US20100257895A1

US20100257895A1 - Method for the uninterrupted operation of a gas liquefaction system

Info

Publication number: US20100257895A1
Application number: US12/668,503
Authority: US
Inventors: Reiner Balling; Andreas Heinemann; Fritz Kleiner; Ulrich Tomschi
Original assignee: Siemens AG
Current assignee: Siemens AG
Priority date: 2007-07-12
Filing date: 2008-07-08
Publication date: 2010-10-14
Also published as: CN101784857B; RU2458295C2; EP2165137A2; WO2009007359A2; CN101784857A; AU2008274289B2; RU2010104871A; AU2008274289A1; WO2009007359A3; EP2015011A1

Abstract

A method for the uninterrupted operation of a gas liquefaction system is provided, wherein the operation is continuously monitored for at least those users of the refrigerant compressor component which represent a two-digit percentage of the total load on the refrigerant compressor component. A total instantaneously available negative load reserve is calculated, and at least one predetermined turbine is switched off when the load reserve reachable via a frequency regulation of the one or more refrigerant compressors is lower than the energy demand of the largest of the refrigerant compressors and either a refrigerant compressor fails or a speed of frequency change for the power supply network for the gas liquefaction system exceeds a present threshold.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application is the US National Stage of International Application No. PCT/EP2008/058821 filed Jul. 8, 2008, and claims the benefit thereof. The International Application claims the benefits of European Patent Application No. 07013711.2 EP filed Jul. 12, 2007. All of the applications are incorporated by reference herein in their entirety.

FIELD OF INVENTION

The invention relates to a method for the uninterrupted operation of a gas liquefaction plant, in particular a natural gas liquefaction plant.

BACKGROUND OF INVENTION

The term liquefied natural gas (abbreviated to LNG) is applied to natural gas which has been liquefied by cooling it. LNG has less than 1/600^thof the volume of natural gas at atmospheric pressure, and is thus especially suitable for transport and storage purposes; in this aggregate state it cannot be used as a fuel.
In power plants which are upstream of a plant for the liquefaction of light carbohydrates, such as for example natural gas, it is conventional to make use of gas turbines fired by natural gas and if necessary steam turbines in order to provide the required electrical energy from the generators coupled to them, which are motor driven.
In conventional natural gas liquefaction plants, the turbo-compressors for the refrigerant circuit are driven by directly coupled gas turbines.
Generic disadvantages of these plants are production down times during the regular maintenance work which is required on the gas turbines, difficult startup or restart of the compressors with single-shaft gas turbines, together with the direct dependence of the size and the power output of the refrigerant compressor on the type-tested gas turbines themselves, the shaft output of which depends in turn on ambient conditions which fluctuate daily or undergo seasonal changes.
For the purpose of avoiding these disadvantages, in newer plants the refrigerant compressor is driven by maintenance-free variable-speed electric motors. An electric generator driven by a gas or steam turbine supplies the electrical power for these motors; upstream static frequency converters permit a gentle startup and variable-speed operation. This is then referred to as an eLNG plant (e for electric).
U.S. Pat. No. 7,114,351 B2 describes such a plant for the provision of the electrical power for driving the refrigerant compressor of an LNG process. By this the electrical power, for the process of liquefying light carbohydrates in gaseous form from a source, is provided in a first step, and in a second step a refrigerant is compressed in a refrigerant compressor which is driven by an electric motor which makes use of the electrical power generated in the first step.
Electric motors supply their nominal power under various operating conditions, which permits continuous operation of the refrigerant compressor even under changing ambient conditions, with a different gas, or input air to the gas turbines at different temperatures. U.S. Pat. No. 7,114,351 B2 also explains that a gas turbine which suddenly goes down can be replaced by one, or even several, additional gas turbines in standby mode or by one, or even several, turbine sets in standby mode, as applicable. However, the disadvantage of this method is that the LNG production process has then already failed, and it takes some hours until the refrigerant compressor concerned has started up again and become thermally stable. One must therefore make allowance, in particular, for interruptions or down times, as applicable.
The applicant's publication “All Electric Driven Refrigeration Compressors in LNG Plants Offer Advantages”, KLEINER et al, GASTECH, Mar. 14, 2005, XP-001544023, therefore proposes a gas liquefaction plant incorporating a power generation module, a transmission module, a refrigerant compression module and a control system, where the power generation module has a number of turbine sets and the refrigerant compression module has at least one refrigerant compressor and a drive motor, coupled to the refrigerant compressor, for driving electrically the refrigerant compressor, the transmission module makes available to the refrigerant compression module the power generated in the power generation module, and the control system is connected to the power generation module and the refrigerant compression module, where the power necessary for the rated demand in normal operation can be made available via the control system by partial- or full-load operation of all the turbine sets, and the number of turbine sets exceeds the minimum number which will ensure continuity of operation of the refrigerant compression module.
The essential thought here is to install a turbine set which is additional, measured against the total power demand of the eLNG plant, in accordance with the n+1 principle. This turbine set is not a standby turbine set. In the uninterrupted or normal state of the plant, as applicable, all the turbine sets necessary for the operation of the eLNG plant, including the n+1^thturbine set, work in partial-load mode, i.e. so much spinning reserve is always maintained that it is possible to compensate for the failure of one turbine set by the control engineering. In this situation, one or more designated turbine sets can undertake the frequency regulation and in the normal situation all the operational turbine sets are equally loaded. In the event of the protective shutdown (tripping) of a turbine or a generator, a control system (dynamic load computer) will decide whether or not measures must be initiated for the purpose of stabilizing the stand-alone network.

