. 2. Description of the Prior Art The cryogenic liquefaction of natural gas is routinely practiced as a means of converting natural gas into a more convenient form for transportation and/or storage. Generally, liquefaction of natural gas reduces its volume by about 600-fold, thereby resulting in a liquefied product that can be readily stored and transported at near atmospheric pressure. Natural gas is frequently transported by pipeline from the supply source to a distant market. It is desirable to operate the pipeline under a substantially constant and high load factor, but often the deliverability or capacity of the pipeline will exceed demand while at other times the demand will exceed the deliverability of the pipeline. In order to shave off the peaks where demand exceeds supply or the valleys where supply exceeds demand, it is desirable to store the excess gas in such a manner that it can be delivered as the market dictates. Such practice allows future demand peaks to be met with material from storage. One practical means for doing this is to convert the gas to a liquefied state for storage and to then vaporize the liquid as demand requires.

The liquefaction of natural gas is of even greater importance when transporting gas from a supply source that is separated by great distances from the candidate market, and a pipeline either is not available or is impractical. This is particularly true where transport must be made by ocean-going vessels. Ship transportation of natural gas in the gaseous state is generally not practical because appreciable pressurization is required to significantly reduce the specific volume of the gas, and such pressurization requires the use of more expensive storage containers.

In view of the foregoing, it would be advantageous to store and transport natural gas in the liquid state at approximately atmospheric pressure. In order to store and transport natural gas in the liquid state, the natural gas is cooled to -240⁰F to -260⁰F where the liquefied natural gas (LNG) possesses a near-atmospheric vapor pressure. Numerous systems exist in the prior art for the liquefaction of natural gas in which the gas is liquefied by sequentially passing the gas at an elevated pressure through a plurality of cooling stages whereupon the gas is cooled to successively lower temperatures until the liquefaction temperature is reached. Cooling is generally accomplished by indirect heat exchange with one or more refrigerants such as propane, propylene, ethane, ethylene, methane, nitrogen, carbon dioxide, or combinations of the preceding refrigerants (e.g., mixed refrigerant systems). A liquefaction methodology which may be particularly applicable to one or more embodiments of the present invention employs an open methane cycle 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 LNG-bearing stream.

Operational flexibility gives an LNG facility the ability to manipulate its LNG production rate to effectively capitalize on instantaneous market conditions due to favorable fluctuations in supply and/or demand. However, in general, the operational flexibility of an LNG facility is affected by factors such as operational upsets, seasonal changes in ambient conditions, equipment maintenance requirements, and problems with supply chain logistics, which often force an LNG facility to reduce its natural gas production rate. Operational flexibility of large-scale LNG facilities can be further limited by its single-shaft industrial gas turbines, which have require complex starting equipment and extensive maintenance outages.

Thus, a need exists a method for increasing the operational flexibility of an LNG facility in a way that minimizes equipment downtime and maximizes production rate.

SUMMARY OF THE INVENTION

In one embodiment of the present invention, there is provided a method of operating a first modular gas turbine employed in an LNG facility. The method comprises overfiring the gas turbine for at least about 6 hours per day for a period of at least 2 days. The overfiring causes the power output of the gas turbine to increase by at least about 5 percent over its power output prior to overfiring.

In another embodiment of the present invention, there is provided a method of operating a modular gas turbine employed in an LNG facility. The method comprises the steps of: (a) determining the operating severity of the turbine; (b) calculating an actual maintenance frequency of the turbine according to the operating severity; (c) comparing the actual maintenance frequency of the turbine to a predicted maintenance frequency to determine a difference; and (d) creating an updated maintenance frequency according to the results of step (c).

In yet another embodiment of the present invention, there is provided a process for producing liquefied natural gas at an LNG facilityjocation where the average ambient air temperature was less than 50⁰F for at least two calendar months of at least one calendar year from 1995 to 2005. The process comprises using a modular gas turbine to drive a refrigerant compressor of the LNG facility.

BRIEF DESCRIPTION OF THE FIGURES

Certain embodiments of the present invention are described in detail below with reference to the enclosed figure, wherein:

FIG. 1 is a simplified flow diagram of an LNG facility employing three refrigerant compressors driven by modular gas turbines.

DETAILED DESCRIPTION

The present invention can be implemented in a process/facility used to cool natural gas to its liquefaction temperature, thereby producing liquefied natural gas (LNG). The LNG process generally employs one or more refrigerants to extract heat from the natural gas and then reject the heat to the environment. In one embodiment, the LNG process employs a cascade-type refrigeration process that uses a plurality of multistage cooling cycles, each employing a different refrigerant composition, to sequentially cool the natural gas stream to lower and lower temperatures. In another embodiment, the LNG process is a mixed refrigerant process that employs a combination of two or more refrigerants to cool the natural gas stream in at least one cooling cycle.

Natural gas can be delivered to the LNG process at an elevated pressure in the range of from about 500 to about 3,000 pounds per square in absolute (psia), about 500 to about 1,000 psia, or 600 to 800 psia. Depending largely upon the ambient temperature, the temperature of the natural gas delivered to the LNG process can generally be in the range of from about 0 to about 180⁰F, or about 20 to about 150⁰F, or 60 to 125°F.

In one embodiment, the present invention can be implemented in an LNG process that employs cascade-type cooling followed by expansion-type cooling. In such a liquefaction process, the cascade-type cooling may be carried out in a mechanical refrigeration cycle at an elevated pressure (e.g., about 650 psia) by sequentially passing the natural gas stream through first, second, and third refrigeration cycles employing respective first, second, and third refrigerants. In one embodiment, the first and second refrigeration cycles are closed refrigeration cycles, while the third refrigeration cycle is an open refrigeration cycle that utilizes a portion of the processed natural gas as a source of the refrigerant. Further, the third refrigeration cycle can include a multi-stage expansion cycle to provide additional cooling of the processed natural gas stream and reduce its pressure to near atmospheric pressure.

