WO1994016992A1

WO1994016992A1 - Combined power environmental cycle (cpec)

Info

Publication number: WO1994016992A1
Application number: PCT/US1993/011644
Authority: WO
Inventors: Leon Awerbuch; Jack Z. Abrams; Bruce R. Gilbert
Original assignee: Bechtel Group Inc.
Priority date: 1993-01-25
Filing date: 1993-12-01
Publication date: 1994-08-04
Also published as: AU5683694A

Abstract

The invention discloses a combined power environmental cycle utilizing crude or residual fuel oil as fuel for a gas turbine (8) in areas where gas is not readily available to produce power and a scrubber (26) to clean the flue gas exhausted from the gas turbine to an acceptable environmental level for disposal while concurrently producing condensate for use in the turbine and with fuel used to fire the turbine.

Description

COMBINED POWER ENVIRONMENTAL CYCLE (CPEC)

BACKGROUND OF THE INVENTION The present invention discloses a power cycle based on the use of fuel oil (crude or residual) as the fuel for a combustion gas turbine in areas where gas is not readily available and a scrubber combined with the turbine for cleaning the exhaust gases from the burner section of the turbine of undesirable contaminants produced by the combustion of such fuel oil in the turbine to an environmentally acceptable condition for exhausting to the atmosphere while concurrently producing condensate for use in the turbine or with fuel used to fire the turbine.

Prior Art Gas turbines have been fired by fuel oil in the past. For example, as described in Gas Turbine World, May- June 1992 at page 50 et seq. , Kalaeloa Cogeneration Partners since May 1991 have been commercially operating a nominal 180- MW combined cycle cogeneration plant on the island of Oahu in Hawaii, burning low-sulfur residual fuel oil to provide electric power to the local utility and process steam to a nearby refinery.

Other examples of burning crude or residual fuel oil in a gas turbine are plentiful. It has of course been recognized that burning crude oil as a fuel in producing power can produce a flue gas that is high in undesirable elements and which cannot readily be dispersed off to the atmosphere.

Various patents have been found that address the problem of cleaning a flue gas derived from burning sulfur (and other contaminants) containing fuels. For example, U.S. Patent 4,804,523 issued Feb. 14, 1989 to the assignee of the present invention provides for efficient removal of sulfur dioxide from a flue gas stream in a scrubber using a recirculating aqueous stream containing magnesium hydroxide and magnesium sulfite which together act as S0₂ absorbents. _Magnesium sulfite is derived from magnesium hydroxide, which is the product of a reaction between soluble magnesium from the sea water and calcium hydroxide added to the scrubbing system. Magnesium sulfite and bisulfite are oxidized to magnesium sulfate by the introduction of air. Magnesium sulfate is converted back to magnesium hydroxide by reaction with additional calcium hydroxide, with gypsum as a by¬ product. Gypsum is soluble in large amounts of sea water and may be returned to the ocean without adverse environmental impact.

U.S. Patent No. 4,337,230 issued June 29, 1982, disclosed a method of absorbing sulfur oxides from flue gases in sea water, comprising adding to the sea water calcium based alkali subsequent to the absorption, and then introducing the sea water to which alkali has been supplied into a decarbonation/oxidation reactor to which an oxygen-containing gas is supplied in order to oxidize sulfur oxides in the sea water and to strip carbon dioxide from the sea water. When the sea water has been removed from the decarbonation/ oxidation reactor, calcium based alkali is again added to the sea water in order to increase its pH.

A waste flue gas desulfurizing method is described in U.S. Patent 4,085,194 issued April 18, 1978 in which a waste flue gas containing sulfurous acid gas is contacted directly with sea water, whereby the sulfurous acid gas is absorbed in the sea water and concurrently sulfites are formed in the sea water by the reaction between the sulfurous acid ions and metal ions present in the sea water, and then the carbonic acid component contained in the sea water which is then in the acidic region is released therefrom by a decarbonation operation to restore the pH value of the sea water in the neutral region, and thereafter oxygen contained in air or from other source is introduced into the sulfite- containing sea water to convert said sulfites into sulfates.