SUMMARY OF INVENTION

An object of the invention is to specify a method for the interruption-free operation of a gas liquefaction plant.
In the inventive method for the interruption-free operation of a gas liquefaction plant, incorporating a power generation module, a transmission module, a refrigerant compression module and a control system, where the power generation module has a number of turbine sets and the refrigerant compression module has at least one refrigerant compressor and, coupled to the refrigerant compressor, a drive motor with a rated electrical demand, for driving electrically the refrigerant compressor, the transmission module makes available to the refrigerant compression module the power generated in the power generation module, and the control system is connected to the power generation module and the refrigerant compression module, and in normal operation the power necessary for the rated demand is provided by partial- or full-load operation of all the turbine sets, where the number of turbine sets exceeds the minimum number which is necessary to ensure the stability of operation of the refrigerant compression module, the operation of at least those users in the refrigerant compression module which represent a two-digit percentage of the total load on the refrigerant compression module is monitored, an overall instantaneously available negative load reserve is calculated and at least one predetermined turbine is shut down if the negative load reserve which can be achieved by frequency regulation of the refrigerant compressor or compressors is smaller than the power demand of the largest of the refrigerant compressors and either a refrigerant compressor fails or a rate of frequency change (df/dt) in the power supply network for the gas liquefaction plant exceeds a prescribed limit.
It is emphasized at this point that, unlike in conventional power networks, in the case of stand-alone networks such as for example the power generation modules of an eLNG plant, the relationship between load and generator power is such that over 80% of the current load is distributed across just a few individual loads. This is not the case for conventional networks, where there are very many individual loads with a small percentage fraction of the total load, and the operation of the consumers is therefore not observed or monitored.
The best way of all of achieving interruption-free operation of the gas liquefaction plant is by operating the turbine sets in such a way that a positive or negative power reserve which is maintained covers the failure of the largest turbine machine, whereby the positive power reserve covers the failure of a generator and the negative power reserve the failure of a motor-compressor train in the refrigerant compression module.
In the event of the failure of a turbine set, the (rotational) speed of the compressor drive will preferably be lowered if a previously determined overall positive load reserve is smaller than the power which was being supplied by the turbine set before its failure. (According to the quadratic load characteristic curve of the turbine compressor, the power drawn from the electric motors reduces as the cube of the rotational speed).
If the current energy demand of the refrigerant compression module is not covered even by the reduction in the compressor drive speed, it is expedient to switch off at least one predetermined electrical consumer in the gas liquefaction plant (load shedding).
The most far-reaching way of ensuring interruption-free operation of a gas liquefaction plant when there are unwanted shutdowns of subsidiary parts of the plant in the liquefaction process or when predefined threshold values are reached by the network frequency and by its rate of change, by the voltage and the phase angle in the power supply network for the gas liquefaction plant, is by shutting down predetermined turbines.
The most serious fault to be expected in the operation of an eLNG plant is an unplanned failure of a turbine set in the power generation module, i.e. in the stand-alone power plant—protective shutdowns of compressor drives are subordinate to this in their effects, and in the case of emergency shutdowns in the process plant it may sometimes be impossible to maintain operation. However, it is even possible in principle to incorporate a partial emergency shutdown (ESD) of the process plant into the dynamic load computer's algorithm.
Due to the elimination of maintenance work necessary on the gas turbines in the power generation module, the duration of interruption-free operation for a gas liquefaction plant which this permits in principle is increased, from the previous one to two years up to more than five years. The only remaining obstacle to increasing the expected productive days from around 340 (the value from historical experience of directly-driven gas liquefaction plants) up to 365 per year is then unplanned (malfunction) shutdowns.
When variable-speed (converter-fed) electric motors are used and are supplied with power from a modern gas and steam (combined cycle) power plant, the thermal efficiency of the plant increases and the emission of greenhouse gases is reduced.
By a suitable layout of the drive facilities, the refrigerant compressors can be started up again, after a process-induced shutdown, within 10 to 30 minutes instead of the 8 to 12 hours for standby turbines or fixed speed electric motors with start-up converters, without reducing the compressor load and without burning off refrigerant.
With an appropriate layout of the supplying stand-alone power plant, and integration of the automation systems involved (e.g. power plant, converter drives, compressors), production from the eLNG plant can also be kept interruption-free during a malfunction shutdown of a generator in the power plant.
Potential dangers to personnel are reduced by the relocation of maintenance work out of the explosion-risk process area into the power plant area.
When variable-speed electric motors with an application-specific layout are used, it is easier to effect optimization for the process conditions within the limitations on the criteria for compressor selection relating to the rotational speed and power of the gas turbines.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be explained in more detail by way of example with reference to the drawings. These show, schematically and not to-scale:

