TW201441479A - System and method for load control with diffusion combustion in a stoichiometric exhaust gas recirculation gas turbine system - Google Patents

Abstract

A system is provided with a turbine combustor having a first diffusion fuel nozzle, wherein the first diffusion fuel nozzle is configured to produce a diffusion flame. The system includes a turbine driven by combustion products from the diffusion flame in the turbine combustor. The system also includes an exhaust gas compressor, wherein the exhaust gas compressor is configured to compress and route an exhaust gas from the turbine to the turbine combustor along an exhaust recirculation path. In addition, the system includes a control system configured to control flow rates of at least one oxidant and at least one fuel to the turbine combustor in a stoichiometric control mode and a non-stoichiometric control mode, wherein the stoichiometric control mode is configured to change the flow rates and provide a substantially stoichiometric ratio of the at least one fuel with the at least one oxidant, and the non-stoichiometric control mode is configured to change the flow rates and provide a non-stoichiometric ratio of the at least one fuel with the at least one oxidant.

Description

System and method for load control by diffusion combustion in a stoichiometric exhaust gas recirculation gas turbine system

The subject matter disclosed herein relates to gas turbine engines.

Gas turbine engines are used in a wide variety of applications, such as power generation, aircraft, and various machinery. Gas turbine engines typically combust fuel and oxidant (eg, air) in a combustor section to produce hot combustion products that then drive one or more turbine stages of the turbine zone. In turn, the turbine section drives one or more compressor stages of the compressor section to compress the oxidant to draw into the combustor section with the fuel. Likewise, the fuel and oxidant are mixed in the combustor section and then combusted to produce a hot combustion product. Gas turbine engines typically premix fuel and oxidant along one or more flow paths upstream of the combustor section, and thus the gas turbine engine typically operates with a premixed flame. Unfortunately, premixed flames can be difficult to control or maintain, which can affect various exhaust emissions and power requirements. Furthermore, gas turbine engines are usually expensive The amount of air acts as an oxidant and discharges a large amount of exhaust gas into the atmosphere. In other words, the exhaust gas is typically wasted as a by-product of gas turbine operation.

Brief description of the invention

Some specific examples that are comparable in scope to the originally claimed invention are summarized below. These specific examples are not intended to limit the scope of the claimed invention, but are intended to provide a brief summary of possible forms of the invention. In fact, the invention may encompass a variety of forms that may be similar or different from the specific examples described below.

In a first embodiment, a system is provided having a turbine combustor having a first diffusion fuel nozzle, wherein the first diffusion fuel nozzle is configured to generate a diffusion flame. The system includes a turbine driven by combustion products from a diffused flame in a turbine combustor. The system also includes an exhaust gas compressor, wherein the exhaust gas compressor is configured to compress exhaust gas from the turbine and send it along the exhaust gas recirculation path to the turbine combustor. Additionally, the system includes a control system configured to control a flow rate of the at least one oxidant and the at least one fuel to the turbine combustor in a stoichiometric control mode and a non-stoichiometric control mode, wherein the stoichiometric control mode is Configuring to vary the flow rates and providing a substantial stoichiometric ratio of the at least one fuel to the at least one oxidant, and the non-stoichiometric control mode is configured to vary the flow rates and provide the at least one fuel and the at least A non-stoichiometric ratio of an oxidant.

In a second embodiment, a method is provided that includes At least one oxidant and at least one fuel are injected into the chamber of the turbine combustor, wherein the at least one oxidant and the at least one fuel are mixed and combusted to form a diffusion flame to produce a combustion product. The method further includes driving the turbine and outputting the exhaust with the combustion products. The method further includes recycling the exhaust gas to the exhaust gas compressor along an exhaust gas recirculation path. The method further includes compressing and transmitting the exhaust gas to the turbine combustor. The method further includes controlling a flow rate of the at least one oxidant and the at least one fuel to the turbine combustor in a stoichiometric control mode, wherein the stoichiometric control mode is configured to vary the flow rate and provide at least one fuel A substantially stoichiometric ratio to at least one oxidant. The method further includes controlling a flow rate of the at least one oxidant and the at least one fuel to the turbine combustor in a non-stoichiometric control mode, wherein the non-stoichiometric control mode is configured to vary the flow rates and provide at least one A non-stoichiometric ratio of fuel to at least one oxidant.

