PROCESS FOR ENABLING CONSTANT POWER OUTPUT IN A POWER PLANT INTEGRATED WITH A CARBON DIOXIDE CAPTURE UNIT

The invention relates to a process for enabling a constant power output in a power plant integrated with a carbon dioxide (CO2) capture unit.

A substantial portion of the world's energy supply is provided by combustion of fuels, especially natural gas or synthesis gas, in a power plant. Generally the fuel is combusted in one or more gas turbines and the resulting gas is used to produce steam. The steam is then used to generate power. Combustion of fuel results in the production of CO2, which needs to be disposed of. During the last decades there has been a substantial global increase in the amount of CO2 emission to the atmosphere.

Following the Kyoto agreement, CO2 emission has to be reduced in order to prevent or counteract unwanted changes in climate.

The CO2 concentration of a gas turbine flue gas depends on the fuel and the combustion and heat recovery process applied and is generally relatively low, typically in the range of 3-15%. Thus, it is desirable to separate and concentrate the CO2 from the exhaust gas because it will be too expensive to compress and deposit the whole flue gas . For this reason, it is advantageous to use a dedicated CO2 capture unit, to remove CO2 from the flue gas and generate a concentrated CO2 stream. A process for carbon dioxide recovery and power generation is described for example in EP 1,688,173. In EP 1,688,173, a power plant integrated with a CO2 capture

unit comprising an absorber and a regenerator is described. For the regenerator, a plurality of heating means in multiple stages is provided and plural kinds of steam with different pressures are extracted from a gas turbine and supplied to the absorbing liquid. In the process described in EP 1,688,173, the reduction in turbine output due to steam extraction is said to be suppressed. However, the use of additional heating means results in the need for additional equipment as well as a more complex process. In addition, the power plant described in EP 1,688,173 is designed to take into account the power requirements of the CO2 capture unit. In the event that the CO2 capture unit is not in operation, the power plant output would be higher than required.

Thus, there is still a need for an optimised and simple process to provide a power output in a power plant integrated with a CO2 capture unit, enabling a constant power output even if the CO2 capture unit is not in operation.

To this end, the invention provides a process for enabling constant power output in a power plant integrated with a CO2 capture unit, wherein the power plant comprises at least one gas turbine coupled to a heat recovery steam generator unit and the CO2 capture unit comprises an absorber and a regenerator, the process comprising the steps of:

(a) introducing hot exhaust gas exiting a gas turbine into a heat recovery steam generator unit to produce a first amount of steam, which first amount of steam is used to generate power, and a flue gas comprising carbon dioxide;

(b) removing carbon dioxide from the flue gas comprising carbon dioxide by contacting said flue gas with absorbing liquid in an absorber to obtain absorbing liquid enriched in carbon dioxide and a purified flue gas; (c) regenerating the absorbing liquid enriched in carbon dioxide by contacting the absorbing liquid enriched in carbon dioxide with a stripping gas at elevated temperature in a regenerator to obtain regenerated absorbing liquid and a gas stream enriched in carbon dioxide;

(d) combusting an amount of fuel in the heat recovery steam generator unit to produce a second amount of steam, wherein the amount of fuel is such that the second amount of steam is sufficient to provide at least 80% of the heat needed for the regeneration of the absorbing liquid.

The phrase "constant power output" as used herein refers to the circumstance that the power output is comparable to a power output the power plant would have had if no CO2 capture unit were present. Constant power output as used herein thus does not imply that there will be no fluctuations in power output over a period of time.

The process enables a power output of the power plant which is independent of the needs of the CO2 capture unit. The power output will not change significantly even if the CO2 capture unit is not in operation. Thus, the power plant can be sized and designed to operate without having to take into account the loss of power due to fulfilment of the requirements of the CO2 capture unit . Furthermore, the process offers additional flexibility compared to a power plant without additional fuel combustion in the heat recovery steam generator unit. The amount of fuel combusted in step (d) can be