FIG. 1 the eLNG plant concept

FIG. 2 the control system's load computer algorithm for the positive load reserve, for realizing a method in accordance with the invention,

FIG. 3 the control system's load computer algorithm for the reduction in the rotation speed of the compressor modules for realizing a preferred embodiment,

FIG. 4 the control system's load computer algorithm for the shutdown of preselected turbines, for realizing a further embodiment,

FIG. 5 turbine utilization in the conventional power generation module of a gas liquefaction plant,

FIG. 6 turbine utilization in the power generation module of a gas liquefaction plant with a standby turbine,

FIG. 7 turbine utilization in the power generation module of a gas liquefaction plant with n+1 turbines in partial-load operation, and

FIG. 8 an alternative turbine utilization in the power generation module of a gas liquefaction plant with n+1 turbines

DETAILED DESCRIPTION OF INVENTION

FIG. 1 shows an integrated solution for a gas liquefaction plant 1 with a stand-alone power plant 23 as the power generation module 2, a transfer module 3 for distributing the power and a refrigerant compression module 4. A control system 5 is connected to the power generation module 2, the transmission module 3 and the refrigerant compression module 4.
The power generation module 2 incorporates three turbine sets 6, each with a turbine 10 and a generator 12, which are connected via a shaft 11. However, the power generation module 2 can also incorporate less than three or more than three turbine sets 6.
The turbine sets 6 are in each case connected via an electrical transformer 13 to the power plant busbar 15 of the transmission module 3, which makes the electrical power available to the motors in the refrigerant compression module 4 and/or other consumers 26.
In the refrigerant compression module 4, the variable-speed electric motors 8 of the refrigerant compressor 7 are actuated via converter transformers 14 and converters 16. Drive motors 8 and refrigerant compressors 7 are connected via shafts 17, and form motor-compressor trains 9, which finally effect circulation of the refrigerant and cooling of the natural gas 21 in the refrigerant circuit 18.
FIG. 1 shows a schematic representation of the closed refrigerant circuit 18. Refrigerant compressors 7 transport compressed refrigerant through the lines 19 to the liquefaction module 25. Used refrigerant in the gaseous state is fed back to the refrigerant compressors 7 via lines 20.
FIG. 1 shows further an inlet on the liquefaction module 25 for light gaseous carbohydrates such as, for example, natural gas 21. In the liquefaction module 25 (and other similar stages, not shown here) the natural gas 21 is transformed by cooling in heat exchangers from the gaseous state into the liquid phase (LNG) 22.
FIG. 2 shows the inventive algorithm of a load computer in the control system 5, for carrying out the method in accordance with the invention, i.e. for controlling the interruption-free operation of a gas liquefaction plant 1. For the purpose of assessing the load conditions, the dynamic load computer receives data 101 constantly from the power plant management system. The data includes the instantaneous power output from each gas or steam turbine, as applicable, the maximum instantaneously possible power from each gas or steam turbine, as applicable, and the minimum instantaneously possible load on each gas or steam turbine, as applicable, expressed in each case as electrical generator power. From the power output and the maximum instantaneously possible power, or from the power output and the minimum instantaneously possible load, it is possible to determine respectively the positive or the negative load reserve.
In a first step 102, the dynamic load computer calculates the overall instantaneously available positive load reserve, taking into account various parameters such as, for example, the instantaneous ambient temperature, the air humidity, and the calorific value of the combustion gas, which are already taken into consideration in the values 101 from the power plant management system.
In a second step 103, the dynamic load computer calculates the positive load reserve using the power of the largest turbine set 6. If the total positive load reserve is sufficient to maintain correct operation of the eLNG plant even if a turbine set 6 is shut down, the dynamic load computer reports to the power station maintenance staff and to the eLNG plant the status “n+1 available” 104. If, in this state, a protective shutdown actually does occur in the power plant, the dynamic load computer remains passive, and the power plant management system reestablishes a balance between the available and demanded loads by reallocating the loads on the remaining generators 12.
