FR2858830A1 - Increasing capacity and efficiency of gas installations which include at least one gas turbine comprises cooling air entering turbine - Google Patents

Abstract

The process comprises cooling the air entering the turbine(s) with a cooling circuit, the cold being produced from the gas process itself and/or by separate refrigeration modules. The cold is transferred to the air in the turbine(s) by exchangers or direct contact in a contactor. The air entering the gas turbine (120) is cooled by a glycol solution in a contactor (121) preferably filled with packing (123). The glycol solution loaded with water from the air is regenerated in a column (132) of which the reboiler (136) is heated by a heating circuit drawing its energy from a bundle (140) placed in the exhaust gases from the gas turbine. The gas installation is a reception and regasifying terminal for liquefied natural gas, the regenerated glycol is cooled by the regasification tube exchangers (160) in which the liquid natural gas to be regasified (101) circulates on the tube side. Alternatively, the gas installation is a natural gas liquefying station and the glycol is cooled in propane evaporators added in parallel to the propane refrigeration circuit which forms the first stage in gas liquefaction. Alternatively, the gas installation is a mains gas compression station and the glycol is cooled by a refrigeration module, with preliminary cooling of the glycol by exchange with the gas entering the station. The air entering the gas turbine(s) is cooled by exchangers in which a thermal transfer fluid circulates, preferably an aqueous solution of glycol or methanol. This thermal transfer fluid is cooled partially or totally in propane evaporators evaporators added in parallel to the propane refrigeration circuit which forms the first stage in gas liquefaction. Alternatively the thermal transfer fluid is cooled partially or totally by absorption refrigeration modules supplied with heat by a circuit recovering heat by a bundle placed in the gas turbine exhaust gases and/or on exchangers placed after the gas compressors. The condensed water, recovered below the exchangers in collectors is, after storing in tanks reinjected via a reinjection module into the turbine(s) at the level of the combustion chamber or vaporiser. The water from the glycol regeneration column(s) is recondensed in aerocondensers to be reinjected into the turbine(s). The gas installation is a mains gas compression station, the gas to be compressed arriving at the station is cooled by counter- flow with the compressed gas from an aerocooler, in gas/gas or gas/water exchangers.

Description

Background of the invention

  The present invention relates to a method for refrigerating the inlet air of gas turbines for gas installations.

  The invention finds particular application in the following gas installations: - the regasification terminals of liquefied natural gas (LNG), - the liquefaction plants of natural gas, - the large transport pipelines, - the gas reinjection plants in the deposits.

  Gas installations that draw their energy from gas turbines are penalized by the effect of the variation of ambient temperature on the available power of these turbines, which decreases from 0.5% to 1%, depending on the models, when the temperature of the air increases by one Kelvin. The efficiency of these turbines is also affected, albeit to a lesser extent, by this increase in temperature.

  Moreover, it is precisely at high ambient temperature that the installation usually requires more power for a given gas flow.

  Under these conditions, the prescribers currently adopt one or other of the following choices: either the gas turbines are chosen so as to provide the power required by the nominal operation of the gas process for the highest ambient temperature. The power of the turbine is then defined taking into account a power de-rating which commonly reaches 20 to 25% with a degradation of the efficiency of the order of 5%. This leads not only to increase the investment cost but also to an underutilization of this power in cold period, therefore to a still lower yield, it being very quickly deteriorated as soon as the load on the turbines is reduced. gas; Either it is accepted that the production of the gas installation is reduced when the temperature increases which has an impact on the efficiency of use of the other parts of the gas installation, or on the elements upstream and downstream of this installation.

  It is therefore desirable to be able to refrigerate the inlet air of these turbines (up to about 5 to 10 C to prevent icing), in order to obtain available powers greater than the rated power at 15 C, instead of an offset of 20 to 25%.

  The effect on the power of the gas turbines as well as on the efficiency can be greatly increased if the inlet air can be cooled to lower temperatures such as -20 C, which means avoiding frost formation.

  There is therefore a need for a refrigeration process to improve the capacity and efficiency of gas installations whose production is conditioned by the power provided by gas turbines.

  SUMMARY OF THE INVENTION The present invention satisfies this need, by means of a method according to which the inlet air of these turbines is refrigerated by cooling cycles, by modifying or optimizing the gas process of these installations in order to benefit from this increased power, and / or by integrating this refrigeration cycle into the gas process itself so as to either obtain cold from the gas process, or to benefit this process, together with the gas turbine, at the level of cold or at the hot level, the existence of the refrigeration cycle.

  Such refrigeration does not require expensive refrigeration plants, correspondingly it requires, in the case of compression cycles, only a limited mechanical power which is only a fraction of the extra power obtained on the compressor. gas turbine; or it requires practically none, either if the cold is available elsewhere, or if the cold is obtained from thermal energy in absorption refrigeration cycles.

  This refrigeration also has the advantage of being very inexpensive if cold is available free of charge on the gas process (in the case of liquefied natural gas reception and regasification terminals) or can be obtained by simply over-sizing the gas process ( case of gas liquefaction plants).

  The invention therefore relates to a process for increasing the capacity and efficiency of gas installations of the type comprising at least one gas turbine, which process comprises cooling the air entering the gas turbines.

  This cooling is communicated to the air: - either for cooling above 0 C by exchangers in which circulates a heat transfer fluid which may be cold water, glycol water (hereinafter also (Aqueous) glycol solution), water added with methanol (hereinafter also (aqueous) methanol solution), or water added with an antifreeze, preferably an aqueous solution of glycol or methanol; or by contact, within a contactor preferably comprising a lining, in which a heat transfer fluid such as a glycol solution, which lowers the dew point of the air and makes it possible to cool it down, descends by gravity below 0 C and up to -20 C without risk of icing. The glycol must then be regenerated before being recycled into the cold loop.

  These elements, exchangers or contactors, are preferably located near the air filter of the gas turbine and a droplet separator is advantageously disposed downstream at the inlet of the air compressor of the turbine.