In the sequence of first, second, and third refrigeration cycles, the refrigerant having the highest boiling point can be utilized first, followed by a refrigerant having an intermediate boiling point, and finally by a refrigerant having the lowest boiling point. In one embodiment, the refrigerant can be a hydrocarbon-containing refrigerant. In another embodiment, the first refrigerant has a mid-boiling point at standard temperature and pressure (i.e., an STP mid-boiling point) within about 20, about 10, or 5°F of the STP boiling point of pure propane. The first refrigerant can contain predominately propane, propylene, or mixtures thereof. The first refrigerant can contain at least about 75 mole percent propane, at least 90 mole percent propane, or can consist essentially of propane. In one embodiment, the second refrigerant has an STP mid-boiling point within about 20, about 10, or 5°F of the STP boiling point of pure ethylene. The second refrigerant can contain predominately ethane, ethylene, or mixtures thereof. The second refrigerant can contain at least about 75 mole percent ethylene, at least 90 mole percent ethylene, or can consist essentially of ethylene. In one embodiment, the third refrigerant has an STP mid-boiling point within about 20, about 10, or 5°F of the STP boiling point of pure methane. The third refrigerant can contain at least about 50 mole percent methane, at least about 75 mole percent methane, at least 90 mole percent methane, or can consist essentially of methane. At least about 50, about 75, or 95 mole percent of the third refrigerant can originate from the processed natural gas stream.

The first refrigeration cycle can cool the natural gas in a plurality of cooling stages/steps (e.g., two to four cooling stages) by indirect heat exchange with the first refrigerant. Each indirect cooling stage of the refrigeration cycles can be carried out in a separate heat exchanger. In the one embodiment, core-and-kettle heat exchangers are employed to facilitate indirect heat exchange in the first refrigeration cycle. After being cooled in the first refrigeration cycle, the temperature of the natural gas can be in the range of from about -45 to about -10⁰F, or about -40 to about -15°F, or about -20 to - 30⁰F. A typical decrease in the natural gas temperature across the first refrigeration cycle may be in the range of from about 50 to about 210⁰F, about 75 to about 18O⁰F, or 100 to 140⁰F.

The second refrigeration cycle can cool the natural gas in a plurality of cooling stages/steps (e.g., two to four cooling stages) by indirect heat exchange with the second refrigerant. In one embodiment, the indirect heat exchange cooling stages in the second refrigeration cycle can employ separate, core-and-kettle heat exchangers. Generally, the temperature drop across the second refrigeration cycle can be in the range of from about 50 to about 180⁰F, about 75 to about 150⁰F, or 100 to 120⁰F. In the final stage of the second refrigeration cycle, the processed natural gas stream can be condensed (i.e., liquefied) in major portion, preferably in its entirety, thereby producing a pressurized LNG-bearing stream. Generally, the process pressure at this location is only slightly lower than the pressure of the natural gas fed to the first stage of the first refrigeration cycle. After being cooled in the second refrigeration cycle, the temperature of the natural gas may be in the range of from about -205 to about -70°, about -175 to about -95⁰F, or - 140 to -125⁰F.

The third refrigeration cycle can include both an indirect cooling section and an expansion-type cooling section. To facilitate indirect heat exchange, the third refrigeration cycle can employ at least one brazed-aluminum plate-fin heat exchanger. The total amount of cooling provided by indirect heat exchange in the third refrigeration cycle can be in the range of from about 5 to about 6O⁰F, about 7 to about 5O⁰F, or 10 to 4O⁰F.

The expansion-type cooling section of the third refrigeration cycle can further cool the pressurized LNG-bearing stream via sequential pressure reduction to approximately atmospheric pressure. Such expansion-type cooling can be accomplished by flashing the LNG-bearing stream to thereby produce a two-phase vapor-liquid stream. When the third refrigeration cycle is an open refrigeration cycle, the expanded two-phase stream can be subjected to vapor-liquid separation and at least a portion of the separated vapor phase (i.e., the flash gas) can be employed as the third refrigerant to help cool the processed natural gas stream. The expansion of the pressurized LNG-bearing stream to near atmospheric pressure can be accomplished by using a plurality of expansion steps (i.e., two to four expansion steps) where each expansion step is carried out using an expander. Suitable expanders include, for example, either Joule-Thomson expansion valves or hydraulic expanders. In one embodiment, the third stage refrigeration cycle can employ three sequential expansion cooling steps, wherein each expansion step can be followed by a separation of the gas-liquid product. Each expansion-type cooling step can further cool the LNG-bearing stream in the range of from about 10 to about 60⁰F, about 15 to about 50⁰F, or 25 to 35⁰F. The reduction in pressure across the first expansion step can be in the range of from about 80 to about 300 psia, about 130 to about 250 psia, or 175 to 195 psia. The pressure drop across the second expansion step can be in the range of from about 20 to about 1 10 psia, about 40 to about 90 psia, or 55 to 70 psia. The third expansion step can further reduce the pressure of the LNG-bearing stream by an amount in the range of from about 5 to about 50 psia, about 10 to about 40 psia, or 15 to 30 psia. The liquid fraction resulting from the final expansion stage is the final LNG product. The liquid fraction resulting from the final expansion stage is the LNG product. Generally, the temperature of the LNG product can be in the range of from about -200 to about -300⁰F, about -225 to about -275⁰F, or -240 to -260⁰F. The pressure of the LNG product can be in the range of from about 0 to about 40 psia, about 10 to about 20 psia, or 12.5 to 17.5 psia.