If the dynamic load computer determines that the instantaneously available positive power reserve is not adequate to compensate for any possible failure of a turbine set 6, it reports the alarm status “n+1 not available” 105 to the maintenance office, as a precaution.
This enables the operating staff to mobilize any power reserves which have been shut down (e.g. for maintenance work), or to reduce the load on the network, e.g. by shutting down other consumers 26, and thereby to prevent any interruption in production if a turbine set 6 goes down. Manual load reallocation between the operational turbine sets 6, and changes in the process steam consumption, are also suitable for this purpose.
If a precautionary load reduction is not initiated by the operating staff of the eLNG plant, e.g. by shutting down unimportant consumers 26 or by a temporary reduction in production, the dynamic load computer can intervene, in that it temporarily reduces the speed of all the operational compressor drives to a value which ensures the stability of the compressor, and thereby guarantees the freedom from interruption of the production. For this purpose the data 106 received from the compressor management system, about the load reductions which are instantaneously possible from reducing the compressor speed without endangering the stability of the compressor operation, is continuously processed and the sum of the possible load reductions for the individual compression modules is added to the positive load reserve 107. The overall load reserve thereby achieved may then possibly cover the failure of a turbine set 6.
In the alarm status “n+1 not available” it is then possible to reestablish the balance between positive and negative load reserves by a lowering of the compressor drive speed. Since this operation can be effected very quickly, it will only be initiated by the dynamic load computer if a protective shutdown in the power plant actually does take place in the alarm state.
The associate algorithm is shown in FIG. 3. As already explained, 107 indicates the sum of the positive load reserve of the turbine sets 6 and the possible load reduction resulting from a reduction in the speed of the compressor modules. In the next step 108, the positive load reserve and the possible load reduction are compared with the instantaneously available power of the largest turbine set 6. Independently of the result of this comparison, if there is a failure 109 of a turbine 10, the conjunction 110 is true, and the speed of the compressor modules will be reduced 111. If the sum of the positive load reserve and the possible load reduction is less than the power of the largest turbine set 6, or at least the one concerned, there will in addition be load shedding 112.
Apart from the computational determination of the difference between the positive and the negative load reserve, it is possible to use an independent determination of the rate of change of the network frequency (df/dt) for the purpose of recognizing a sudden change in the load conditions—without regard for its cause. The rate of change of the frequency is proportional to the step change concerned in the load, and can thus be used to determine the necessary protective shutdowns.
Since a change in frequency is a direct consequence of the event which triggers it, and the determination of the rate of change requires more time than a protective shutdown via the direct shutdown signals, any action based on the calculated frequency change might come too late. For this reason, this function can be regarded as a backup to the direct shutdown described. Apart from this, it is necessary to ensure that actions resulting from the computational determination of the lower frequency do not cause any spurious tripping.
If the measures described are not sufficient to balance out the difference between the positive and negative load reserves, the dynamic load computer initiates a chain of preprogrammed load shedding when a predefined lower frequency threshold is reached, in order to prevent a further fall in the network frequency—and with it a protective shutdown of the entire power plant. The consumers recorded in the load computer, which can if necessary be switched off at times without interrupting production, are disconnected from the network as quickly as is required, and to the necessary extent, to maintain the network frequency.