  The refrigerant is preferably supplied to the refrigerant from the gas process itself, but may also, in whole or in part, be provided by specific refrigeration modules, in particular by absorption cycles which can advantageously draw their thermal energy from the gas. exhaust of the gas turbine.

  The water condensed by cooling the air and / or at the top of the column regenerating the glycol may, where appropriate, be usefully recovered especially in locations where water is scarce to provide extra power for the turbines. gas injection at the combustion chambers of the gas turbine, or by saturation vaporization in the incoming air for other turbines of the gas process.

Brief description of the figures

  FIG. 1 represents a reception and regasification terminal of the liquefied natural gas associated with a gas turbine thermal power station.

  Figures 2 to 5 show a gas liquefaction plant. Figures 6 to 9 show a gas pipeline compressor station.

  Figure 10 shows a gas reinjection plant in the hydrocarbon deposits.

  DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS OF THE INVENTION According to a first embodiment, the method of the invention is applied to reception and regasification terminals of liquefied natural gas associated with gas turbine power plants.

  Currently, LNG regasification terminals that receive liquefied natural gas from LNG tankers, usually at the rate of several million tons per year, regasify the liquefied gas, after having put it under network pressure by one or more pumperies. bringing heat: - either by runoff vaporizers using seawater which is thereby cooled, the limitations of this cooling imposing large flow rates of water so expensive facilities, - or by combustion vaporizers immersed which therefore consume energy (about 200 kW h / t, or 1.5% of the energy regasified gas).

  However, it is now increasingly considered to locate near these terminals power plants, including combined cycle, which consume a portion of the gas emitted by the terminal.

  In these LNG regasification terminal projects associated with combined cycle plants, it naturally came to the idea of the designers to combine the demand for heat from the terminal to regasify LNG, and the heat sources emitted by the plant. Power plant. This makes it possible, on the one hand, to make installations that may be less expensive at the terminal, and, on the other hand, in certain cases, to make the power plant benefit from a cold supply that can improve the performance of the thermal cycle.

  On this last point, the best use of cold is to cool the inlet air of the gas turbine. However, the possibilities of this system are limited in the solutions currently envisaged, the air temperature at the inlet of the gas turbine which must remain above 5 C to prevent icing.

  In winter, the temperature drop of the inlet air is either canceled or greatly reduced, and the terminal must also use the other heat sources available on the combined cycle to regasify LNG.

  These disadvantages can be avoided, and the profit on the production capacity as well as the efficiency of the combined cycle can be considerably increased, if the cold available on the terminal is used to cool the inlet air below 0 C and up to about -20 C, which is possible by suppressing the icing phenomenon.

  The process of the invention consists in cooling and concomitantly drying the inlet air of the gas turbine (or turbines) by watering with a cold glycol solution circulating against the current of the air, in a contactor provided with a packing, the cold glycol coming from the regasification exchangers of the terminal.

  The cold injected glycol solution allows the air to cool down to temperatures of up to -20 ° C without the risk of icing.

  The glycol recovered at the bottom of the contactor, charged with most of the water contained in the air supplied to the gas turbine, is regenerated in a distillation column where the reboiling energy is obtained preferentially from the exhaust fumes. exhaust gas turbine (s).

  If necessary, the water vapor leaving the top of the regeneration column can be recondensed by exchange with the glycol coming from the contactor and used by a reinjection module to inject water at the combustion chamber of the reactor. gas turbine so as to further increase the production capacity, if allowed by mechanical limitations.

  The regenerated hot glycol column bottom of the regeneration is, after cooling by heat exchange with the glycol to be regenerated, before entering the column, and / or by air cooler, sent to cool in regasifiers LNG terminal.

  The latter are tubular exchangers (the glycol being on the shell side).

  In the rare periods when the combined cycle is at a standstill or in very cold weather, all or the additional heat supply for the regasification is provided by a backup means such as boilers fed with natural gas and heating the boiler. glycol solution upstream of the regasification exchangers, and / or by heating this solution from the heat of the fumes exiting the combined cycle, via a bypass of the hot water loop used for the reboiling of the glycol regeneration column .

  In the case where the LNG terminal is stopped, the combined cycle plant can still operate on the mains gas with an uncooled inlet air, so with the simple loss of the capacity increase provided by the cooling .

  A detailed description of this embodiment is given below with reference to the diagram of FIG.

  The LNG (101) coming from the high pressure pumps of the LNG terminal is sent to tubular exchangers (160) where it exchanges heat and regasifies (103) by exchange with the glycol / hot water solution circulating on the shell side.

  This glycol enters the heat exchangers (160) and returns to the required temperature up to about -25 C. It is then directed to the upper part of the air-glycol contactor (121) located after the air filter. (122) of the gas turbine (120) of the power plant. This contactor preferably contains a packing (123) making it possible to maximize the contact between the air and the glycol solution.

  The sizing of the contactor is made in such a way as to ensure a speed of the air avoiding any mechanical entrainment of the liquid by the air. As a precaution, a droplet recuperator (125) prevents any drive to the gas turbine.

  At the bottom of the contactor (121), the glycol solution (105), charged with the water extracted from the air, is found at a temperature slightly lower than that of the ambient air, while the air comes out at the upper part of the contactor at a temperature slightly higher than that of the cold glycol solution coming from the regasifier tubular exchanger of the LNG terminal, the level of this temperature is optimized according to the characteristics of the turbine and the reciprocal thermal balances of the terminal and power plant.

  The wet glycol solution (105) is sent to the regeneration unit through the pump (130). In this unit, the wet glycol is used preferentially to condense the reflux water of the column (132). If necessary, depending on the heat balance, it is heated in the exchanger (135) by the regenerated glycol leaving the reboiler of the regeneration column, and then injected into the column (132). Conversely, the dry and hot glycol from the reboiler (136), after possibly being cooled in the exchanger (135), is sent to the regasifier exchangers of the terminal (160).

  The reboiling energy of the glycol regeneration unit is provided by a heat transfer fluid or steam loop. The water extracted from the glycol (110) is either rejected after treatment in the ambient environment or is reinjected into the gas turbine (if this permits) at the combustion chambers by a reinjection module (107).