adjusted to control the additional amount and type of steam produced. Thus, the process offers additional means to control the steam production in the heat recovery steam generator unit. Another advantage is that combustion of the amount of fuel in step (d) requires oxygen. The exhaust gas from the gas turbine comprises, in addition to CO2, usually also oxygen. Part of the oxygen from the exhaust gas is used for the fuel combustion. As a result, the flue gas exiting the heat recovery steam generator unit has a relatively lower concentration of oxygen and a relatively higher concentration of CO2 (higher CO2/O2 ratio) . CO2 is removed by contacting the flue gas with absorbing liquid. The presence of oxygen can have a negative effect on the absorbing liquid. Especially when the absorbing liquid comprises an amine compound, degradation of the amine and/or formation of heat stable salts can take place. By lowering the amount of oxygen in the flue gas, these problems are reduced or avoided. In the process, a power plant comprising at least one gas turbine is used. Typically, fuel and an oxygen- containing gas are introduced into a combustion section of the gas turbine. In the combustion section of the gas turbine, the fuel is combusted to generate a hot combustion gas. The hot combustion gas is expanded in the gas turbine, usually via a sequence of expander blades arranged in rows, and used to generate power via a generator. Suitable fuels to be combusted in the gas turbine include natural gas and synthesis gas. In step (a), hot exhaust gas exiting the gas turbine is introduced into to a heat recovery steam generator unit, where heat contained in the hot exhaust gas is used to produce a first amount of steam.

Preferably, the hot exhaust gas has a temperature in the range of from 350 to 700 ⁰ C, more preferably from 400 to 650 ⁰ C. The composition of the hot exhaust gas can vary, depending on the fuel gas combusted in the gas turbine and on the conditions in the gas turbine.

Generally, the hot exhaust gas comprises in the range of from 10 to 15 % of O2. Generally, the hot exhaust gas comprises in the range of from 3 to 6 % of CO2.

The heat recovery steam generator unit is any unit providing means for recovering heat from the hot exhaust gas and converting this heat to steam. For example, the heat recovery steam generator unit can comprise a plurality of tubes mounted stackwise. Water is pumped and circulated through the tubes and can be held under high pressure at high temperatures. The hot exhaust gas heats up the tubes and is used to produce steam.

Suitably, the heat recovery steam generator unit can be designed to produce one, two or three types of steam: high-pressure steam, intermediate pressure steam and low- pressure steam. Preferably, the steam generator is designed to produce at least a certain amount of high- pressure steam, because high-pressure steam can be used to generate power. Suitably, high-pressure steam has a pressure in the range of from 90 to 150 bara, preferably from 90 to 125 bara, more preferably from 100 to 115 bara. Suitably, low-pressure steam is also produced, the low-pressure steam preferably having a pressure in the range of from 2 to 10 bara, more preferably from to 8 bara, still more preferably from 4 to 6 bara. This low- pressure steam is used for the regeneration of the absorbing liquid comprising CO2.

The invention offers the possibility of controlling the amount and type of steam produced in the heat

recovery steam generator unit, by adjusting the amount of fuel added to the heat recovery steam generator unit (vide infra) . Preferably, low-pressure steam piping is used to deliver the heating steam from the heat recovery steam generator to the CO2 capture unit. Suitably, this low steam piping is arranged in a closed loop to segregate the steam produced which is used for power production from steam used in process heat exchangers

The heat recovery steam generator unit emits a flue gas comprising CO ₂ . The composition of the flue gas depends among others on the type of fuel used in the gas turbine. Suitably, the flue gas comprises in the range of from 0.25 to 30 % (v/v) of CO ₂ , preferably from 1 to 20 %

(v/v) . The flue gas usually also comprises oxygen, preferably in the range of from 0.25 to 20 % (v/v), more preferably from 5 to 15% (v/v) , still more preferably from 1 to 10 % (v/v) . The preferred ranges are achieved with an increasing amount of fuel combusted in the heat recovery steam generator unit, resulting in a decrease of the oxygen content as oxygen is used in the combustion. In step (b) , CO ₂ is removed by contacting the flue gas with an absorbing liquid in an absorber. The absorbing liquid may be any absorbing liquid capable of removing CO ₂ from a flue gas stream. In particular, absorbing liquids capable of removing CO ₂ from flue gas streams having relatively low concentrations of CO ₂ and comprising oxygen are suitable. Such absorbing liquids may include chemical and physical solvents or combinations of these. Furthermore, in the event that the flue gas stream comprises an appreciable quantity of oxygen, suitably in the range of from 1 to 20 % (v/v) of oxygen, preferably a corrosion inhibitor is added to the absorbing liquid. Suitable corrosion inhibitors are

described for example in US 6,036,888.

Suitable physical solvents include dimethylether compounds of polyethylene glycol.

Suitable chemical solvents include ammonia and amine compounds .

In one embodiment, the absorbing liquid comprises one or more amines selected from the group of monethanolamine (MEA), diethanolamine (DEA), diglycolamine (DGA), methyldiethanolamine (MDEA) and triethanolamine (TEA) . MEA is an especially preferred amine, due to its ability to absorb a relatively high percentage of CO2 (volume CO2 per volume MEA) . Thus, an absorbing liquid comprising MEA is suitable to remove CO2 from flue gases having low concentrations of CO2, typically 3-10 volume % CO2.