In a third embodiment, a method is provided that includes The oxidant is directed to at least one oxidant compressor to produce a stream of compressed oxidant. The method further includes directing a recycle low oxygen content gas stream to a compressor section of the gas turbine engine to produce a compressed low oxygen content gas stream. The method further includes directing a first portion of the first compressed oxidant flow rate of the compressed oxidant stream and the first fuel stream rate fuel stream to the at least one turbine combustor at a substantially stoichiometric ratio and mixing the compressed oxidant stream at the point of combustion And the fuel stream, and combusting the mixture of the compressed oxidant stream and the fuel stream. The method further includes directing a first portion of the compressed low oxygen content gas stream of the low oxygen content gas flow rate to the at least one turbine combustor and after the combustion point It mixes with the compressed oxidant and the combustion stream of the fuel and produces a high temperature, high pressure, low oxygen content stream. The method further includes directing the high temperature, high pressure, low oxygen content stream to an expander section of the gas turbine engine and expanding the high temperature, high pressure, low oxygen content stream to produce a first mechanical power and having a first recirculated low oxygen content gas stream The recycle of the low oxygen content gas stream, wherein the recycle low oxygen content gas stream contains a first recycle low oxygen content gas effluent level. The method further includes using the first portion of the first mechanical power to drive the compressor section of the gas turbine engine. The method further includes using a second portion of the first mechanical power to drive at least one of: a generator, the at least one oxidant compressor, or at least one other mechanical device. The method further includes recycling the recirculated low oxygen content gas stream from the outlet of the expander section to the inlet of the compressor section of the gas turbine engine in a recirculation loop. The method further includes extracting at least a second portion of the compressed low oxygen content gas stream from the gas turbine engine, and delivering the at least a second portion of the compressed low oxygen content gas stream to the first at least one oxidation catalyst unit, and A low oxygen content product stream comprising a first low oxygen content product effluent level within a target range is produced. The method further includes reducing a fuel flow rate to a second fuel flow rate that is less than the first fuel flow rate, and reducing the first portion of the compressed oxidant flow rate to less than the first compressed oxidant flow rate a second compressed oxidant flow rate, wherein the substantially stoichiometric ratio is maintained, a second mechanical power less than the first mechanical power is generated, and a low oxygen content product stream comprising a second low oxygen content product effluent level within a target range is produced . The method further includes reducing a fuel flow rate to a third fuel flow rate that is less than the second fuel flow rate, and reducing the first portion of the compressed oxidant flow rate And a third compressed oxidant flow rate that is less than the second compressed oxidant flow rate, wherein the substantially stoichiometric ratio is maintained, a third mechanical power less than the second mechanical power is generated, and a third low oxygen content product effluent is produced A low oxygen content product stream that is horizontally within the target range. The method further includes reducing a fuel flow rate to a fourth fuel flow rate that is less than the third fuel flow rate, and reducing the first portion of the compressed oxidant flow rate to be less than the third compressed oxidant flow rate a fourth compressed oxidant flow rate, wherein the substantial stoichiometric ratio is not maintained, and lean fuel combustion is achieved, producing a fourth mechanical power that is less than the third mechanical power, and producing a high oxygen content that includes a high oxygen content product effluent level Product stream.

10‧‧‧System

12‧‧‧ hydrocarbon generation system

14‧‧‧ Turbine-based service system

16‧‧‧Oil/Gas Extraction System

18‧‧‧Enhanced Oil Recovery (EOR) System

20‧‧‧ Underground storage

22‧‧‧ground equipment

24‧‧‧Production tree

26‧‧‧ Oil/Gas Well

28‧‧‧ Pipe fittings

30‧‧‧ hole

32‧‧‧ soil

34‧‧‧Fluid injection system

36‧‧‧ Pipe fittings

38‧‧‧ hole

40‧‧‧ fluid

42‧‧‧Exhaust

44‧‧‧ arrow

46‧‧‧Offset distance

48‧‧‧oil/gas

50‧‧‧ arrow

52‧‧‧ gas turbine system

54‧‧‧Exhaust gas (EG) treatment system

56‧‧‧Heat Recovery Steam Generator (HRSG)