The natural gas feed stream to the LNG process will usually contain such quantities of C2+ components so as to result in the formation of a C2+ rich liquid in one or more of the cooling stages of the second refrigeration cycle. Generally, the sequential cooling of the natural gas in each cooling stage is controlled so as to remove as much of the C2 and higher molecular weight hydrocarbons as possible from the gas, thereby producing a vapor stream predominating in methane and a liquid stream containing significant amounts of ethane and heavier components. This liquid can be further processed via gas-liquid separators employed at strategic locations downstream of the cooling stages. In one embodiment, one objective of the gas/liquid separators is to maximize the rejection of the C5+ material to avoid freezing in downstream processing equipment. The gas/liquid separators may also be utilized to vary the amount of C2 through C4 components that remain in the natural gas product to affect certain characteristics of the finished LNG product.

The exact configuration and operation of gas-liquid separators may be dependant on a number of parameters, such as the C2+ composition of the natural gas feed stream, the desired BTU content of the LNG product, the value of the C2+ components for other applications, and other factors routinely considered by those skilled in the art of LNG plant and gas plant operation. In one embodiment of the present invention, the C2+ hydrocarbon stream or streams may be demethanized via a single stage flash or a fractionation column. The gaseous methane-rich stream can be directly returned at pressure to the liquefaction process. The resulting heavies-rich liquid stream may then be subjected to fractionation in one or more fractionation zones to produce individual streams rich in specific chemical constituents (e.g., C₂, C₃, C₄, and C₅+).

Each refrigeration cycle of the LNG facility of the present invention can include a refrigerant compressor operably coupled to a gas turbine driver. In one embodiment, the gas turbine can be a modular gas turbine. As used herein, the term "modular" refers to a turbine having interchangeable segments. A modular gas turbine may expedite the required time a turbine is offline for maintenance by allowing one interchangeable segment to be repaired offline while the turbine operates with a replacement interchangeable segment. Examples of modular turbines include Siemens SMS-600 or SMS-700 gas turbines (available from Siemens AG in Erlangen, Germany) and Solar Mars© or Titan™ gas turbines (available from Solar Turbines Incorporated in Peoria, Illinois) or the equivalent thereof. In another embodiment of the present invention, the gas turbine driver can have a single-shaft or multi-shaft configuration.

According to one embodiment of the present invention, the gas turbine can be an aeroderivative gas turbine. As used herein, the term "aeroderivative gas turbine" refers to a gas turbine based on an aircraft engine design that has been adapted for industrial use. Examples of aeroderivative gas turbines include, for example, a GE LMl 600, LM2000, LM2500, LM2500+, LM6000, or LMS- 100® (available from GE Power Systems in Atlanta, GA) or the equivalent thereof. In one embodiment, the gas turbine employed in the inventive LNG facility has a rated power output of greater than about 20 megawatts (MW), greater than about 30 MW, greater than about 35 MW, or greater than 40 MW at ISO standard conditions. In another embodiment, the gas turbine of the present invention has a thermal efficiency of greater than about 30, greater than about 35, greater than about 37, greater than about 40, or greater than 44 percent at ISO standard conditions.

In one embodiment, the inventive LNG facility has a production rate greater than about 1.0 million, greater than about 2.0 million, greater than about 3.0 million, greater than about 3.8 million, or greater than 4.0 million metric tons per annum (mtpa). In accordance with one embodiment of the present invention, the production rate of the inventive LNG facility may be increased by more than about 3 percent, more than about 5 percent, or more than about 7 percent by overfiring one or more gas turbines used to drive one or more refrigerant compressors. , As used herein, the term "overfiring" refers to increasing one or more turbine operating parameters above the manufacturer-provided base-load values, also referred to herein as rated values. Turbine manufacturers provide rated values for operating parameters such as, for example, firing temperature, air compressor discharge pressure, exhaust temperature, and the like in order to characterize turbine performance. According to one embodiment of the present invention, overfiring can be at least partly caused by increasing the fuel-to-air ratio. In one embodiment, overfiring results in an increase of at least about 5°F, at least about 15°F, at least about 30⁰F, or at least 40⁰F in the firing temperature of the turbine. As a result, the turbine's power output can increase at least about 2 percent, at least about 3 percent, or at least 5 percent above its power output prior to overfiring, under the same conditions. In general, overfiring can occur for at least about 6 hours per day, at least about 8 hours per day, or at least 12 hours per day for a period of at least 2 successive days, at least 7 successive days, or at least 14 successive days. According to one embodiment of the present invention, turbine overfiring can be accompanied by a simultaneous adjustment of the turbine's maintenance frequency. As used herein, the term "maintenance frequency" refers to the time between performing planned or unplanned maintenance on the turbine when the turbine is shut down. In accordance with one embodiment of the present invention, the maintenance frequency for a gas turbine can be modified as a result of overfiring by first determining the operating severity of the turbine. As used herein, the term "operating severity" refers to the current values for turbine operating parameters such as firing temperature, air compressor discharge pressure, exhaust temperature, and the like, as compared to the rated values for the same parameter. For example, finding the difference between the actual firing temperature and the rated firing temperature is one way to determine the operating severity of the compressor.

Next, an actual maintenance frequency can be calculated based on the operating severity of the gas turbine, as described above. The actual maintenance frequency is then compared to a predicted maintenance frequency. In one embodiment, the predicted maintenance frequency can be specified by the turbine manufacturer. Subsequently, an updated maintenance frequency of the turbine can then be calculated according to the difference, if any, between the actual and predicted maintenance frequencies. In one embodiment, the updated maintenance frequency can be at least about 0.5 percent, at least about 1 percent, or at least about 2.5 percent shorter than the predicted maintenance frequency.

In one embodiment, a computer can be used to calculate the updated maintenance frequency according to the inventive procedure described above, and subsequently, the updated maintenance frequency may be used to plan future plant outages. In another embodiment, the updated maintenance frequency calculated via computer may be used to manipulate current turbine operating parameters. In yet another embodiment, the updated maintenance frequency may be used to alter product logistics.