A desulphurization process, in which acid components of waste gas are removed by spray drying absorption, using an aqueous suspension of slaked lime or limestone as absorbent with recycling of part of the reaction product to the absorbent, is controlled on the basis of determination of the chloride content of the aqueous suspension including recycled reaction product. The chloride content of the absorbent is used as the basis for (a) controlling the amount of chloride in the aqueous suspension to such a value that a specific chloride content of the spray dried product is between 1 and 7% by weight, and, within this range is related to the difference between the temperature of the desulfurized waste gas and the adiabatic saturation temperature thereof, and/or (b) for controlling the quantity of water evaporated by the spray drying, which is also related to the set forth chloride content, to change the difference between the temperature of the desulfurized waste gas and the adiabatic saturation temperature thereof, to provide a minimum temperature difference so as to maximize the acid base reaction yet maintain an actual temperature difference high enough to avoid sticky products.

Still there is need for an efficient power cycle using liquid fuel oil in a gas turbine and a system from cleaning flue gas from the gas turbine so as to be dischargeable into the atmosphere.

SUMMARY OF THE INVENTION The present invention is directed to a combined power cycle utilizing a gas turbine capable of operating on a crude oil or residual oil fuel combined with a scrubbing process for removing environmentally undesirable contaminants from the gaseous exhaust from the oil fired gas turbine. Turbine efficiency and fuel oil acceptability are also improved utilizing the combined power environmental cycle of the present invention.

In a broad aspect the invention provides a method for producing power using liquid fuel oil wherein the liquid fuel oil is combusted in a combustion gas turbine. Hot flue gases exhausted from the turbine contain sulfur dioxide and water vapor as products of combustion. The hot flue gases are flowed to a sea water scrubber where sulfur dioxide is removed _from the hot flue gases to produce a clean flue gas including water vapor contained therein. The clean flue gas is directed to a flue gas condenser having a sea water heat exchange tube where the water vapor portion of the clean flue gas is condensed. At least a portion of the condensed water vapor is made available as water or steam for injection into the combustion gas turbine to improve its efficiency and to lower the formation of undesirable products of combustion therein. Another portion of the condensed water vapor is made available for cleaning the fuel oil prior to its use in the combustion gas turbine or for emulsifying the fuel oil into an oil-water emulsion to improve the burning characteristics of the fuel oil.

In another aspect the present invention provides a combined power environmental cycle system for producing power using liquid fuel oil particularly where gas is not available to fire the gas turbine. A combustion gas turbine is provided with burners adapted to be fired with liquid fuel oil. The turbine has a turbine exhaust for exhausting hot flue gases which contain sulfur dioxide and water vapor. A source of liquid fuel oil is operably connected to the burner section of the combustion turbine for combustion therein. A sea water scrubber is provided and used for removing sulfur dioxide from hot flue gases. The sea water scrubber has a flue gas inlet, a sea water intake port, a clean flue gas exit port and a liquid effluent exhaust port. Conduit means are arranged to connect the turbine exhaust to the flue gas inlet of the sea water scrubber. There is a sea water source connected by a conduit with the sea water intake port of the sea water scrubber. A flue gas condenser having a sea water heat exchange tube is also connected to the sea water source by a suitable conduit. The flue gas condenser has a sea water inlet, a sea water outlet and a condensate outlet. The clean flue gas exit port of the sea water scrubber is connected to the flue gas condenser. Conduits are operably connected between the condensate outlet of the flue gas condenser and the combustion turbine for making available condensate to the combustion turbine. Conduit means are also operatively connected between the condensate outlet of the flue gas condenser and the source of liquid fuel for making available condensate for use with the liquid oil fuel.