58‧‧‧Exhaust Gas Recirculation (EGR) System

60‧‧‧Exhaust

62‧‧‧Steam

64‧‧‧Processed water

66‧‧‧Exhaust

68‧‧‧Oxidant

70‧‧‧fuel

72‧‧‧Mechanical power

74‧‧‧Power

76‧‧‧ extraction points

78‧‧‧Exhaust gas (EG) supply system

80‧‧‧Exhaust gas (EG) extraction system

82‧‧‧Exhaust gas (EG) treatment system

84‧‧‧Other systems

86‧‧‧ pipeline

88‧‧‧ storage tank

90‧‧‧Carbon storage system

92‧‧‧ Carbon dioxide

94‧‧‧Nitrate

95‧‧‧ flow

96‧‧‧First stream (CO ₂ lean N ₂ flow)

97‧‧‧Second flow (intermediate concentration of CO ₂ and N ₂ streams)

98‧‧‧ third stream (CO ₂ rich N ₂ stream)

100‧‧‧Control system

102‧‧‧Combined circulatory system

104‧‧‧Steam turbine

106‧‧‧ Machine

108‧‧‧ water

110‧‧‧Exhaust gas recirculation path

112‧‧‧Exhaust gas injection into the EOR system

114‧‧‧Steam injection into the EOR system

116‧‧‧Other oil/gas systems

118‧‧‧ Controller

120‧‧‧ processor

122‧‧‧ memory

124‧‧‧Steam turbine control

126‧‧‧SEGR: Gas Turbine System Control

128‧‧‧ Machine Control

130‧‧‧Sensor feedback

132‧‧‧ close interface

134‧‧‧Remote interface

150‧‧‧ gas turbine engine

152‧‧‧Compressor section

154‧‧‧burner section

156‧‧‧ Turbine section

158‧‧‧Compressor level

160‧‧‧ burner

162‧‧‧Rotary axis

164‧‧‧fuel nozzle

166‧‧‧ head section

168‧‧‧ burning part

170‧‧‧Compressed exhaust gas

172‧‧‧ combustion gases

174‧‧‧ Turbine grade

176‧‧‧Axis

178‧‧‧ Machine

180‧‧‧ Machine

182‧‧‧Exhaust gas outlet

184‧‧‧Exhaust gas inlet

186‧‧‧Oxidant Compression System

188‧‧‧Oxidant compressor

190‧‧‧ drive

192‧‧‧Exhaust gas (EG) treatment components

194‧‧‧EG processing components

196‧‧‧EG processing components

198‧‧‧EG processing components

200‧‧‧EG processing components

202‧‧‧EG processing components

204‧‧‧EG processing components

206‧‧‧EG processing components

208‧‧‧EG processing components

210‧‧‧EG processing components

212‧‧‧ pipeline

214‧‧‧ heat exchanger

216‧‧‧ pipeline

220‧‧‧How to operate

222‧‧‧ squares

224‧‧‧ squares

226‧‧‧ square

228‧‧‧ squares

230‧‧‧ squares

232‧‧‧ square

234‧‧‧ squares

236‧‧‧ squares

238‧‧‧ squares

240‧‧‧ squares

242‧‧‧ squares

244‧‧‧ square

246‧‧‧ squares

300‧‧‧ gas treatment subsystem

302‧‧‧ valve

304‧‧‧ Sensor

306‧‧‧ Provide control signals

308‧‧‧catalyst and heat recovery (CHR) systems

310‧‧‧Dehumidification System (MRS)

312‧‧‧Degranulation System (PRS)

314‧‧‧Booster blower

316‧‧‧catalyst unit

318‧‧‧ heat exchanger

320‧‧‧catalyst unit

322‧‧‧catalyst unit

324‧‧‧catalyst unit

326‧‧‧catalyst unit

328‧‧‧catalyst unit

330‧‧‧ heat exchanger

332‧‧‧ heat exchanger

334‧‧‧Oxidant Catalytic Unit (UCU)