  The loop of coolant (or steam) used for reboiling draws its energy from a spindle (140) located in the exhaust gas of the gas turbine (120), downstream of the boiler of the steam cycle of the plant combined cycle.

  In an alternative embodiment of this embodiment, a portion of the wet glycol (105) from the return pump (130) serves to cool the air upstream of the contactor (121) in a heat exchanger (102) so as to Condense a portion of the water to reduce the power of the glycol regeneration unit. This pre-cooling is regulated in flow so that the air temperature does not fall below +5 / +10 C.

  The glycol loop can also be used to regasify LNG when the air no longer provides regasification heat: - when the thermal power station is off, - when the ambient air temperature is too low and can not provide sufficient heat.

  In the first case (stationary thermal plant), which is supposed to be infrequent, it is possible to consume gas: emergency boilers (150) make it possible to supply sufficient energy to the system. The passage through the air-glycol contactor is avoided by the implementation of the valves and the glycol is only used as transfer liquid between boilers and regasifiers.

  In the second case, depending on the frequency of these conditions: - either the backup boilers are used in addition as indicated above, or hot water is derived from the heat recovery bundles normally providing the reboiling heat from the loop, to the water / glycol boilers which then act as exchangers without the use of fuel.

  According to a second embodiment, the process of the invention is applied to gas liquefaction plants.

  With regard to such installations, two processes are currently generally used to liquefy the gas. Both have a first level of cold consisting of a propane cycle. In other less common processes, the refrigerant providing this first level of cold may be a mixture of gases, and solutions similar to those described hereafter for propane cycle processes could be applied to these processes.

  When the ambient temperature increases, the specific load of this first level of cold increases considerably in application of the law of CARNOT because the temperature of the hot source (the ambient air or the sea water where one rejects the frigories) is higher. Since this increased load can only be partially toppled over the colder-level cycles, the first level of cold is generally the high-temperature bottleneck of the liquefaction plants. Or at this increased power, required by the (the) compressor (s) propane, corresponding conversely a decrease in the power available on the (the) gas turbine (s) driving this (s) compressor (s).

  These two reverse phenomena can only be reconciled by a reduction in LNG production, which leads to a reduction in the propane flow rate, a reduction which, moreover, is unfavorable, because it displaces the operating point of the propane compressors in a zone to degraded performance, which further increases the power required.

  In total, for example, at 33 C ambient temperature, the liquefaction capacity can be reduced by 15 to 17% from its 21 C level.

  As a result, in summer, the production potential is reduced and upstream there is an underutilization of gas and pipeline production and processing facilities and, downstream, a difficult management problem for LNG tankers whose capacity summer transport remains equal, if not better, because sea conditions are generally less severe than in winter.

  Considering that the cost of the installations of a liquefaction train is considerable (cost which can be doubled by the cost of the upstream installations), whereas the actual cost of the driving gas turbines of the compressors of the liquefaction cycle does not represents a small fraction, one may wonder why, in current installations, more powerful gas turbines are not expected.

  The explanation is that gas turbines have a well-defined range of models and that process designers looking to build high capacity units have in fact already aligned their process design for a medium temperature. the most powerful existing models, in the category, generally considered, industrial turbines.

  This has even led, for the two large gas turbines often used in liquefaction trains APCI process (Air Products), the expensive use of an addition of power by variable speed electric motors installed on the same tree.

  Under these conditions, the ability to completely or partially erase the power drop of these turbines at high temperature, or even increase it by further cooling, is of interest for a new project of high capacity.

  This is even more the case if it is a de-bottlenecking operation of existing liquefaction facilities, which can be used to improve production in the summer and maintain it at a level close to the winter level all year round.

  The adaptation of the process of the invention to liquefaction plants of natural gas can be declined according to three variants described below: a) A first variant is represented by the diagrams of FIGS. 2 and 3.

  In both cases it is created bypassing the two upper pressure stages of the propane cycle, two additional evaporators for cooling a brine loop.

  The scheme of FIG. 2 is a preferred example of application to the PHILLIPS liquefaction process and is explained as follows.

  The first evaporator HP (207) with a propane side temperature of 7 to 10 C can cool the brine to 10 to 15 C. The second evaporator MP (208) with a propane side temperature of about -5 C can cool the brine to 0 C.

  The brine is sent into the air / brine heat exchanger (202) installed at the inlet of the gas turbine (220) driving the propane compressor (s). Flow control valves make it possible to optimize the distribution of the cold brine water between the air inlets 2858830 11 of the different cycles, so as to obtain an operation where the increased power of the turbines is best used. This gives the maximum LNG production gain.

  Optionally, the water condensed by the cooling air and recovered in the collector (s) (204) is stored in the capacity (205) so that it can be reinjected under pressure, in the hottest period of time. the day, either according to the devices commonly used by turbine manufacturers in the combustion chambers of gas turbines, or according to the devices recommended by some manufacturers, directly to the suction of the air compressor or it vaporizes in progress compression thus reducing the power of compression. According to the diagram of FIG. 2, the water stored in the capacity (205) is injected into the turbines (220) and (220 bis) via the injection module (206) at the combustion chambers (206 bis) .

  This option is particularly valid in countries where fresh water can not be easily provided and where, due to the proximity of the sea, air has only a low moisture content as soon as the temperature drops. .

  On the propane cycle side, the propane / brine evaporators are fed in series from a bypass of the condensed propane circuit. The propane gas from the evaporators (207 and 208) is returned respectively to the suction of the high pressure and medium pressure stages of this compressor.

  The scheme of FIG. 3 is a preferred example of application to the APCI liquefaction process and is analogous to the application to the PHILLIPS process described above, but differs in the following points: Because, in this process, the high ambient temperature overload can be more easily distributed between the propane cycle and the lower temperature cycle called MR cycle by changing the composition of the refrigerant mixture of the MR cycle, it is advantageous to increase, by the refrigeration of the air, the power of the gas turbines of both groups, even if that of the group driving the propane compressor must be greater to compensate for the overhead due to the additional flow of propane evaporators (307 and 308).