The flow schematic and apparatus illustrated in FIG. 1 represents one embodiment of the inventive LNG facility employing modular gas turbine driven refrigerant compressors. Those skilled in the art will recognize that FIG. 1 is a schematic only and, therefore, many items of equipment that would be needed in a commercial plant for successful operation have been omitted for the sake of clarity. Such items might include, for example, compressor controls, flow and level measurements and corresponding controllers, temperature and pressure controls, pumps, motors, filters, additional heat exchangers, and valves, etc. These items would be provided in accordance with standard engineering practice.

To facilitate an understanding of FIG. 1, the following numeric nomenclature was employed. Items numbered 1 through 99 are process vessels and equipment which are directly associated with the liquefaction process. Items numbered 100 through 199 correspond to flow lines or conduits that contain predominantly methane streams. Items numbered 200 through 299 correspond to flow lines or conduits that contain predominantly ethylene streams. Items numbered 300 through 399 correspond to flow lines or conduits that contain predominantly propane streams. The LNG facility illustrated in FIG. 1 cools the natural gas to its liquefaction temperature using cascade-type cooling in combination with expansion-type cooling. The cascade-type cooling is carried out in three mechanical refrigeration cycles; a propane refrigeration cycle, followed by an ethylene refrigeration cycle, followed by a methane refrigeration cycle. The methane refrigeration cycle includes a heat exchange cooling section followed by an expansion cooling section.

Referring to FIG. 1, the main components of the propane refrigeration cycle include a propane compressor/driver system 11, a propane cooler 12, a high-stage propane chiller 14, an intermediate-stage propane chiller 16, and a low-stage propane chiller 18. The main components of the ethylene refrigeration cycle include an ethylene compressor-driver system 21, an ethylene cooler 22, a high-stage ethylene chiller 24, an intermediate-stage ethylene chiller 26, and a low-stage ethylene chiller/condenser 28, and an ethylene economizer 30. The main components of the methane refrigeration cycle's heat exchange cooling section include a methane compressor/driver system 33, a methane cooler 34, a main methane economizer 36, and a secondary methane economizer 38. The main components of the methane refrigeration cycle's expansion cooling section include a high-stage methane expander 40, a high-stage methane flash drum 42, an intermediate-stage methane expander 44, an intermediate-stage methane flash drum 46, a low-stage methane expander 48, and a low-stage methane flash drum 50. In addition, the LNG facility in FIG. 1 includes a first distillation column 52 and a second distillation column 54 for heavies removal and natural gas liquids (NGL) recovery.

The operation of the LNG facility illustrate in FIG. 1 will now be described in more detail, beginning with the propane refrigeration cycle. Propane compressor/driver system 1 1 is illustrated as generally including an inlet air compressor 13, an inlet air conduit 400, a combustion chamber 15, a fuel conduit 402, a modular turbine 17, and a drive shaft 19 operably coupled to a propane compressor 10. Modular turbine 17 additionally includes two or more modular sections 45. Air is fed into inlet air compressor 13 via conduit 400 and enters combustion chamber 15, wherein it combusts with the fuel stream entering combustion chamber 15 via conduit 402. The resulting energy is used to move modular turbine 17, which imparts rotational power to propane compressor 10 via drive shaft 19. The three stages of compression in propane compressor 10 preferably exist in a single unit, although each stage of compression may be a separate unit and the units mechanically coupled to be driven by a single driver. The compressed propane is discharged from propane compressor 10 and then passed through conduit 300 to propane cooler 12, wherein it is cooled and liquefied via indirect heat exchange with an external fluid (e.g., air or water). A representative pressure and temperature of the liquefied propane refrigerant exiting cooler 12 is about 100⁰F and about 190 psia. The stream from propane cooler 12 is passed through conduit 302 to a pressure reduction means, illustrated as expansion valve 56, wherein the pressure of the liquefied propane is reduced, thereby evaporating or flashing a portion thereof. The resulting two-phase product then flows through conduit 304 into high-stage propane chiller 14. High stage propane chiller 14 uses indirect heat exchange means 4, 6, and 8 to cool respective incoming gas streams, including methane refrigerant in conduit 152, natural gas feed in conduit 100, and ethylene refrigerant in conduit 202. Cooled methane refrigerant gas exits high-stage propane chiller 14 through conduit 154 and is fed to main methane economizer 36, which will be discussed in greater detail in a subsequent section. The cooled natural gas stream, also referred to herein as the methane-rich stream, from high-stage propane chiller 14 flows via conduit 102 to a separation vessel 58 wherein gas and liquid phases are separated. The predominately liquid phase, which can be rich in C3+ components, is removed via conduit 303. The predominately vapor phase is removed via conduit 104 and fed to intermediate-stage propane chiller 16 wherein the stream is cooled via an indirect heat exchange means 62. The resultant vapor/liquid stream is then routed to low-stage propane chiller 18 via conduit 112 wherein it is cooled by an indirect heat exchange means 64. The cooled methane-rich stream then flows through conduit 114 and enters high-stage ethylene chiller 24, which will be discussed further in a subsequent section. The gaseous propane refrigerant from high-stage propane chiller 14 is returned to the high-stage inlet port of propane compressor 10 via conduit 306. The residual liquid refrigerant is passed via conduit 308 through a pressure reduction means, illustrated here as expansion valve 72, whereupon the pressure of the stream is reduced to thereby flush or vaporize a portion thereof. The resulting cooled, two-phase stream enters intermediate-stage propane chiller 16 by means of conduit 310, thereby providing coolant for intermediate-stage chiller 16. The vaporized portion of the propane refrigerant exits intermediate-stage propane chiller 16 via conduit 312 and is fed to the intermediate- stage inlet port of propane compressors 10. The liquid portion flows from intermediate-stage propane chiller 16 through conduit 314 and is passed through a pressure-reduction means, illustrated here as expansion valve 73, whereupon a portion of the propane refrigerant stream is vaporized. The resulting vapor/liquid stream then enters low-stage propane chiller 18 via conduit 316 and acts as a coolant for the methane-rich and ethylene refrigerant streams entering low-stage propane chiller 18 via conduits 112 and 206, respectively. The vaporized propane refrigerant stream then exits low- stage propane chiller 18 and is routed to the low-stage inlet port of propane compressors 10 via conduit 318 wherein the refrigerant is compressed and recycled through the previously described propane refrigeration cycle.