OBJECT OF THE INVENTION

It is a principle object of the present invention to provide a power cycle based on the use of fuel oil (crude or residual) as the fuel for a combustion gas turbine in areas where gas is not readily available and a sea water scrubber combined with the turbine for cleaning the exhaust gases from the burner section of the turbine of undesirable contaminants produced by the combustion of such fuel oil in the turbine to an environmentally acceptable condition for exhausting to the atmosphere while concurrently producing condensate for use in the turbine or with the fuel used to fire the turbine. Other objects and advantages of the present invention will become apparent from the following detailed description read in view of the accompanying drawing which is incorporated herein and made a part of this specification.

BRIEF DESCRIPTION OF THE DRAWING The drawing is process diagram of the combined power environmental cycle in accordance with the present invention.

DETAILED DESCRIPTION OF THE INVENTION

The combined power environmental cycle (CPEC) is schematically illustrated in the drawing. As these shown the power cycle is generally indicated by the area denoted as "A" in the drawing and the environmental cycle is generally indicated by the area denoted as "B" . The cycles are combined to permit use of crude oil or residual oil to fire a combustion gas turbine in areas where gas is not readily available and to provide environmentally acceptable effluents for exhausting from the cycle. Condensate recovered from the environmental cycle is made available for use in the turbine either as injected steam or injected water to improve turbine efficiency and to reduce the formation of undesirable products of combustion in the burner section of the gas turbine. Condensate may also be made available for use with the fuel oil to clean it or to emulsify it to improve the combustion efficiency of the fuel oil in the turbine. The use of crude or residual oil as a fuel for gas turbines is well known. However, the turbine exhaust when using oil as a fuel contains levels of N0_χ and S0₂ which do not meet environmental standards and therefore must be treated before being released.

The following typical data will be useful in order to better understand the environmental problems that can occur when utilizing liquid crude oil to fuel a combustion gas turbine. Table 1 shows an analysis of a typical washed crude oil useful as a fuel in accordance with the invention.

Table 1 Typical Washed Crude Oil Fuel Analysis - Gravity 32.9 - 33.9

- Bottom sediment and water 0.1 max (% vol)

- Wax (% weight) 2.6 max

- Sulfur (% weight) 1.75 - 1.95 - H₂S (ppm) 0 - 30

- Ash (ppm) 15 - 70

- CONRADSON Carbon Residue 2.8 - 4.5 (% weight)

- HHV (MJ/kg) 44.2 - 45.24 - Vanadium 16 - 34

- Calcium (ppm) 1.0 max

- Sodium + Potassium (ppm) 1.0 max

- REID Vapour Pressure2 200 - 380 (mbar) - Viscosity SUS at 37,8°C 47.3 - 44.7

Typical exhaust gas data for a crude oil fired gas turbine at several different conditions is shown in Table II

Table II Exhaust Data For Typical Oil Fired Gas Turbine Condition 1 2 3 4

Fuel Crude Crude Crude Crude

Gas Turbine Exhaust Gas

Temperature (F) 1011.4 969.2 951.0 1054.2 Flow (Lb/Hr) 2021508 2357516 2506392 1707012

Gas Turbine Exhaust Gas Composition

N₂ (% by volume) 74.61 75.64 76.12 74.56 0₂ (% by volume) 14.19 14.22 14.27 14.01 H₂0 (% by volume) 6.50 5.26 4.68 6.62 C0₂ (% by volume) 3.21 3.97 4.02 3.92 AR (% by volume) .89 .91 .91 .89 NO_χ (PPMVD (15% 02) 195 221 232 180

10 10 10 10 7 7 7 7

321 333 336 330 17 17 18 18

33 38 40 30 As illustrated by Tables I and II, burning of crude oil in a gas turbine can produce an exhaust gas that must be treated before it can be released.