In another embodiment, the absorbing liquid comprises one or more amines selected from the group of methyldiethanolamine (MDEA), triethanolamine (TEA), N, N'- di (hydroxyalkyl) piperazine, N, N, N ' , N' - tetrakis (hydroxyalkyl) -1, 6-hexanediamine and tertiary alkylamine sulfonic acid compounds.

Preferably, the N, N' -di (hydroxyalkyl) piperazine is N, N ' -d- ( 2-hydroxyethyl) piperazine and/or N,N'-di-(3- hydroxypropyl ) piperazine . Preferably, the tetrakis (hydroxyalkyl) -1, 6- hexanediamine is N, N, N' ,N'-tetrakis (2-hydroxyethyl) -1, 6- hexanediamine and/or N, N, N' , N' -tetrakis (2-hydroxypropyl) - 1, 6-hexanediamine .

Preferably, the tertiary alkylamine sulfonic compounds are selected from the group of 4- (2- hydroxyethyl) -1-piperazineethanesulfonic acid, 4- (2- hydroxyethyl) -1-piperazinepropanesulfonic acid, 4- (2-

hydroxyethyl) piperazine-1- ( 2-hydroxypropanesulfonic acid) and 1, 4-piperazinedi ( sulfonic acid).

In yet another embodiment, the absorbing liquid comprises N-ethyldiethanolamine (EDEA) . In an especially preferred embodiment, the absorbing liquid comprises ammonia.

It has been found that, especially when using an absorbing liquid comprising an amine, better absorption of CC>2 is achieved when absorption takes place at relatively low temperature and at elevated pressure.

Elevated pressure means that the operating pressure of the CC>2 absorber is above ambient pressure. Preferably, the operating pressure of the absorber is in the range of from 50 to 200 mbarg, more preferably from 70 to 150 mbarg. As the pressure of the flue gas will typically be close to ambient pressure, preferably the flue gas is pressurised prior to entering the absorber. As the temperature of the flue gas will typically be relatively high, preferably the flue gas is cooled prior to entering the absorber.

In step (c), the absorbing liquid enriched in carbon dioxide is regenerated by contacting the absorbing liquid enriched in carbon dioxide with a stripping gas at elevated temperature in a regenerator to obtain regenerated absorbing liquid and a gas stream enriched in carbon dioxide. It will be understood that the conditions used for regeneration depend inter alia on the type of absorbing liquid and on the conditions used in the absorption step. Suitably, regeneration takes place at a higher temperature and a lower pressure than the absorption. Preferred regeneration temperature are in the range of from 100 to 200 ⁰ C. Preferred regeneration pressures are in the range of from 1 to 5 bara.

In the event that the absorbing liquid comprises ammonia, suitably the absorbing step is performed at temperatures below ambient temperature, preferably in the range of from 0 to 10 ⁰ C, more preferably from 2 to 8 ⁰ C. The regeneration step is suitably performed at temperatures higher than used in the absorption step. When using an absorbing liquid comprising ammonia, the CC>2-enriched gas stream exiting the regenerator has a elevated pressure. Suitably, the pressure of the Cθ2~ enriched gas stream is in the range of from 5 to 8 bara, preferably from 6 to 8 bara. In applications where the CC>2-enriched gas stream needs to be at a high pressure, for example when it will be used for injection into a subterranean formation, it is an advantage that the CO2- enriched gas stream is already at an elevated pressure.

Normally, a series of compressors is needed to pressurise the CC>2-enriched gas stream to the desired high pressures. A CO2~enriched gas stream which is already at elevated pressure is easier to further pressurise. In step (d) , the heat requirements of the regeneration step are at least partly met by combusting an amount of fuel in the heat recovery steam generator unit to produce a second amount of steam. The amount of fuel combusted is such that the second amount of steam is sufficient to provide at least 80% of the heat needed for the regeneration of the absorbing liquid. Preferably, the second amount of steam obtained in step (d) is used to provide at least 90%, more preferably at least 95%, and still more preferably 100% of the heat needed for the regeneration of the absorbing liquid.