As previously noted, the ethylene refrigerant stream in conduit 202 is cooled in high-stage propane chiller 14 via indirect heat exchange means 8. The cooled ethylene refrigerant stream then exits high-stage propane chiller 14 via conduit 204. The at least partially condensed stream enters intermediate-stage propane chiller 16 wherein it is further cooled by an indirect heat exchange means 66. The two-phase ethylene stream is then routed to low-stage propane chiller 18 by means of conduit 206 wherein the stream is totally condensed or condensed nearly in its entirety via indirect heat exchange means 68. The ethylene refrigerant stream is then fed via conduit 208 to a separation vessel 70 wherein the vapor portion, if present, is removed via conduit 210. The liquid ethylene refrigerant is then fed to the ethylene economizer 30 by means of conduit 212. The ethylene refrigerant at this location in the process is generally at a temperature of about - 24⁰F and a pressure of about 285 psia.

Turning now to the ethylene refrigeration cycle illustrated in FIG. 1 , the ethylene in conduit 212 enters ethylene economizer 30 and is cooled via an indirect heat exchange means 75. The sub-cooled liquid ethylene stream flows through conduit 214 to a pressure reduction means, illustrated here as expansion valve 74, whereupon a portion of the stream is flashed. The cooled, vapor/liquid stream enters high-stage ethylene chiller 24 through conduit 215 wherein it acts as a coolant for the methane-rich stream flowing through an indirect heat exchange means 82. The vapor and liquid portions of the ethylene refrigerant stream exit chiller 24 via conduits 216 and 220, respectively. The ethylene refrigerant vapors are routed back to the ethylene economizer 30, warmed via an indirect heat exchange means 76, and subsequently fed via conduit 218 to the high- stage inlet port of ethylene compressor 20. The liquid portion of the ethylene refrigerant stream is then further cooled in an indirect heat exchange means 78 of ethylene economizer 30. The resulting cooled ethylene stream exits ethylene economizer 30 via conduit 222 and passes through a pressure reduction means, illustrated here as expansion valve 80, whereupon a portion of the ethylene is flashed.

In a manner similar to high-stage ethylene chiller 24, the two-phase refrigerant stream enters intermediate-stage ethylene chiller 26 via conduit 224 and cools the natural gas stream flowing through an indirect heat exchange means 84 via conduit 116. The cooled methane-rich stream exiting intermediate-stage ethylene chiller 26 is totally condensed or condensed nearly in its entirety and is routed via conduit 118 to first distillation column 52 of the heavies removal/NGL recovery section of the inventive LNG facility. The overhead, predominantly vapor product exits first distillation column 52 via conduit 119 and combines with a yet-to-be-discussed stream in conduit 120 prior to entering low-stage ethylene chiller/condenser 28. The predominantly liquid bottoms stream from first distillation column 52 is routed to second distillation column 54 via conduit 121. The bottoms liquid product from second distillation column 54 can be ri chin ethane and heavier components and can be routed to further processing, fractionation, and/or storage via conduit 128. The predominantly methane vapor overhead stream exiting second distillation column 54 in conduit 126 combines with a yet-to-be-discussed stream in conduit 168 prior to entering the high-stage suction port of methane compressor 32.

Turning back to intermediate-stage ethylene chiller 26, the vapor and liquid portions of the ethylene refrigerant stream exit ethylene chiller 26 via conduits 226 and 228, respectively. The gaseous stream in conduit 226 combines with a yet-to-be- described ethylene vapor stream in conduit 238. The combined ethylene refrigerant stream enters ethylene economizer 30 via conduit 239, is warmed by an indirect heat exchange means 86, and is fed to the low-stage inlet port of ethylene compressor 20 via conduit 230. As shown in FIG. 1, ethylene compressor/driver system 21 comprises an inlet air compressor 23, an inlet air conduit 404, a combustion chamber 25, a fuel conduit 406, a turbine 27, and a drive shaft 29 operably coupled to an ethylene compressor 20. Modular turbine 27 includes at least two modular sections 45. Ethylene compressor/driver system 21 operates analogously to propane/compressor driver system 11 previously described. In addition, the three stages of compression in ethylene compressor 20 preferably exist in a single unit, although each stage of compression may be a separate unit and the units mechanically coupled to be driven by a single driver. The compressed ethylene product from ethylene compressor 20 flows via conduit 236 to ethylene cooler 22, wherein it is cooled via indirect heat exchange with an external fluid (e.g., air or water). The resulting condensed ethylene refrigerant stream is then introduced via conduit 202 to high-stage propane chiller 14 for recycle through the ethylene refrigeration cycle, as previously described.

The liquid portion of the ethylene refrigerant stream from intermediate-stage ethylene chiller 26 in conduit 228 enters low-stage ethylene chiller/condenser 28 and cools the composite methane-rich stream in conduit 120 via an indirect heat exchange means 90. The vaporized ethylene refrigerant from low-stage ethylene chiller/condenser 28 flows via conduit 238 and combines with the ethylene vapors from the intermediate- stage ethylene chiller in conduit 226. The combined ethylene refrigerant vapor stream is then heated by the indirect heat exchange means 86 in the ethylene economizer 30 prior to entering the low-stage suction port of ethylene compressors 20 as described previously. The pressurized, LNG-bearing stream exiting the ethylene refrigeration cycle via conduit 122 can be at a temperature in the range of from about -200 to about - 50⁰F, about -175 to about -100⁰F, or -150 to -125°F and a pressure in the range from about 500 to 700 psia, or 550 to 725 psia.