Referring specifically to the drawing, a gas turbine is shown and identified generally by the numeral 8. The gas turbine includes a compression section 14, a burner section 10 and an expansion section 16. The burner section 10 of the turbine 8 is adapted for burning crude oil or residual oil rather than gas as a fuel. Such conversions are well known in the art and generally require conversion to oil burners and an oil injection system. Fuel oil is supplied to the burner section of the turbine 8 via fuel line 12. Compressed air is supplied to the burner section 10 by the compression section 14. The hot exhaust gas produced by the burner section 10 may, for example, be used by the expander section 16 of the turbine to drive a generator 18. The hot flue gas is flowed from the burner section 10 via conduit 11 to the expansion section 16.

It is desirable to limit the formation of S0₃ and unburned carbon in the hot flue gas exiting the burner section. To limit the formation of these materials in the hot flue gas a small amount of between about 250 to 1,000 parts per million Mg of a slurry of magnesium oxide (MgO) in oil should be injected into the crude oil fuel line 12 and mixed with the fuel oil ahead of the burner section 10 of the gas turbine as indicated by the phantom arrow identified as 17 in the drawing. Vanadium contained in the crude oil fuel reacts with the MgO and loses its catalytic effect.

In accordance with the invention the hot flue gases exhausted from expansion chamber 16 of the gas turbine are directed to a heat recovery steam generator 20 via line 13 and used as a heat exchange fluid as described later in more detail to provide steam for use in the gas turbine. A booster fan is connected to the outlet of the heat recovery steam generator 20 by conduit 15 for receiving the flue gas therefrom. The booster fan 22 increases the pressure of the flue gas to a value suitable for injection into a sea water scrubber generally indicated by the number 26.

It may be desirable to clean the flue gas with a venturi scrubber shown in phantom as 23 in the drawing. Thus, when it is desirable to avoid discharging to the sea unburned hydrocarbons, unburned carbon and any residual heavy metals in the flue gas a venturi prescrubber should be utilized before the flue gas enters the sea water scrubber 26. When the crude oil or residual oil is very rich in heavy metals (Ni, Cr, etc.) a venturi scrubber ahead of the sea water scrubber will remove and concentrate the metal oxides and separate them from the flue gas. Therefore these heavy metals will not be discharged into the seawater scrubber. In operations where it is desired or required to reduce N0_X emissions to less than 40 ppm, a selective catalytic reduction (SCR) system is advantageously used. The SCR system would be installed downstream of the heat recovery steam generator as indicated in phantom in the drawing. A preferred sea water scrubber for use in cleaning flue gas and a method of operating it are shown and described in U.S. Patent 4,804,523 which is assigned to the assignee of the present invention and briefly described in the prior art portion of this specification. The disclosure of U.S. Patent 4,804,522 is hereby incorporated herein by reference. The sea water scrubber has been modified for use in the present invention as herein described. Efficient removal of sulfur dioxide from a flue gas stream is achieved in a scrubber using a recirculating aqueous stream containing magnesium hydroxide and magnesium sulfite which together act as S0₂ absorbents. Magnesium sulfite is derived from magnesium hydroxide, which is the product of a reaction between soluble magnesium from the sea water and calcium hydroxide added to the scrubbing system. Magnesium sulfite and bisulfite are oxidized to magnesium sulfate by the introduction of air. Magnesium sulfate is converted back to magnesium hydroxide by reaction with additional calcium hydroxide, with gypsum as a by-product. Gypsum is soluble in large amounts of sea water and may be returned to the ocean without adverse environmental impact.

For the location far away from the seashore, the seawater scrubber as described herein may be replaced by a conventional wet scrubber with magnesium hydroxide and magnesium sulfite as S0₂ absorbent, in a liquid closed loop system. This is made possible by the internal regeneration of Mg(OH)₂ from the magnesium sulfate effluent with the added Ca(0H)₂ in a stoichiometric ratio with the amount of S0₂ removed (see U.S. Patent 4,804,523 issued February 14, 1989 to the assignee of the present invention) . The solid by-product CAS0₄.2H₂0 (gypsum) can be dewatered and sold or disposed of as landfill. The recovery of the water vapors from the flue gas as condensate - when seawater is not available for cooling can be made by using cooling towers wet or dry.