In principle, the algorithm applied to the unplanned shutdown of turbine sets 6 can also be applied to the unplanned shutdown of large consumers, primarily the large compressor drives. The layout of the management system for the power plant and machines is such that it can compensate for load shedding of this magnitude without the involvement of the dynamic load computer. FIG. 4 shows the principle. If the total of the negative load reserve which can be achieved by frequency regulation is larger than the largest load shedding to be assumed from shutting down compressor drives, the dynamic load computer will not intervene. Otherwise, a preselected turbine set 6 will be shut down, and the resulting positive load reserve balances out the remaining gap.
Here, 113 identifies the calculation of the negative load reserve and the determination of the compressor modules with the largest load. In step 114, these two values are compared. If the negative load reserve is larger than the larger load from the compressor modules, the computer reports the status “n+1 available” 115. Otherwise it reports “n+1 not available” 116.
Using the data from the power plant management system 101 and from the compressor management system 106, an assignment 117 of turbine sets 6 and compression modules is effected. With the help of this assignment, preselected turbines 10 are shut down if the negative load reserve is less 116 than the power demands of the largest compression modules and 124 either one compression module goes down 122 or 123 the rate of change of the frequency 120 in the power supply network for the gas liquefaction plant 1 exceeds 121 a prescribed limit.
In the case of even larger load shedding 126, e.g. in the case of partial emergency shutdowns of the process, it may be necessary to take several turbine sets 6 out of the network 128. If the sequence and the scale 118 of such an emergency shutdown is known, such a procedure can also in principle be controlled by the load computer, e.g. in that a preselection 119 is made of turbines 10 which are to be shut down, in order possibly to enable operation of a sub-process to continue. Large load shedding 126 and the exceeding 121 of a limit for the rate of frequency change 120 are combined together logically in the sense of a non-exclusive disjunction 127.
FIG. 5 shows schematically the turbine utilization in a conventional power generation module of a gas liquefaction plant 1, operating as rated. All the turbines 10 of the power generation module run under nominal full load 27. The power generation module operated in this way provides no positive load reserve to ensure interruption-free operation of the complete gas liquefaction plant is possible in the event of a failure of a turbine set 6.
FIG. 6 shows schematically the turbine utilization, in the power generation module of a gas liquefaction plant operating as rated, described in U.S. Pat. No. 7,114,351 B2. The additional turbine 24, kept ready on standby, is started up in the event of a failure of another turbine 10 running under full load when the gas liquefaction plant is operating as rated. Interruptions and down times can be the consequence in the LNG production process in the event of the failure of a turbine 10, and it can take a few hours until the refrigerant compressor 7 which is affected has been started up again and the liquefaction process has stabilized thermally.
FIG. 7 shows schematically and by way of example the turbine utilization in the power generation module 2 of a gas liquefaction plant as described in the applicant's publication “All Electric Driven Refrigeration Compressors in LNG Plants Offer Advantages”, KLEINER et al, GASTECH, Mar. 14, 2005, XP-001544023 when the refrigerant compression module 4 is operating as rated. All the turbines 10 run under partial load 28. There is no standby turbine 24. The positive load reserve is adequate to ensure interruption-free operation of the gas liquefaction plant 1, if a turbine 10 fails, by raising the load on the remaining turbines 10.
FIG. 8 shows schematically and by way of example an alternative turbine utilization in the power generation module 2 of a gas liquefaction plant as described in the applicant's publication “All Electric Driven Refrigeration Compressors in LNG Plants Offer Advantages”, KLEINER et al, GASTECH, Mar. 14, 2005, XP-001544023 when the refrigerant compression module 4 is operating as rated. All the turbines 10 run under partial- or full-load 28,27. Here again there is no standby turbine 24. However, the utilization of the turbines 10 is not necessarily the same. Apart from other parameters it is possible, for example, to take into account the operating life of turbines 10 in determining their utilization on a machine-specific basis.