  For this reason, the cold brine leaving the evaporator (308) is sent, in parallel, into the air / brine heat exchangers (302) of the two turbines (320) where the condensation water is also recovered. in the manifolds (304) and capacitors (305) for reinjection by the modules (306).

  The distribution of the cold brine flow and, in the hot period, the injection of water between the gas turbines is regulated by control valves not shown in the diagram so that the increase in power resulting is optimal in terms of LNG production capacity.

  In the case where the drive of the compressors is provided in a different way, for example with a gas turbine, driving the propane compressor and two gas turbines respectively distributing the BP and HP compression of the MR cycle, the devices could be closer to those relating to the PHILLIPS process described above, that is to say, not necessarily involving air refrigeration installations on the MR cycle turbines: the choice depends on the respective power balances of the cycles considered. at high ambient temperatures and climatic conditions.

  The operation at the different temperatures of these two processes thus modified can be analyzed as follows: Dans In the case of the hottest temperature, the flow of cold brine is preferentially sent to the air intake of the propane compressor so to obtain an air of 5 to 10 C. The increase in power of the resulting gas turbine is divided between the power required to compress the additional propane, emitted at the level of the propane / brine evaporators, and between the additional power corresponding to an increase in the flow of gas to be liquefied.

  The air cooling of the other turbines of the lower temperature level cycles is adjusted so that their power makes it possible to process this increased flow rate thus authorized by the increased power of the propane turbine. This does not require cooling the air as much as on the propane turbine.

  Also for this purpose, optionally, as shown in the diagram of Figure 2 in hot and dry countries, the air cooling of these turbines (220 bis) can be obtained by simply injecting water into the air. admission to a vaporizer (202 bis), which may be sufficient to obtain the lower temperature drop required on these turbines.

  When the ambient temperature is lower at around 15 C, the propane cycle is less charged and it is usually the power available on gas turbines of other cycles at lower temperature level which limits the production.

  In this case, if one has as shown in the diagram of Figure 3, also provided air cooling on the turbine of this (these) other (s) cycle (s), the brine is preferentially sent to the air intake of these turbines and allows them to obtain an additional production of order of 6 to 7%.

  Optionally still the condensation water can be re-injected into the combustion chamber system for extra power if necessary.

  When the air is at 10 C, the air cooling obtained is at most 5 C and the production gain thus obtained is limited to 3 or 4%.

  b) A second variant is represented by the diagram of FIG.

  In this variant, the cold is not produced by propane evaporators but by an absorption refrigeration module, with ammonia or lithium bromide (407 and 408), according to known technologies and applied in the packaging plants. high capacity air.

  The cold produced in the refrigeration module (407) is transferred to the air, as in the previous variant, by cold brine sent via the pump (409) to the air / glycol heat exchangers (402) of the turbines with gas (420 and 420 bis).

  Where appropriate, the water condensed in these exchangers, collected in the collectors (404) and the capacitors (405), can be injected into the gas turbines at the combustion chambers (406bis) during hot periods, via the injection module (406), so as to obtain additional power.

  As in the previous variant, the distribution of the cold brine flow (and if necessary in warm period, that of the condensed water) between the gas turbines of the different cycles is regulated by control valves not shown. in the diagram, so that the resulting power increase is optimal with respect to the LNG production capacity.

  The hot source of the absorption cycle can be provided either by a boiler installed in recovery of the exhaust heat of a gas turbine via the beam (419), or by the use of steam otherwise present for the purposes of the process , or by a steam boiler or hot water specific.

  In this variant, the propane cycle is not required to refrigerate the air. The entire increase in power, due to air cooling on the propane turbine, can then be used to increase LNG production. Therefore the increase of the latter may be greater than in variant (a) above, insofar as the maximum liquefaction potential defined by the other parts of the process or upstream installations allows.

  c) A third variant is represented, for the APCI process with 2 turbines, by the diagram of FIG.

  Similar solutions would be used in the case of the PHILLIPS process with 3 cycles and the APCI process with 3 turbines.

  In this variant, the cooling of the air of the ugly turbine (s) driving the propane compressor is pushed to approximately -20 ° C., which brings a considerable additional power compared to an operation at +30 ° C. order of 35% more).

  For this purpose, the air inlet of the propane compressor drive turbine is used with the cold glycol air cooling and regeneration system defined in the first embodiment relating to the terminals. LNG carriers described above.

  This increased power available on this turbine makes it possible to substantially increase the cooling potential of the propane cycle, making it possible to supply, via the glycol loop, both the cold and the air of the turbine. propane drive, but also to the turbine (s) drive other cycles, while maintaining on this turbine power reserve to increase the flow of gas to be liquefied consistent with that provided by the increase power supplied to the turbines of the other cycles.

  The system represented by the diagram of FIG. 5 is thus described.

  The cold is produced by propane evaporators located in parallel with the evaporators of the liquefaction cycle and transmitted to the air of the gas turbines via a solution of glycol.

  Since the cold level required to cool the air in the propane compressor drive turbine is lower than that contemplated in variant (a) above, not only HP (507) and MP evaporators must be used. (508), but at the BP level (509).

  The glycol solution actually flows in two loops that meet at the propane evaporators. The first loop is that of the coldest glycol leaving the LP propane evaporator (509). This glycol cold at a temperature of about -25 C is directed to an air-glycol contactor (521) preferably provided with a lining (523) located at the suction of the drive turbine of the propane compressor. The air entering the turbine is thus cooled to about -20 ° C. and any glycol entrainments separated in the separator (525). At the bottom of this air-glycol contactor, the glycol (505) charged with the humidity of the air (and, if the air is at 30 C, at a temperature of about 20 C) is sent via the pump ( 524) to the regeneration unit (532) after heating in the exchanger (535) countercurrently the regenerated glycol leaving the reboiler (536) of the column (532).

  It is this regenerated glycol, cooled to around 25 C, which is sent to the HP propane evaporator (507) after confluence with the glycol of the second loop and pressurized in the pump (524 bis).

  The reboiling energy is provided by the steam produced in a recovery boiler located at the exhaust of the turbine via the beam (540).