As shown in the drawing, the sea water scrubber 26 receives the dirty flue gas from blower fan 22 via conduit 34 which enters the top of the scrubber. The flue gas is flowed down the scrubber via central duct 35 and is discharged near the bottom of the scrubbing tower 32. The flue gas then flows upwardly through contact trays 43 generally in a counter current direction relative to the flow of absorbent downward through the tower 32. For example, the absorbent may take the form of fresh sea water and other chemicals as described heretofore and is introduced into the tower via line 39 and spray nozzles 40. The flue gas continues upwardly through the tower 32 and is eventually discharged through the clean flue conduit 33.

A sump 30 of absorbent fluid is maintained at the bottom of the tower 32. A recirculation pump 36 is connected to the sump through a section line 37. The absorbent passing through the pump is primarily recirculated through line 38 to spray nozzles 40, 42. A side stream 46 from pump 36 is mixed with fresh sea water passing through the flue gas condenser 50 and then directed to a suitable location for discharge. The clean flue gas leaving the sea water scrubber via line 33 contains a substantial portion of water vapor. The flue gas is directed to flue gas condenser 50 and is passed in heat exchange relationship with fresh cold sea water entering the flue gas condenser via line 39. Condensate is removed from the condenser 50 via conduit 52 for further use in accordance with the invention. The flue gas exits the condenser 50 via line 54 and may be reheated in heater 56 and flared in exhaust stack 58.

An alternative to the flue gas condenser 50 for recovering distilled water is the direct cooling of the saturated flue gas stream with cooled distilled water, whereby at least a portion of the evaporated water in the flue gas stream condenses and combines with the pure distilled water to produce warm pure water. A water/water cooler will be provided for this alternative.

The condensate leaving the flue gas condenser via conduit 52 may be used as distilled water in the power cycle or to produce distillate products. Appropriate pumps 60 and 62 and conduits 64 and 66 are provided to move the condensate to facilitate such uses.

Condensate is returned to the power cycle by condensate pump 60 via conduit 64. The condensate is treated in polishing unit 68 to remove or convert scale forming ions to non scale forming ions. The polishing unit, with its mixed bed of anions resins and cations resins, will convert scale forming ions to non-scale forming ions. Condensate exits polishing unit 68 via conduit 70 and may be divided into three streams via conduits 72, 74, 76. Condensate is made availa_ble for washing or emulsifying the crude oil/residual oil liquid fuel via conduit 72. Conventional washing or emulsifying equipment may be used to wash or emulsify the fuel oil.

Condensate may also be directly injected into the combustion section 10 of the combustion turbine via conduit

74. Injection of condensate (i.e., distilled water) into the combustion section of a gas turbine reduces NO_χ emissions in the hot flue gases exiting the turbine. This is particularly important when liquid fuel is used in a gas turbine. Injection of condensate directly or as steam as later described into the combustion section of a gas turbine in a CPE cycle can reduce N0_χ emissions from 220 ppm to about 40 ppm.

In accordance with the invention condensate is flowed via conduit 76 to the heat recovery steam generator 20 for conversion into steam. A portion of such steam is made available via conduit 80 for injection into the burner section 10 and/or the expansion section 16 of the gas turbine to improve the efficiency thereof. A second portion of the steam generated in the heat recovery steam generator 20 is flowed via conduit 82 to a steam turbine 84 which may be used to drive generator 86. The effluent from steam turbine 84 is passed through a steam turbine condenser 90 via conduit 88. The effluent is condensed and returned to condensate return conduit 64 via conduit 92 for recycling. A condensate booster pump 94 may be added to the condensate return line 64 if needed.