Claims

1.-4. (canceled)

5. A method for interruption-free operation of a gas liquefaction plant comprising

a power generation module including a plurality of turbine sets;

a transmission module providing power generated in the power generation module to the refrigerant compression module;

a refrigerant compression module including a refrigerant compressor and a drive motor with a rated electrical demand coupled to the refrigerant compressor as an electrical drive for the refrigerant compressor; and

a control system, the control system being connected to the power generation module and to the refrigerant compression module, and in normal operation the power required for the rated demand is provided by partial- or full-load operation of all the turbine sets, wherein the plurality of turbine sets exceeds a minimum plurality of turbine sets necessary to ensure continuity of operation of the refrigerant compression module, the method comprising:

monitoring continuously the operation of at least those consumers in the refrigerant compression module representing a two digit percentage fraction of the total load from the refrigerant compression module;

calculating a total instantaneously available negative load reserve; and

shutting down at least one predetermined turbine when the negative load reserve achievable by frequency regulation of the refrigerant compressor is less than the power demand from the largest of the refrigerant compressors and the refrigerant compressor goes down.

6. The method as claimed in claim 5, wherein an instantaneously available positive load reserve is calculated and a compressor drive speed is lowered in the event of the failure of a turbine set when the positive load reserve is less than the power provided by the turbine set before the failure.

7. The method as claimed in claim 6, wherein at least one predetermined electrical consumer in the gas liquefaction plant is shut down when, after the failure of a turbine set, even a reduced compressor speed does not enable the actual power from the turbine sets to cover the current power demand for the refrigerant compression module.

8. The method as claimed in claim 5, wherein predetermined loads are shed when predefined lower threshold values for the network frequency are reached in the power supply network for the gas liquefaction plant.

9. The method as claimed in claim 6, wherein predetermined loads are shed when predefined lower threshold values for the network frequency are reached in the power supply network for the gas liquefaction plant.

10. The method as claimed in claim 7, wherein predetermined loads are shed when predefined lower threshold values for the network frequency are reached in the power supply network for the gas liquefaction plant.

11. A method for interruption-free operation of a gas liquefaction plant comprising

a power generation module including a plurality of turbine sets;

calculating a total instantaneously available negative load reserve; and

shutting down at least one predetermined turbine when the negative load reserve achievable by frequency regulation of the refrigerant compressor is less than the power demand from the largest of the refrigerant compressors and a rate of change in the frequency in the power supply network for the gas liquefaction plant exceeds a prescribed limit.

12. The method as claimed in claim 11, wherein an instantaneously available positive load reserve is calculated and a compressor drive speed is lowered in the event of the failure of a turbine set when the positive load reserve is less than the power provided by the turbine set before the failure.

13. The method as claimed in claim 12, wherein at least one predetermined electrical consumer in the gas liquefaction plant is shut down when, after the failure of a turbine set, even a reduced compressor speed does not enable the actual power from the turbine sets to cover the current power demand for the refrigerant compression module.

14. The method as claimed in claim 11, wherein predetermined loads are shed when predefined lower threshold values for the network frequency are reached in the power supply network for the gas liquefaction plant.

15. The method as claimed in claim 12, wherein predetermined loads are shed when predefined lower threshold values for the network frequency are reached in the power supply network for the gas liquefaction plant.

16. The method as claimed in claim 13, wherein predetermined loads are shed when predefined lower threshold values for the network frequency are reached in the power supply network for the gas liquefaction plant.

17. A gas liquefaction plant, comprising:

a power generation module including a plurality of turbine sets;

a control system, the control system being connected to the power generation module and to the refrigerant compression module, and in normal operation the power required for the rated demand is provided by partial- or full-load operation of all the turbine sets, wherein the plurality of turbine sets exceeds a minimum plurality of turbine sets necessary to ensure continuity of operation of the refrigerant compression module.