336‧‧‧Oxidant fuel

338‧‧‧Heat Recovery Unit (HRU)

340‧‧‧Heat Recovery Steam Generator (HRSG)

342‧‧‧Steam

344‧‧‧Steam Turbine (ST)

346‧‧‧load

348‧‧‧Mechanical power

350‧‧‧Power

352‧‧‧Dehumidification unit (MRU)

354‧‧‧Dehumidification unit (MRU)

356‧‧‧Dehumidification unit (MRU)

358‧‧‧ heat exchanger

360‧‧‧Condenser

362‧‧‧ water

364‧‧‧Dehumidification separator or filter

372‧‧‧ water

374‧‧‧Degranulation unit (PRU)

376‧‧‧Degranulation unit (PRU)

378‧‧‧Degranulation unit (PRU)

380‧‧‧Inertial separator

382‧‧‧ Gravity Separator

384‧‧‧ particles

386‧‧‧Drop filter

388‧‧‧First grading filter

390‧‧‧Second grading filter

392‧‧‧ particles

394‧‧‧Drain valve

396‧‧‧Drainage system

420‧‧‧ system

422‧‧‧Target system

424‧‧‧Processing subsystem

426‧‧‧Compression system

428‧‧‧Dehumidification/dehydration system

430‧‧‧Degranulation/filter system

432‧‧‧Gas Separation System

434‧‧‧Gas purification system

436‧‧‧CO ₂ rich flow

438‧‧‧ intermediate concentration flow

440‧‧‧CO ₂ lean flow

442‧‧ ‧ gas treatment system

444‧‧‧Energy recovery system

446‧‧ ‧ gas treatment system

448‧‧ gas treatment system

450‧‧ ‧ gas treatment system

452‧‧‧Energy recovery system

454‧‧‧Energy recovery system

456‧‧‧Energy recovery system

458‧‧‧Compression system

460‧‧‧Dehumidification/dehydration system

462‧‧‧ Turbine/expander

464‧‧‧load

466‧‧‧Mechanical power

468‧‧‧Power

490‧‧‧Shield

492‧‧‧Compressor discharge chamber

Room 494‧‧

496‧‧‧First wall or liner

498‧‧‧Second wall or flow casing

500‧‧‧Flow channel

502‧‧‧ holes or perforations

504‧‧‧Exhaust flow

506‧‧ ‧ holes or perforations

508‧‧‧Exhaust gas injection

510‧‧‧Diluent injector

512‧‧‧Diluent injection

514‧‧‧ Thinner

516‧‧‧flame

518‧‧‧Fluid Supply System (FSS)

520‧‧‧Combustion products or waste gas

522‧‧‧ valve

524‧‧‧ Extraction pipeline

526‧‧‧ valve

528‧‧‧Drainage line

530‧‧‧Drainage system

550‧‧‧Premixed fuel nozzle

552‧‧‧Premixed flame

554‧‧‧Diffusion fuel nozzle

556‧‧‧Diffuse flame

558‧‧‧ mixed part

560‧‧‧Injection

562‧‧‧Mixed room

564‧‧‧Shell

566‧‧‧Injection channel

568‧‧‧ catheter

570‧‧‧Injected into the exit

580‧‧‧First mixing room

582‧‧‧Second mixing room

584‧‧‧ first outer casing part

586‧‧‧Second outer casing

590‧‧‧ parallel mixing section

592‧‧‧Vortex

594‧‧‧Inner conduit or hub (hub)