  The second glycol loop serving the turbine (s) other than the propane turbine generally does not require a cold level below 0 C and therefore, it is then designed as described for the variant ( a) above: the glycol of this loop is taken, in bypass regulated by the valve (510) at a temperature of about 0 C, out of the propane evaporator MP (508) and sent into the glycol exchanger -air (502) located at the air intake of this (these) other (s) turbine (s) (520 bis).

  As in the previous versions, the condensed water in the exchangers (502), in the droplet separators (503) and, if appropriate, in a top condenser (534) of the column (532) can be reinjected into the turbine (s) at the combustion chambers via reinjection modules not shown in the diagram.

  The increase in the propane flow rate corresponding to this variant (of the order of 20%) requires not only the addition of evaporators to supply the cold to the glycol loop, as well as reconductors, but possibly a modification of the compressor wheels. . This solution is therefore more suitable for taking into account the origin of the design of the liquefaction train, than for a modification of existing installations.

  On the other hand, it allows, with the available gas turbine models, even in tropical countries with high humidity, a production potential gain of nearly 10%.

  This process can also be applied if the propane constituting the refrigerant fluid of the first stage of the liquefaction is replaced by a mixed composition refrigerant.

  The choice between the variants of type (a) and (b) or (c) therefore depends on the possible flow limitations of the other elements of the liquefaction line as well as the climatic conditions and the power balances of the various cycles constituting the process of liquefaction at different ambient temperatures to consider.

  According to a third embodiment, the method of the invention is applied to gas pipeline compression stations.

  The pipelines have their capacity defined by the maximum pressure and the diameter of the tubes chosen, and by the power installed in compressor stations whose compressors are most commonly driven by gas turbines.

  The distance between two stations defines, for the flow rate considered under given gas temperature conditions, the arrival pressure.

  The power required for the compression is proportional to the mass flow, inversely proportional to the density of this gas, and a function of the compression ratio.

  When the ambient temperature is high, the power of the gas turbines is reduced as indicated above, but there is also a negative effect of the ambient temperature on the power required at the compressor stations and on the pressure losses in the pipe: the inlet temperature in the pipe is that of the outlet of the air cooler located after the compressors of the compressor stations, ie the temperature of the air increased by the air / gas difference of the cooling air is about 15 C, - taking into account the importance of flow rates and therefore the heat capacity of the gas in transit, the heat transfers from the ground to the gas are low and the arrival temperature in the station is practically that of departure from the station reduced by the expansion effect (isenthalpic) in the tube (of the order of 0.5 C per bar), ie of the order of 10 C for the pressure losses commonly encountered between two gas pipeline stations, - the pert e of charge in the pipeline for unchanged mass flow, is inverse function of the square root of the density of the gas, density which varies not only as the inverse of the absolute temperature as for the perfect gases, but as the inverse of very sensitive temperature compressibility coefficient for natural gas in the pressure and temperature zone considered in the pipelines. This effect of the variation of the compressibility coefficient amounts to almost doubling the effect of the temperature resulting from the only law of perfect gases.

  The first effect, of an increase of the air temperature on the flow in the pipe, is thus either to decrease the flow in inverse function of the square root of the density, or to increase the loss. by keeping the flow rate, and thus reducing the arrival pressure at the next station, which requires a greater compression power, all the less available as the air temperature is high for the gas turbine .

  Moreover, the gas arriving at the next station whose temperature follows practically, 10 C below, the departure temperature variations of the previous station is less dense at unchanged pressure, further increasing the compression power which for a given mass flow rate varies according to density.

  In total the maximum capacity of a pipeline can vary by more than 15% between a temperature of 30 C and a temperature of 5 C.

  To overcome these negative effects of high ambient temperatures, three variants can be implemented according to the method of the invention.

  a) A first variant consists in cooling the intake air of the station gas turbines by a refrigeration cycle. This refrigeration cycle can be either a cycle based on the compression of a refrigerant (mechanical energy cycles) or an absorption cycle where the energy is supplied in thermal form. In this case the heat required in the absorption cycle is provided by a hot water or steam boiler which can be either a burner boiler or a recovery boiler on the exhaust gas turbines. It can also be taken by an exchanger on the gas circuit at the outlet of the compressor if the compression ratio induces a sufficient temperature.

  The whole of the calories can be rejected in the ambient atmosphere by aircoolers of the circuit of water, or possibly, if it is more economic in investments, rejected in the gas by an exchanger, at the exit or the entrance of the station.

  The increased power of the gas turbines therefore allows a higher compression ratio and a lower pressure at the inlet of the station at the arrival of the section of gas pipeline upstream.

  The water recovered by the condensation in the air cooler can, if necessary, be reinjected upstream of the combustion chambers of the turbine in the hottest periods, to obtain an additional gain in power, the adoption of this the solution is a function of the climatic conditions (night-day variation of temperature and degree of humidity of the air).

  This variant is represented by the diagram of FIG.

  The air of the gas turbine, after passing through the filter (601), is cooled in the airleau exchanger (602) by the cold water optionally glycoled, from the refrigeration module (607). The air can be cooled to a temperature between 4 C and 15 C depending on the characteristics of the refrigeration module and the power increase needs of the gas turbine to consider.

  The water, condensed in the exchanger (602) and separated in the droplet separator (603), can be optionally stored in the capacity (605) and used for reinjection under pressure upstream of the combustion chambers of the turbine, during the hot periods of the day, via a filtration, treatment and pumping module (606).

  The refrigeration module (607) can be based either on a compression cycle of a refrigerant (mechanical energy or electrical energy) or on an absorption cycle. In this case, the thermal energy (hot water for lithium bromide cycles, steam for ammonia cycles) can be taken by a hot loop with a recovery boiler on the exhaust gases of the gas turbine. via the beam (608), either simply provided by a specific small boiler not shown in the diagram and / or by recovery on the gas at the compression outlet (611).