Turning now to the methane refrigeration cycle, the pressurized, methane-rich stream in conduit 122 is then routed to the main methane economizer 36, wherein it is further cooled by an indirect heat exchange means 92. The stream exits through conduit 124 and enters the expansion-cooling section of the methane refrigeration cycle. The liquefied predominantly methane stream is then passed through a pressure-reduction means, illustrated here as high-stage methane expander 40, whereupon a portion of the stream is flashed or vaporized. The resulting two-phase product enters high-stage methane flash drum 42 via conduit 163 wherein the gaseous and liquid portions are separated. The high-stage methane flash gas in conduit 155 is transported to main methane economizer 36, wherein it is heated via an indirect heat exchange means 93. The resulting stream exits main methane economizer 36 via conduit 168 and combines with the second distillation column vapor product in conduit 126 as previously noted. The combined stream then enters the high-stage inlet port of methane compressor 32, which will be described in more detail in a subsequent section. The liquid product from high-stage flash drum 42 enters secondary methane economizer 38 via conduit 166, wherein the stream is cooled via an indirect heat exchange means 39. The resulting cooled stream flows via conduit 170 to a pressure reduction means, illustrated here as intermediate-stage expansion valve 44, wherein a portion of the liquefied methane stream is vaporized. The resulting two-phase stream in conduit 172 then enters intermediate-stage methane flash drum 46 wherein the liquid and vapor phases are separated and exit via conduits 176 and 178, respectively. The vapor portion enters secondary methane economizer 38, is heated by an indirect heat exchange means 41 , and then reenters main methane economizer 36 via conduit 188. The stream is further heated by indirect heat exchange means 95 before being fed into the intermediate- stage inlet port of methane compressor 32 via conduit 190.

The liquid product from the bottom of intermediate-stage flash drum 46 then enters the final stage of the expansion cooling section as it is routed via conduit 176 through a pressure reduction means, illustrated here as low-stage methane expander 48, whereupon a portion of the liquid stream is vaporized. The cooled, mixed-phase stream is routed to low-stage methane flash drum 50 by means of conduit 186 wherein the vapor and liquid portions are separated. The liquefied natural gas (LNG) product, which is at approximately atmospheric pressure, exits low-stage methane flash drum 50 via conduit 198 and can be routed to storage. In one embodiment, the LNG product can be subsequently routed to an onsite or offsite re-gasification unit.

As shown in FIG. 1, the vapor stream exits low-stage methane flash drum 50 via conduit 196 and enters secondary methane economizer 38 wherein it is heated via an indirect heat exchange means 43. The stream then travels via conduit 180 to main methane economizer 36 wherein it is further cooled by an indirect heat exchange means 97. The vapor then enters the high-stage inlet port of methane compressor 32 by means of conduit 182. Methane compressor/driver system 33 operates in a like manner to the previously-described propane and ethylene compressor/driver systems 1 1, 21. Methane compressor/driver system 33 is illustrated as generally including an inlet air compressor 35, an inlet air conduit 408, a combustion chamber 37, a fuel conduit 410, a modular turbine 39, and a drive shaft 41 operably coupled to methane compressor 32. Modular turbine 39 includes at least two modular sections 45. Methane compressor/driver system 33 operates analogously to propane/compressor driver system 1 1 previously described. Compressed propane is discharged into conduit 192 and passes through methane cooler 34, wherein it is cooled via indirect heat exchange with an external fluid (e.g., air or water). The product of cooler 34 is then introduced via conduit 152 to high-stage propane chiller 14 for additional cooling via indirect heat exchange means 4 as previously discussed.

As previously noted, the methane refrigerant stream from high-stage propane chiller 14 in conduit 154 enters main methane economizer 36 wherein it is further cooled via indirect heat exchange means 98. The resulting cooled, methane-rich stream exits main methane economizer 36 via conduit 160 and is combined with the cooled natural gas effluent in conduit 1 19 from the overhead of first distillation column 54 of the heavies removal/NGL recovery section of the inventive LNG facility. The combined stream in conduit 120 then enters low-stage ethylene chiller/condenser 28, as previously discussed, and ultimately becomes the final LNG product.

In one embodiment, propane, ethylene, and/or methane compressor/driver systems can additionally comprise a second gas turbine and a second refrigerant compressor. In one embodiment, one refrigeration cycle comprises two refrigerant compressors, each driven by a respective gas turbine, operated in parallel. In another embodiment, two refrigeration cycles each include two refrigerant compressors and utilize two common gas turbines. In accordance with this embodiment, one gas turbine drives one compressor from each refrigeration cycle. This "two-trains-in-one" design significantly enhances the availability of the LNG plant. In a further embodiment, one gas turbine can be overfired when the second gas turbine is inoperable to minimize impact on plant production rate. It has been discovered that the above-described pre-cooling refrigerant can be particularly advantageous when employed in LNG facilities located in cold weather (e.g., artic) environments. Generally, such cold weather environments include locations where during any calendar year from 1995 to 2005, inclusive, the average ambient temperature was less than 5O⁰F during at least two, six, or ten months of the calendar year. Average ambient temperature for a calendar month is calculated by averaging the mean daily air temperatures over an entire calendar month, where the mean daily air temperature is the average of the high and low air temperatures for a day. Further, the present invention can be advantageous when employed in locations where during any calendar year from 1995 to 2005, inclusive, the yearly average ambient temperature was less than about 50⁰F, in the range of from about 0° to about 45°F, or in the range of from 10° to 40⁰F. Yearly average ambient temperature is calculated by averaging the mean daily air temperatures over an entire calendar year. It has also been discovered that the present invention can have advantages when employed in cold weather environments exhibiting a wide variation in yearly temperature extremes. Yearly variation in temperature extremes is calculated as the highest mean daily air temperature of a calendar year minus the lowest mean daily air temperature of that calendar year. For example, the present invention can be advantageously employed in regions where during at least one calendar year from 1995 to 2005, inclusive, the yearly variation in temperature extremes was at least about 50⁰F, in the range of from about 75° to 150⁰F, or in the range of from 85° to 125⁰F. NUMERIC RANGES

The present description uses numeric ranges to quantify certain parameters relating to the invention. It should be understood that when numerical ranges are provided, such ranges are to be construed as providing literal support for claim limitations that only recite the lower value of the range as well as claims limitation that only recite the upper value of the range. For example, a disclosed numerical range of 10 to 100 provides literal support for a claim reciting "greater than 10" (with no upper bounds) and a claim reciting "less than 100" (with no lower bounds).