596‧‧‧External catheter

598‧‧ vortex blades

600‧‧‧ circumferential direction

602‧‧‧ vertical axis

604‧‧‧ internal passage

606‧‧‧Outer channel

608‧‧‧radial channel

610‧‧‧Injection

612‧‧‧ arrow

614‧‧‧Mixture

616‧‧‧ arrow

618‧‧‧Mixture

620‧‧‧ arrow

622‧‧‧ arrow

624‧‧‧ arrow

640‧‧‧Independent channel

642‧‧‧fuel passage

644‧‧‧Oxidant channel

646‧‧‧Inner catheter

648‧‧‧External catheter or structure

650‧‧‧fuel exports

652‧‧‧Oxidant export

654‧‧‧Shared plane or downstream

656‧‧‧ outline or border

670‧‧‧Independent channel

672‧‧‧Injection

674‧‧‧ mixed part

676‧‧・Internal mixing room

678‧‧‧External mixing room

680‧‧‧Inner duct or casing

682‧‧‧External catheter or casing

684‧‧‧fuel-diluent channel

686‧‧‧Oxidizer-diluent channel

688‧‧‧Inner catheter

690‧‧‧External catheter

692‧‧‧Export

694‧‧‧Export

696‧‧‧shared or downstream

698‧‧‧fuel-diluent mixture

700‧‧‧Oxidant-diluent mixture

702‧‧‧ outline or border

720‧‧‧independent channel

722‧‧‧Fluid A channel

724‧‧‧ Fluid B channel

726‧‧‧Function C channel

728‧‧‧catheter or structure

730‧‧‧catheter or structure

732‧‧‧catheter or structure

734‧‧‧Fluid A

736‧‧‧ Fluid B

738‧‧‧ Fluid C

740‧‧‧ Hole

742‧‧‧ Hole

744‧‧‧ Hole

746‧‧‧ shared plane or downstream

760‧‧‧D fluid channel

762‧‧‧catheter or structure

764‧‧‧ Fluid D

766‧‧‧Export

770‧‧‧Diluent injection system

772‧‧‧Hot products of combustion

774‧‧‧Fluid E

776‧‧‧Fluid F

778‧‧‧ Fluid G

790‧‧‧Fuel A nozzle

792‧‧‧fuel B nozzle

794‧‧‧Fuel C nozzle

796‧‧‧fuel D nozzle

798‧‧‧Fuel E nozzle

800‧‧‧Fuel F nozzle

802‧‧‧fuel G nozzle

810‧‧‧ Fluid supply circuit

812‧‧‧Diluent supply circuit

814‧‧‧fuel nozzle supply circuit

816‧‧‧First nozzle circuit

818‧‧‧Second nozzle circuit

820‧‧‧ third nozzle circuit

822‧‧‧Stoichiometric Control Mode

824‧‧‧Non-stoichiometric control mode

826‧‧‧ lean fuel control mode

828‧‧‧rich fuel control mode

830‧‧‧ Fluid supply control

832‧‧‧First loop control

834‧‧‧Second loop control

836‧‧‧ Third loop control

840‧‧‧Gas turbine load (EGR flow)

842‧‧‧fuel/oxidant ratio

844‧‧‧Diffuse flame operability curve

846‧‧‧Premixed flame operability curve

These and other features, aspects and advantages of the present invention will become better understood from the <RTIgt; 2 is a diagram of a specific example of a system of a turbine-based service system to a hydrocarbon generation system; FIG. 2 is a diagram of a specific example of the system of FIG. 1 further illustrating a control system and a combined cycle system; FIG. 3 is FIG. And a detailed description of a system of systems of 2, which further illustrate details of a gas turbine engine, an exhaust gas supply system, and an exhaust gas treatment system; FIG. 4 is a flow diagram of a specific example of a method of operating the system of FIGS. 1-3; Figure 5 is a specific example of the exhaust gas treatment system of Figures 1-3 Figure 6 is a diagram of a specific example of the exhaust gas supply system of Figures 1-3; Figure 7 is an illustration of a specific example of the gas turbine engine of Figures 1-3, further illustrating the combustor, fuel nozzle, and Details of a flow of oxidant, fuel, and diluent; FIG. 8 is a diagram of a specific example of the fuel nozzle of FIG. 7 illustrating a premixed fuel nozzle configuration; FIG. 9 is a diagram of a specific example of the fuel nozzle of FIG. It illustrates a premixed fuel nozzle configuration; FIG. 10 is a diagram of a specific example of the fuel nozzle of FIG. 7 illustrating a premixed fuel nozzle configuration; FIG. 11 is a diagram of a specific example of the fuel nozzle of FIG. FIG. 12 is a diagram illustrating a specific example of the fuel nozzle of FIG. 7 illustrating a diffusion fuel nozzle configuration; FIG. 13 is a diagram of a specific example of the fuel nozzle of FIG. 7 illustrating a diffusion fuel nozzle configuration; FIG. Figure 13 is a schematic cross-sectional view of a specific example of the fuel nozzle of Figure 13 taken along line 14-14; Figure 15 is a schematic cross-sectional view of a specific example of the fuel nozzle of Figure 13 taken along line 14-14; Figure 7 burner and fuel nozzle Examples Figure, which illustrates a diffusion fuel nozzle configuration and a diluent injection system; Figure 17 is a schematic cross-sectional view of a specific example of the burner and fuel nozzle of Figure 7, taken along line 17-17, illustrating the multi-nozzle of the fuel nozzle Configuration; and Figure 18 is a plot of gas turbine load and exhaust gas recirculation (EGR) flow versus diffusion/fire ratio for the pre-mixed flame configuration.