  (b) A second variant consists of not only cooling the air of the gas turbines, but also of refrigerating the gas at its introduction in the next section, in addition to the cooling given by the air coolers located after the compression. The gas refrigeration level at the inlet of a section must be such that, given the temperature reduction due to the isenthalpic expansion, its temperature does not drop below 0 C to avoid frost problems. of soil, which amounts to setting an inlet temperature in the pipeline of nearly 10 C if the pressure drop is 20 bars in the section considered.

  This results in virtually unchanged flow conditions whatever the ambient temperature and therefore an almost constant transport capacity equivalent to or even greater than that allowed by an ambient temperature of 5 to 10 C with conventional stations equipped with the same turbines. gas.

  However, refrigerating the gas requires a cooling contribution much higher than that needed to refrigerate air from gas turbines, because the mass flow rates of gas in a gas pipeline are commonly 4 to 5 times greater than those of the air required for turbines stations, and the heat capacity of the gas more important than that of air.

  For this reason, most or all of this cooling of the gas emitted on a section is obtained according to the method of the invention by a heat exchange, between the inlet and the outlet of the gas of a station, taking advantage of the that the station entry temperature is normally lower, of the order of 10 C, than the outlet temperature of the stations, because of the almost isenthalpic expansion in the upstream section; the pipeline section can then be considered as an expansion valve, that is to say a refrigerating machine: the energy is supplied by the turbo compressor unit, whose required compression power is increased in proportion to the increase the effective volume of gas at the suction: the latter is inverse function of the density, and it is reduced because of the heating in the exchangers where are recovered his frigories. This increase in power is precisely made possible by the increase in power of the gas turbine due to the refrigeration of the air.

  In order for the station input gas to be able to cool not only the output gas but also the air-cooling water circuit of the gas turbines to around 5 C maximum (to obtain air at 10/15 C), it is necessary that the temperature of the inlet gas is barely higher than 0 C.

  If, in view of the characteristics of the pipeline and the temperature and the heat transfer coefficient of the soil, this is not the case, an additional refrigeration loop can make it possible to obtain the level of cold required by the refrigeration of the air.

  Obviously, this low temperature level of the gas entering the station is not necessarily present at the first station of a gas pipeline, the gas coming from the field gas treatment plants which generally deliver a gas at a temperature higher than C. In this case, this first station must include a much larger cold loop capable of providing tens of megawatts needed to cool the gas.

  As a result, this mixed air / gas refrigeration solution at pipeline stations is mainly applicable for a long pipeline with many stations, while for an intervention to remove a bottleneck. in summer, on a given section of an existing pipeline, it is better, in the first stage, resort to a more limited intervention according to the first variant on the downstream station of the section considered.

  The described applications correspond to regional gas pipelines with high ambient temperature differences, and with a soil that does not have a too high coefficient of thermal conductivity and with gas flow temperatures maintained above 0 C.

  They can also be applied with gas temperatures lower than 0 C in the following two cases: - pipes in an arctic environment, where the ground is permanently frozen at 1 m depth (permafrost); it is precisely necessary to avoid that the compressed gas is sent, in summer, to a temperature higher than 0 C (-5 C to -10 C in general) to prevent the melting of this permafrost. In this case, the cold loop cooling air must be regulated in flow to avoid causing air icing. The method of the invention makes it possible to reduce the cost of refrigeration of the intermediate stations which no longer need specific refrigeration installations and to increase the power of the gas turbines in the summer and therefore, if necessary, the flow rate. allowing lower station arrival pressure; - Offshore pipelines where the cooling of the gas to -20 C temperatures provides, at the high pressures generally considered, a considerable gain in density and therefore transport capacity. But this requires that the tube is then insulated (with a thickness of insulation keeping the external temperature above 0 C) and not just coated with concrete.

  The economic advantage of such a solution for offshore depends on the comparison between the extra cost of this insulation, compared to that of a larger diameter pipe to achieve the same result on the pressure drop, also the l Interest is more evident if the diameter adopted is already the maximum diameter for the laying conditions considered. In addition the evaluation must take into account the gain on the compression power of the next station that receives a cold gas.

  The solutions of the second variant do not differ from those of the first variant as regards the air circuit of the gas turbine. They differ in the natural gas circuit and the refrigeration module and its associated equipment (refrigerant condenser, and possibly boiler and hot loop) which can be totally removed, where intervene only in addition to the cold provided by the station input gas.

  A first alternative is represented by the diagram of FIG.

  The heat exchanges between inlet gas, outlet gas and cooling water of the turbine air are made by the same loop. The water cooled in the inlet / water gas exchanger (712) is sent, after possibly additional cooling in a refrigeration module (707), in the exchanger (702).

  However, it comes out at a rather low temperature because the flow of water is important; it must in fact transit heat exchanges between incoming gas and outgoing gas which are much greater than that required for cooling the air. This water, at a low temperature, then enters via the pump (714) into the outgoing gas / water heat exchanger (713) where it heats up to the outlet temperature of the air cooler, minus the gap at the end. hot. The heated water then enters the incoming gas / water temperature exchanger (712) where it cools by heating the gas that goes to the compressor inlet.

  The water, condensed in the exchanger (702) and separated in the droplet separator (703), can be optionally stored in the capacity (705) and used for reinjection under pressure upstream of the combustion chambers of the turbine, during the hot periods of the day, via a filtration, treatment and pumping module (706).

  The loop water was thus the heat transfer vehicle between incoming gas and outgoing gas on the one hand, and for a small part, the coldest level, towards the inlet air of the turbine (s). (s) gas.

  The refrigeration module (707) can be based either on a compression cycle of a refrigerant (mechanical energy or electrical energy), or on an absorption cycle. In this case, the thermal energy (hot water for lithium bromide cycles, steam for ammonia cycles) can be taken by a hot loop with a recovery boiler on the exhaust gases of the gas turbine. via the beam (708), either simply provided by a specific small boiler not shown in the diagram and / or by recovery on the gas output compression (711).

  Bypasses ("bypass") allow to return to a conventional scheme in case of difficulty or when the pipeline runs at partial load and therefore does not provide the same cold due to a lower trigger, but does not require no plus maximum performance at compressor stations.

  A second alternative is represented by the diagram of FIG.