DEFINITIONS As used herein, the terms "a," "an," "the," and "said" means one or more.

As used herein, the term "actual maintenance frequency" refers to the maintenance frequency of a gas turbine determined using current values for turbine operating parameters such as firing temperature, air compressor discharge temperature, exhaust temperature, and the like. As used herein, the term "aeroderivative gas turbine" refers to a gas turbine originally based on aircraft engine design modified for industrial use.

As used herein, the term "and/or," when used in a list of two or more items, means that any one of the listed items can be employed by itself, or any combination of two or more of the listed items can be employed. For example, if a composition is described as containing components A, B, and/or C, the composition can contain A alone; B alone; C alone; A and B in combination; A and C in combination; B and C in combination; or A, B, and C in combination.

As used herein, the term "monthly average ambient temperature" refers to the temperature calculated by averaging the mean daily air temperatures, as defined below, over an entire calendar month.

As used herein, the term "cascade refrigeration process" refers to a refrigeration process that employs a plurality of refrigeration cycles, each employing a different pure component refrigerant to successively cool natural gas.

As used herein, the terms "containing," "contains," and "contain" have the same open-ended meaning as "comprising," "comprises," and "comprise," provided below.

As used herein, the term "compressor" also refers to each stage of compression and any equipment associated with interstage cooling.

As used herein, the terms "comprising," "comprises," and "comprise" are open- ended transition terms used to transition from a subject recited before the term to one or elements recited after the term, where the element or elements listed after the transition term are not necessarily the only elements that make up of the subject.

As used herein, the term "firing temperature" refers to the temperature of the combustion chamber of an operating gas turbine driver. As used herein, the terms "having," "has," and "have" have the same open-ended meaning as "comprising," "comprises," and "comprise," provided above

As used herein, the term "hydrocarbon-containing" refers to material that contains at least 5 mole percent of one or more hydrocarbon compounds. As used herein, the terms "including," "includes," and "include" have the same open-ended meaning as "comprising," "comprises," and "comprise," provided above.

As used herein, the term "ISO standard conditions" refers to the set of standard ambient conditions established by the International Standards Organization (ISO) for standard comparison of gas turbines as specified in the GPSA Data Book, 12^th ed., page 15-13.

As used herein, the term "maintenance frequency" refers to the time between performing planned or unplanned maintenance on the turbine wherein the turbine is shut down during maintenance.

As used herein, the term "mean daily air temperature" refers to the average of the high and low air temperatures for a day.

As used herein, the term "modular" means having interchangeable segments.

As used herein, the term "mixed refrigerant" means a refrigerant containing a plurality of different components, where no single component makes up more than 75 mole percent of the refrigerant. As used herein, the term "multi-shaft turbine" refers to a turbine having two or more shafts.

As used herein, the term "operating severity" refers to a comparison of the current values for turbine operating parameters such as firing temperature, air compressor discharge pressure, exhaust temperature, and the like, as compared to the manufacturer-provided rated values for the same parameter.

As used herein, the term "overfiring" refers to the increasing of one or more turbine operating parameters above the manufacturer-provided rated values.

As used herein, the term "power output" refers to the power available at the output shaft of a gas turbine used to drive a load. As used herein, the term "predicted maintenance frequency" refers to the maintenance frequency of a gas turbine determined according to specific values for turbine operating parameters such as, for example, firing temperature, air compressor discharge, exhaust temperature, and the like. As used herein, the term "production rate" refers to the rate of production of feed natural gas.

As used herein, the term "pure component refrigerant" means a refrigerant that is not a mixed refrigerant. As used herein, the term "rated" refers to manufacturer-specified values for turbine operating parameters.

As used herein, the term "seasonal temperature variation" refers to the difference between the minimum and maximum annual temperature of a region.

As used herein, the term "thermal efficiency" refers to a measure of the energy input required by the gas turbine required to produce a certain output power.

As used herein, the term "updated maintenance frequency" refers to a maintenance frequency that has been adjusted as a result of a difference between the actual and predicted maintenance frequencies.

As used herein, the term "yearly average ambient temperature" refers to the temperature calculated by averaging the mean daily air temperature, as defined above, over an entire calendar year.

As used herein, the term "yearly variation in temperature extremes" refers to the range calculated by subtracting the lowest mean daily air temperature from the highest mean daily air temperature of that calendar year.

The preferred forms of the invention described above are to be used as illustration only, and should not be used in a limiting sense to interpret the scope of the present invention. Obvious modifications to the exemplary embodiments, set forth above, could be readily made by those skilled in the art without departing from the spirit of the present invention.

The inventors hereby state their intent to rely on the Doctrine of Equivalents to determine and assess the reasonably fair scope of the present invention as pertains to any apparatus not materially departing from but outside the literal scope of the invention as set forth in the following claims.

Claims

What is claimed is:

1. A method of operating a first modular gas turbine employed in an LNG facility, said method comprising: overfiring said first modular gas turbine for at least about 6 hours per day for a period of at least 2 successive days, wherein said overfiring causes the power output of said first modular gas turbine to increase by at least about 5 percent over said first modular gas turbine's maximum power output prior to said overfiring.