A preferred way of performing of step (d) is to monitor the power generated by the heat recovery steam generator unit and adjust the amount of fuel introduced

into the heat recovery steam generator unit in dependence of the amount of power generated by the heat recovery steam generator unit. As explained earlier, in the heat recovery steam generator unit preferably high pressure steam is produced in a steam turbine, which high pressure steam is converted to power, for example via a generator coupled to the steam turbine . The power output of the generator coupled to the steam turbine will decrease when the CC>2 capture unit is in operation, due to the amount of steam extracted from the heat recovery steam generator unit needed to heat up the regenerator of the CO2 capture unit. By monitoring the output of generator coupled to the steam turbine of the heat recovery generator unit, the amount of fuel combusted in the heat recovery steam generator unit can be adjusted to compensate for the loss of power due to fulfilling the heat requirements of the CO2 regenerator. In the event that the output decreases, the amount of fuel combusted can be increased.

Preferably, the necessary amount of fuel to be combusted is predetermined. The power output of the generator coupled to the steam turbine when the CO2 capture unit is not in operation is taken as a base case and the amount of fuel to be combusted in order to achieve the same output when the CO2 capture unit is in operation is then determined.

Suitable fuels to be combusted in the heat recovery steam generator unit include natural gas and synthesis gas .

Combustion of the amount of fuel in step (d) requires the presence of oxygen. This oxygen can be supplied separately to the heat recovery steam generator unit, but preferably the hot exhaust gas comprises oxygen and at least part of this oxygen is used in the

combustion of the fuel in step (d) . As a result of using oxygen from the hot exhaust gas, the amount of oxygen in the flue gas exiting the heat recovery steam generator unit will be lower. This is favourable for the CO2 absorption process, especially when an amine absorbing liquid is used. Oxygen can cause amine degradation. A lower oxygen content of the flue gas will therefore result in less amine degradation.

Preferably, the gas stream enriched in carbon dioxide is pressurised using a carbon dioxide compressor to produce a pressurised carbon dioxide stream. The carbon dioxide compressor needs to be driven. In a preferred embodiment, part of the steam produced in the heat recovery steam generator unit is used to drive the carbon dioxide compressor. In this manner, an additional heat integration is achieved.

The pressurised CO2 stream can be used for many purposes, in particular for enhanced recovery of oil, coal bed methane or for sequestration in a subterranean formation. In a preferred embodiment, the pressurised CO2 stream is used for enhanced oil recovery. By injecting CO2 into an oil reservoir, the oil recovery rate can be increased. Typically, the pressurised CO2 stream is injected into the oil reservoir, where it will be mixed with some of the oil which is present. The mixture of CO2 and oil will displace oil which cannot be displaced by traditional injections.

The invention will now be illustrated, by means of example only, with reference to the accompanying figure 1.

In figure 1, a power plant comprising a gas turbine (1), a heat recovery steam generator unit (2) and a CO2

capture unit (3) is shown. In the gas turbine, an oxygen- containing gas is supplied via line 4 to compressor 5. Fuel is supplied via line 6 to combustor 7 and combusted in the presence of the compressed oxygen-containing gas. The resulting combustion gas is expanded in expander 8 and used to generate power in generator 9. Remaining exhaust gas comprising CO2 and oxygen is led via line 10 to a heat recovery steam generator unit 2. In the heat recovery steam generator unit, water is heated against the hot exhaust gas in heating section 11 to generate steam. The steam is led via line 12 into a steam turbine 13 to produce additional power in generator 14. An amount of fuel is led via line 15 to the heat recovery steam generator unit and combusted, using oxygen from the exhaust gas, to produce additional steam. Hot flue gas comprising CO2 and oxygen is led via line 16 to an amine absorber 17. Preferably, the hot flue gas is first cooled in a cooler (not shown) and the cooled flue gas is pressurised using a blower (not shown) prior to entering the amine absorber. In amine absorber 17, CO2 is transferred at elevated pressure from the flue gas to the amine liquid contained in the amine absorber. Purified flue gas, depleted in carbon dioxide, is led from the amine absorber via line 18. Amine liquid, enriched in CO2 is led from the amine absorber via line 19 to a regenerator 20. In the regenerator, amine liquid enriched in CO2 is depressurised and contacted with a stripping gas at elevated temperature, thereby transferring CO2 from the amine liquid to the stripping gas to obtain regenerated amine liquid and a gas stream enriched in CO2. The gas stream enriched in CO2 is led from the regenerator via line 21. Preferably, the gas stream

enriched in CO2 is pressurised using a CO2 compressor (not shown) and the pressurised CO2 stream is used elsewhere. Regenerated amine liquid is led from the regenerator via line 22 to the amine absorber. The heat needed to provide the elevated temperature of the regenerator is supplied using low pressure steam, which is led from steam turbine 13 via line 23 to the regenerator .