  The heat transfer between incoming gas / off gas is effected by a gas / gas exchanger (812) which makes it possible to obtain this transfer with lower temperature differences at the cost of higher cost exchangers.

  The air of the gas turbine (s) is always cooled by a specific cold water loop which is cooled by the gas entering the gas / water heat exchanger (813) and, if necessary, by a module refrigeration system (807) similar, but of lower power than that described for the first level solutions.

  As in the previous variants, the water, condensed in the exchanger (802) and separated in the droplet separator (803), can be optionally stored in the capacity (805) and used for reinjection, under pressure, upstream of the combustion chambers of the turbine, during the hot periods of the day, via a filtration module, treatment and pumping (806).

  (c) A third alternative is to look for increases in power from gas turbines at larger compressor stations by cooling the air to temperatures below 0 C, for example, if it is considered cost-effective depending on the characteristics of the pipeline. , -20 C.

  This cooling below 0 C is obtained by using the refrigeration system of the air by flow against the current in contactors placed at the aspirations of the turbines, with glycol cooled to 25 ° C, according to the arrangements described above for applications relating to LNG terminals and gas liquefaction plants.

  In this case, the cold must be preferentially supplied to the glycol by ammonia absorption refrigeration modules.

  The heat energy required by this absorption cycle as well as that required for the reboiling of the glycol regeneration column may preferably be taken from the recovery boilers located on the exhaust gas turbines, but may also, in the where natural gas is inexpensive, come from an auxiliary boiler.

  This third variant can be applied either to solutions where only the air is cooled or to solutions where the natural gas to be transported is also cooled by ingoing gas / exhaust gas exchange.

  In this case the refrigeration module can also be used if necessary in addition to refrigeration on the gas if this is required due to excessive heat loss due to soils with higher thermal conductivity.

  This variant is represented by the diagram of FIG. 9.

  This scheme concerns the case where the greater cooling of the air is combined with a cooling of the natural gas by ingoing gas / exhaust gas exchange. For simplicity of description only one gas turbine is shown.

  The cold, produced in the ammonia absorption refrigeration module (907), is transferred to the glycol loop. The cold glycol is sent into the contactor where it cools the air and heats up.

  The glycol regeneration circuit is similar to that shown in the diagram of FIG.

  At the bottom of the contactor, the glycol at a temperature lower than that of the air by a few degrees, is taken up by a pump (930). After pressurized by the pump (930) the glycol is sent to the top of the regeneration column (931) to ensure reflux; then, after heating in the exchanger (935), against the current of the glycol leaving the reboiler (936) of the regeneration column (932), the glycol to be regenerated and heated is sent to this column (932).

  The regenerated glycol leaving the reboiler (936) is taken up by a pump (950), then successively cooled in the exchanger (935) by the glycol to be regenerated, optionally in the exchanger (913) by the cold gas entering the station , then in the refrigeration module (907), before being injected into the contactor (921) at approximately -25 ° C.

  The reboiling heat is preferably provided by a recovery boiler located in the exhaust of the gas turbine via the beam (940). This boiler also supplies heat to the ammonia absorption refrigeration module (907). If this is considered more economical, this recovery boiler can be replaced by a specific boiler heated with natural gas.

  The water vapor extracted from the air escaping at the top of the regeneration column may, if necessary, be condensed in an air cooler and injected during hot periods into the gas turbines at the combustion chambers.

  The diagram of the gas circuit of FIG. 9 is the same as that described in variant (b), the second alternative of the process of the invention applied to the pipelines described above but, if necessary, could also be identical to the diagram of FIG. the first alternative of this variant.

  Also, this solution for cooling the suction air of gas turbines below 0 ° C., obtained by contact with a cold glycol solution, can be applied to the first variant of the application to gas pipelines described above. before, version that does not include heat exchange gas entering I gas outgoing.

  According to a fourth embodiment, the method of the invention is applied to gas reinjection plants in the hydrocarbon deposits.

  In a reinjection plant, the gas is compressed from the delivery pressure of the gas (of the order of 40 to 80 bar) to very high pressures necessary to obtain, at the bottom of the deposit, a pressure that is clearly greater than the pressure. from the field (usually several hundred bars).

  As a result, the specific power consumed by the compressor is very high and most often requires 2 or 3 compressors in series whose output temperatures are high (100 and 120 C) and require intermediate air coolers.

  Commonly the specific power per ton of reinjected gas requires, at the gas turbines which drive the compressors, an air tonnage greater than twice the tonnage of gas to be compressed.

  The invention consists in providing a refrigerant circuit, the role of which is to refrigerate at the same time and in series the air of the gas turbine and, if necessary, the gases at the suction of the compressors, which increases the power at the turbine and decreases the specific power at the compressor.

  In addition, in the case of absorption cycles, the energy source of this cycle, particularly in the case of lithium bromide cycles, can advantageously be obtained by heat exchange with the gases at the discharge of the compressors, decreasing by even the charge of the air coolers after compression. If higher temperatures are required by the chosen absorption cycle, it can be provided by a recovery boiler on the gas turbine or by a specific boiler.

  For this application also, it is conceivable to cool the inlet air of gas turbines to a temperature below 0 C so as to obtain a power increase gas turbines more consistent. As in previous applications, this is achieved by cooling the air in a contactor in which a cold glycol solution which absorbs the moisture of the air and which is regenerated before being sent to a refrigeration module after which it is recycled to the contactor.

  In this case the refrigeration module should preferably be an ammonia absorption module capable of producing cold at the desired level.

  The thermal energy supplied to this module can always be supplied in part by a loop of hot water recovering the heat at the compressor outlet, but must be completed by that recovered at the outlet of the (of one) turbine ( s) gas by a recovery boiler which can then also provide the reboiling energy of the glycol regeneration column. If necessary it can be more economical, on a site where in principle the gas is cheap to replace this boiler recovery by a simple boiler gas.

  In both cases (cooling the air above and below 0 C) the water extracted from the air and recovered respectively at the bottom of the air exchanger or the glycol solution for the first case, or The top of the regeneration column can be re-injected via a re-injection module into the turbine (s) at the combustion chambers during the hottest periods so as to further increase the available power by a few percent.