Thus, the present invention broadly provides a method for producing power in an environmentally satisfactory manner using crude or residual oil in a gas turbine. The hot flue gases containing sulfur dioxide and water vapor are exhausted from the gas turbine and flowed to a sea water scrubber. Sea water is used in the sea water scrubber to remove sulfur dioxide from the hot flue gases to produce a clean flue gas including water vapor contained therein. The water vapor is condensed and the condensate is made available for injection into the gas turbine and for use with the liquid fuel. A particular advantage of the present invention is that crude fuel oil or residual oil, which are about 50% of the cost of refined oil, can be burned more efficiently by the cycle of the present invention than by any other process. Further the C0₂ emissions per kw/hr produced is the lowest in comparison with coal fired units or crude or residual oil burned in a boiler. Other advantages and uses of the present invention will be apparent to those skilled in the art.

The principles, preferred embodiments and modes of operation of the present invention have been described in the foregoing specification. However, the invention which is intended to be protected is not to be construed as limited to the particular embodiments disclosed. The embodiments are to be regarded as illustrative rather than restrictive. Variations and changes may be made by others without departing from the spirit of the present invention. Accordingly, all such variations and changes, which fall within the spirit and scope of the present invention as defined in the following claims, are expressly intended to be embraced thereby.

Claims

WHAT IS CLAIMED IS:

1. A method for producing power using liquid fuel oil comprising combusting liquid fuel oil in a gas turbine; exhausting hot flue gases containing sulfur dioxide and water vapor from said gas turbine; flowing said hot flue gases to a sea water scrubber; flowing sea water to said sea water scrubber; removing sulfur dioxide from said hot flue gases utilizing sea water in said sea water scrubber to produce a clean flue gas including water vapor contained therein; flowing the clean flue gas to a flue gas condenser; condensing water vapor from said clean flue gas; making available at least a portion of the condensed water vapor for injection into said gas turbine and making available another portion of said condensed water vapor for use with the liquid fuel prior to combustion thereof.

2. The method of claim 1 further characterized in that the clean flue gas is flowed to a water/water condenser for condensing water vapor from said flue gas.

3. The method of claim 1 further characterized in that at least a portion of the condensed water vapor made available for injection into said gas turbine is reconverted to steam by heat exchange with the hot flue gas exhausted from said gas turbine.

4. The method of claim 3 further characterized in that at least a portion of the reconverted steam is injected into the burner section of said gas turbine to improve the efficiency thereof and to reduce the NO_χ content of the flue gas exhausted therefrom.

5. The method of claim 3 further characterized in that at least a portion of the reconverted steam is flowed to a steam turbine for driving said steam turbine. 6. The method of claim 5 further characterized in t_hat said steam turbine is utilized to drive a generator.

7. The method of claim 5 where the exhaust gas from said steam turbine is flowed to a steam turbine condenser to preheat sea water flowing to said sea water scrubber.

8. The method of claim 7 further characterized in that the condensate from said steam turbine condenser is added to the condensed water vapor from said clean flue gas prior to said condensed water vapor being made available for injection into said gas turbine and prior to said condensed water vapor being made available for use with said liquid fuel.

9. The method of claim 8 further characterized in that magnesium oxide is mixed with liquid fuel oil prior to combusting said liquid fuel oil in said gas turbine.

10. The method of claim 1 further characterized in that the hot flue gases exhausted from said gas turbine are passed in heat exchange relationship with at least part of the portion of the condensed water vapor made available for injection into said gas turbine to reconvert said part to steam.

11. The method of claim 10 further characterized in that the hot flue gas after passing in said heat exchange relationship is flowed through a venturi scrubber to remove unburned carbon and any residual heavy metals in said hot flue gas.

12. A combined cycle for producing power using liquid fuel oil in a gas turbine and for providing an environmentally acceptable flue gas from said gas turbine for disposal comprising combusting liquid fuel oil in a gas turbine; exhausting hot flue gases containing sulfur dioxide and water vapor from said gas turbine; flowing said hot flue gas to a sea water scrubber; removing sulfur dioxide from the hot flue gas in said sea water scrubber to produce a clean flue gas including water vapor contained therein; condensing water vapor from said clean flue gas and making said condensed water vapor available for use at said steam turbine.