2. The method of claim 1, wherein said overfiring causes at least about a 5°F increase in the firing temperature of said first modular gas turbine.

3. The method of claim 1, further comprising shortening said first modular gas turbine's maintenance frequency by at least about 0.5 percent.

4. The method of claim 1 , wherein said first modular gas turbine is a multi- shaft turbine.

5. The method of claim 1, wherein said overfiring is at least partly caused by increasing in the fuel-to-air ratio of said first modular gas turbine.

6. The method of claim 1, wherein said overfiring causes the production rate of said LNG facility to increase by at least about 3 percent.

7. The method of claim 1, wherein said first modular gas turbine has a thermal efficiency greater than about 37 percent at ISO standard conditions

8. The method of claim 1, wherein said first modular gas turbine has a rated power of at least 35 megawatts at ISO standard conditions.

9. The method of claim 1 , wherein said first modular gas turbine is used to drive a compressor.

10. The method of claim 9, wherein said compressor is used to compress a refrigerant in said LNG facility.

1 1. The method of claim 10, wherein said refrigerant is a hydrocarbon- containing refrigerant

12. The method of claim 1 , wherein said LNG facility is positioned in a location where the average ambient temperature was less than 50⁰F for at least two calendar months of at least one calendar year from 1995 to 2005.

13. The method of claim 1, wherein said LNG facility utilizes cascade-type cooling to liquefy at least a portion of its natural gas feed.

14. The method of claim 1, wherein said LNG facility includes a second modular gas turbine, wherein said first and second modular gas turbines power respective first and second refrigerant compressors, wherein said first and second refrigerant compressors operate in parallel.

15. The method of claim 14, wherein said overfiring of said first modular gas turbine is carried out when said second modular gas turbine is shut down.

16. The method of claim 1, wherein said LNG facility has a production rate of greater than about 3.8 million metric tons per annum.

17. The method of claim 1, wherein said modular gas turbine is an aeroderivative gas turbine.

18. A method of operating a modular gas turbine employed in an LNG facility, said method comprising:

(a) determining the operating severity of said modular gas turbine;

(b) calculating an actual maintenance frequency of said modular gas turbine according to said operating severity;

(c) comparing said actual maintenance frequency of said modular gas turbine to a predicted maintenance frequency to determine a difference; and

(d) creating an updated maintenance frequency according to the results of step

(C).

19. The method of claim 18, wherein said predicted maintenance frequency is dependent on one or more manufacturer-specified turbine operating parameters.

20. The method of claim 19, wherein said turbine-operating parameter is firing temperature.

21. The method of claim 18, wherein said modular gas turbine is a multi-shaft modular gas turbine.

22. The method of claim 21, wherein said multi-shaft modular gas turbine has a thermal efficiency of greater than about 37 percent at ISO standard conditions.

23. The method of claim 22, wherein said modular gas turbine has a rated power output of greater than about 35 megawatts at ISO standard conditions.

24. The method of claim 18, further comprising, prior to step (a), overfiring said modular gas turbine.

25. The method of claim 24, wherein said overfiring causes the firing temperature of said modular gas turbine to increase by at least about 5⁰F.

26. The method of claim 18, further comprising, prior to step (a), measuring the actual firing temperature of said modular gas turbine; comparing said actual firing temperature of said modular gas turbine to a recommended firing temperature for said modular gas turbine; comparing said actual firing temperature and said recommended firing temperature to determine a temperature difference; and using said temperature difference to determine said operating severity of said modular gas turbine.

27. A process utilizing a computer to perform the method according to claim

28. The method of claim 18, wherein said LNG facility is positioned in a location where the average ambient temperature was less than 5O⁰F for at least two calendar months of at least one calendar year from 1995 to 2005.

29. The method of claim 18, wherein said modular gas turbine is an aeroderivative gas turbine.

30. In a process for producing liquefied natural gas at an LNG facility location where the average ambient temperature was less than 50⁰F for at least two calendar months of at least one calendar year from 1995 to 2005, the improvement comprising: using an modular gas turbine to drive a refrigerant compressor of said LNG facility.

31. The process of claim 30, wherein said modular gas turbine is a multi-shaft turbine.

32. The process of claim 30, further comprising overfiring said modular gas turbine for a period of greater than about 48 hours.

33. The process of claim 30, wherein said overfiring causes the power output of said modular gas turbine to increase by at least about 5 percent.

34. The process of claim 30, further comprising decreasing the maintenance frequency of said modular gas turbine by at least about 0.5 percent.

35. The process of claim 30, wherein said modular gas turbine has a thermal efficiency of greater than about 37 percent.

36. The process of claim 30, wherein said refrigerant compressor is used to compress a hydrocarbon-containing refrigerant stream in said LNG facility.

37. The process of claim 36, wherein said hydrocarbon-containing refrigerant is a mixed refrigerant.

38. The process of claim 36, wherein said hydrocarbon-containing refrigerant is a pure-component refrigerant.

39. The process of claim 30, wherein said LNG facility utilizes cascade-type cooling to liquefy at least a portion of its natural gas feed stream.

40. The process of claim 30, wherein said modular gas turbine is an aeroderivative gas turbine.

41. The process of claim 30, wherein said LNG facility has a production rate greater than about 2 million metric tons per annum.

42. The process of claim 30, wherein the yearly variation in ambient temperature extremes of said LNG facility location was at least 50⁰F for at least one calendar year from 1995 to 2005.

43. The process of claim 30, wherein the yearly average ambient temperature of said LNG facility location was less than 50⁰F for at least one calendar year from 1995 to 2005.

44. The process of claim 30, wherein the yearly variation in ambient temperature extremes of said LNG facility location was in the range of from about 75°F to about 15O⁰F for at least one calendar year from 1995 to 2005.

45. The process of claim 44, wherein the yearly average ambient temperature of said LNG facility location was in the range of from about 0° to about 45⁰F for at least one calendar year from 1995 to 2005.