  In the simplest version (cooling of the air at about 5 ° C.), the invention is represented by the diagram of FIG. 10. The refrigeration installation, considered here in the description, is a bromide absorption cycle. lithium. It consists of: - the module (007) which comprises the absorber (s) and the evaporator (s), the steam air condenser (007 bis).

  The heat is supplied to the evaporators of this module by a hot loop which circulates the water in gasleau exchangers (017 and 018), located directly to the discharge of the compressors, upstream of the air coolers (013 and 014).

  The cold is brought in a first stage to the airleau air inlet air exchanger (s) gas (s) (002), then in parallel, the gasleau exchangers (015 and 016) located at l suction of the compressors (011 and 012). Control valves make it possible to optimize the distribution of the flow on the exchangers of the aspirations giving the maximum gain on the required compression power.

  The water, condensed in the exchanger (002) and separated in the droplet separator (003), can be optionally stored in the capacity (005) and used for reinjection, under pressure upstream of the combustion chambers of the turbine, during the hot periods of the day, through a filtration module, treatment and pumping (006).

  This description, which relates to a single gas turbine, obviously applies if several turbines, driving compressors in series or in parallel, are considered. In this case, the refrigeration module and the cold and hot loops are common to several turbines.

  In the case of refrigerant compression cycles, the exchangers (017 and 018) are not necessary.

  Similarly, if the choice of absorption cycles requires a supply of heat at a temperature level higher than that available at the discharge of the compressors, the heat loop exchangers (017 and 018) are to be replaced, either by a boiler heat recovery on the exhaust gas of one of the turbines, (019) either by a specific boiler not shown in the diagram.

  Where appropriate, solutions comprising a cooling of the intake air of the gas turbines of up to -20 ° C. and obtained by contact with a solution of cold glycol, as described in the above applications, may also be selected for these gas reinjection installations; they bring a greater power increase, allowing for example to reduce the number of compression lines corresponding to a given gas turbine model, resulting in a very significant reduction in the amount of investment.

Claims (16)

  A method for increasing the capacity and efficiency of gas plants of the type comprising at least one gas turbine, which method comprises cooling the air entering the gas turbine (s) with a refrigeration loop. , the cold being produced from the gas process itself, and / or by separate refrigeration modules; the cold being transferred to the air of the gas turbine (s), either by exchangers or by direct contact in a contactor.   2. The method of claim 1, wherein the air entering the gas turbine (120; 520; 920) is cooled by a glycol solution in a contactor (121; 521; 921) preferably provided with a lining. (123; 523,923).   The process according to claim 2, wherein the glycol solution charged with water, extracted from the air, is regenerated in a column (132; 532; 932) whose reboiler (136; 536; 936) is preferably heated by a hot loop, drawing its energy from a beam (140; 540; 940) located in the gas turbine exhaust.   4. The method according to claim 3, wherein when the gas plant is a reception and regasification terminal of liquefied natural gas, the regenerated glycol is cooled by regasification tubular exchangers (160), in which circulates, on the tube side, the liquefied natural gas to be regasified (101).   The method of claim 2, wherein when the gas plant is a natural gas liquefaction plant, the glycol is cooled in propane evaporators (507; 508; 509) added in parallel to the propane refrigeration circuit constituting the first stage of cooling the gas to be liquefied.   The method of claim 2 wherein, when the gas plant is a pipeline compressor station, the glycol is cooled by a refrigeration module (907).   7. The method of claim 6, wherein the glycol is pre-cooled by the gas entering the station via a heat exchanger (913).   The method of claim 1, wherein the air entering the gas turbines (220; 320; 420; 420 bis; 620; 720; 820; 020) is cooled by heat exchangers (202; 302; 402; 602; 702; 802; 002) in which circulates a heat transfer fluid, preferably an aqueous solution of glycol or methanol.   9. The method of claim 8, wherein the heat transfer fluid cooling the air entering the gas turbines by the exchangers (202; 302), is partially or completely cooled in propane evaporators (207, 208; 307). , 308) added in parallel to the propane refrigeration circuit constituting the first cooling stage of the gas to be liquefied.   The method of claim 8, wherein the heat transfer fluid cooling air entering the gas turbines through the heat exchangers (602; 702; 802) is cooled partially or completely by compression mechanical refrigeration modules (607). 707; 807).   11. The method of claim 8, wherein the heat transfer fluid cooling the air entering the gas turbines by the exchangers (402; 602; 702; 802; 002) is cooled, partially or completely by refrigeration modules. absorption (407; 607; 707,807; 007).   The method of claim 11, wherein heat is supplied to the absorption refrigeration modules (407; 607; 707; 807; 007) through a heat-retrieval loop (419; 608; 708; 808,008); located in the exhaust gases of the gas turbine and / or, where appropriate, on exchangers located after the gas compressors (711 017; 018).   The method of claim 8, wherein the condensed water recovered at the bottom of the exchangers (202; 302; 402; 602; 702; 802; 002) in manifolds (204; 304; 404; 604; 704; 804; 004) is, after storage in capacitors (205; 305; 405; 605; 705; 805; 005), reinjected via a feedback module (206; 306; 406; 606; 706; 806; 006) into the turbines (220, 220 bis, 320, 420, 620, 720, 820, 020) at the combustion chambers.   14. The method of claim 8, wherein the condensed water recovered at the bottom of the exchanger (202) in the collector (204) is, after storage in a capacity (205) reinjected via a reinjection module (206). in the turbine (s) (220 bis) at a vaporizer (202 bis).   15. The method of claim 3 or 4, wherein the water leaving the regeneration columns of the glycol (132; 532; 932) is recondensed in aircondensers to be reinjected into the turbine (s) (120; 520; 920) or in the turbine (520 bis).   16. A process according to claim 1, wherein when the gas plant is a pipeline compressor station, the gas to be compressed arriving in the compressor station countercurrently compresses the compressed gas exiting an air cooler, either in gas / gas exchangers (812; 912) or in gas / water exchangers (712; 713).