13. A combined power environmental cycle system for producing power using a crude oil/residual oil liquid fuel oil comprising: a combustion turbine having a burner section adapted to be fired with liquid fuel oil, said turbine including a turbine exhaust for exhausting hot flue gases containing sulfur dioxide and water vapor; a source of liquid fuel oil operably connected to the burner section of said combustion turbine; a sea water scrubber for removing sulfur dioxide from hot flue gases, said sea water scrubber having a flue gas inlet, a sea water intake port, a clean flue gas exit port and a liquid effluent exhaust port; conduit means connecting said turbine exhaust to the flue gas inlet of said sea water scrubber; a source of sea water; conduit means operably connecting said source of sea water with the sea water intake port of the sea water scrubber; a flue gas condenser having a sea water heat exchange tube, said flue gas condenser having a flue gas exhaust outlet and a condensate outlet; conduit means operably connecting said sea water source with the sea water heat exchange tube; conduit means operably connecting the clean flue gas exit port of said sea water scrubber and the clean flue gas inlet of said flue gas condenser; conduit means operably connected between the condensate outlet of said flue gas condenser and the burner section of the combustion gas turbine for making available condensate for injection into the burner section of said combustion gas turbine and; conduit means operatively connected between the condensate outlet of said flue gas condenser and the source of liquid fuel for making available condensate to said liquid fuel oil.

14. The system of claim 13 further characterized by a heat recovery steam generator and means connecting said heat recovery steam generator into said conduit means operably connecting said turbine exhaust to the flue gas inlet of said sea water scrubber.

15. The system of claim 14 further characterized by means operably connecting said heat recovery steam generator to the conduit means operably connected between the condensate outlet of said flue gas condenser and the burner section of the combustion turbine whereby the hot flue gas exhausted from said gas turbine are passed in heat exchange relationship with condensate in said conduit means.

16. The system of claim 13 further characterized by a source of magnesium oxide slurry and conduit means connecting said source of magnesium oxide to said source of liquid fuel.

17. The system of claim 13 further characterized by a venturi prescrubber operably connected between said gas turbine exhaust and the flue gas inlet of the sea water scrubber.

18. The system of claim 17 further characterized by a selective catalytic reduction means operably connected between said gas turbine exhaust and the flue gas inlet of the sea water scrubber.

19. The system of claim 17 further characterized by a steam turbine and conduit means operably connecting said steam turbine with said heat recovery steam generator for recovering steam from said heat recovery steam generator for use in driving said steam turbine. 20. A method for producing power using liquid fuel oil comprising combusting liquid fuel oil in a gas turbine; exhausting hot flue gases containing sulfur dioxide and water vapor from said gas turbine; flowing said hot flue gases to a scrubber; removing sulfur dioxide from said hot flue gases in said scrubber to produce a clean flue gas including water vapor contained therein; condensing water vapor from said clean flue gas; making available at least a portion of the condensed water vapor for injection into said gas turbine or for use with the liquid fuel prior to combustion thereof.

21. The method of claim 20 further characterized in that the clean flue gas is flowed to a water/water condenser for condensing water vapor from said flue gas.

22. The method of claim 20 further characterized in that the clean flue gas is flowed to a flue gas condenser for condensing water vapor from said flue gas.

23. The method of claim 20 further characterized in that at least a portion of the condensed water vapor made available for injection into said gas turbine is reconverted to steam by heat exchange with the hot flue gas exhausted from said gas turbine.

24. The method of claim 23 further characterized in that at least a portion of the reconverted steam is injected into the burner section of said gas turbine to improve the efficiency thereof and to reduce the NO_χ content of the flue gas exhausted therefrom.

25. The method of claim 24 further characterized in that at least a portion of the reconverted steam is flowed to a steam turbine for driving said steam turbine.

26. The method of claim 25 further characterized in that said steam turbine is utilized to drive a generator. 27. The method of claim 25 where the exhaust gas from said steam turbine is flowed to a steam turbine condenser to preheat sea water flowing to said scrubber.

28. The method of claim 27 further characterized in that the condensate from said steam turbine condenser is added to the condensed water vapor from said clean flue gas prior to said condensed water vapor being made available for injection into said gas turbine and prior to said condensed water vapor being made available for use with said liquid fuel.

29. The method of claim 28 further characterized in that magnesium oxide is mixed with liquid fuel oil prior to combusting said liquid fuel oil in said gas turbine.

30. The method of claim 20 further characterized in that the hot flue gases exhausted from said gas turbine are passed in heat exchange relationship with at least part of the portion of the condensed water vapor made available for injection into said gas turbine to reconvert said part to steam.

31. The method of claim 30 further characterized in that the hot flue gas after passing in said heat exchange relationship is flowed through a venturi scrubber to remove unburned carbon and any residual heavy metals in said hot flue gas.

32. A method for producing power using liquid fuel oil comprising combusting liquid fuel oil in a gas turbine; exhausting hot flue gases containing sulfur dioxide and water vapor from said gas turbine; flowing said hot flue gases to a scrubber; removing sulfur dioxide from said hot flue gases in said scrubber to produce a clean flue gas including water vapor contained therein; condensing water vapor from said clean flue gas; and making available at least a portion of the condensed water vapor for subsequent use. 33. The method of claim 32 further characterized in that the clean flue gas is flowed to a water/water condenser for condensing water vapor from said flue gas.

34. The method of claim 32 further characterized in that the clean flue gas is flowed to a flue gas condenser for condensing water vapor from said flue gas.

35. The method of claim 32 further characterized in that at least a portion of the condensed water vapor is made available for injection into said gas turbine is reconverted to steam by heat exchange with the hot flue gas exhausted from said gas turbine.

36. The method of claim 35 further characterized in that at least a portion of the reconverted steam is injected into the burner section of said gas turbine to improve the efficiency thereof and to reduce the N0_χ content of the flue gas exhausted therefrom.

37. The method of claim 36 further characterized in that at least a portion of the reconverted steam is flowed to a steam turbine for driving said steam turbine.

38. The method of claim 37 further characterized in that said steam turbine is utilized to drive a generator.

39. The method of claim 37 where the exhaust gas from said steam turbine is flowed to a steam turbine condenser to preheat sea water flowing to said scrubber.

40. The method of claim 39 further characterized in that the condensate from said steam turbine condenser is added to the condensed water vapor from said clean flue gas prior to said condensed water vapor being made available for injection into said gas turbine and prior to said condensed water vapor being made available for use with said liquid fuel. ₄₁. The method of claim 40 further characterized in that magnesium oxide is mixed with liquid fuel oil prior to combusting said liquid fuel oil in said gas turbine.

42. The method of claim 32 further characterized in that the hot flue gases exhausted from said gas turbine are passed in heat exchange relationship with at least part of the portion of the condensed water vapor made available for injection into said gas turbine to reconvert said part to steam.

43. The method of claim 42 further characterized in that the hot flue gas after passing in said heat exchange relationship is flowed through a venturi scrubber to remove unburned carbon and any residual heavy metals in said hot flue

/ gas.

44. A method for producing distilled water using liquid fuel oil in a power cycle comprising combusting liquid fuel oil in a gas turbine; exhausting hot flue gases containing sulfur dioxide and water vapor from said gas turbine; flowing said hot flue gases to a scrubber; removing sulfur dioxide from said hot flue gases in said scrubber to produce a clean flue gas and including water vapor contained therein; condensing water vapor from said clean flue gas to produce distilled water; and making available at least a portion of the distilled water for subsequent use.

45. The method of claim 44 further characterized in that the clean flue gas is flowed to a water/water condenser for condensing water vapor from said flue gas.

46. The method of claim 44 further characterized in that the clean flue gas is flowed to a flue gas condenser for condensing water vapor from said flue gas.