Detailed description of the invention

One or more specific embodiments of the invention will be described below. In order to provide a brief description of these specific examples, all features of an actual implementation may not be described in the specification. It should be understood that in the development of any such actual implementation, as in any engineering or design project, many implementations must be made - specific decisions to achieve the developer's specific purpose, such as compliance with system-related and business-related restrictions, which may Change from one implementation to another. Moreover, it should be understood that such development efforts may be complex and time consuming, but are still routine tasks of design, manufacture, and manufacture for those skilled in the art having the benefit of this disclosure.

When introducing elements of various specific embodiments of the invention, the articles "a", "the", and "said" are intended to mean the presence of one or more elements. The terms "comprising", "including" and "having" are intended to be inclusive and mean that there may be other elements than those listed.

As discussed in detail below, the specific examples disclosed are generally related to stoichiometric operation of a gas turbine system having exhaust gas recirculation (EGR), and particularly a gas turbine system using EGR. For example, the gas turbine system can be configured to recirculate exhaust gases along an exhaust gas recirculation path, stoichiometrically combust fuel and oxidant along with at least some of the recirculated exhaust gases, and capture exhaust gases for various target systems. Together with the recirculating exhaust gases may help to increase the stoichiometric combustion of carbon dioxide (CO ₂₎ concentration level in the exhaust gas, which is then post processed to separation and purification of CO ₂ and nitrogen (N ₂₎ was used in the various target systems. Gas turbine systems may also use various exhaust gas treatments (eg, heat recovery, catalyst reactions, etc.) along the exhaust gas recirculation path to increase CO ₂ concentration levels and reduce other emissions (eg, carbon monoxide, nitrogen oxides) And the level of concentration of unburned hydrocarbons, and increased energy recovery (eg, with a heat recovery unit). Further, the gas turbine engine can be configured to combust fuel and oxidant with one or more diffusion flames instead of or in addition to a premixed flame. Diffusion flame operation and can help maintain the stability of combustion within certain limits stoichiometry, which in turn helps to increase the CO ₂ generation. For example, as discussed below, a gas turbine system operating with a diffusion flame may allow for a greater amount of EGR than a gas turbine system operating with a premixed flame. In turn, an increased amount of EGR helps increase CO ₂ production. Possible target systems include pipelines, storage tanks, carbon sequestration systems, and hydrocarbon generation systems, such as enhanced oil recovery (EOR) systems.

As a general case, it is worth noting that the premix is The difference between a flame (ie, premixed combustion) and a diffusion flame (ie, diffusion combustion). Combustion (ie, premixed or diffused combustion) is essentially in fuels and oxidants (such as air, oxygen, oxygen-enriched air, oxygen-reduced air, or oxygen and nitrogen) An exothermic chemical reaction (eg, a combustion reaction) between the mixtures). The exothermic chemical reaction between the fuel and the oxidant can substantially affect (and control) the stability of the flame (eg, the stability of the flame surface), and vice versa. For example, the heat released from the exothermic chemical reaction helps to maintain the flame, and thus higher flame temperatures generally result in greater flame stability. In other words, higher temperatures associated with exothermic chemical reactions can help increase flame stability, while lower temperatures associated with exothermic chemical reactions can reduce flame stability. The flame temperature can primarily depend on the fuel/oxidant ratio. In particular, the flame temperature can be highest at the stoichiometric fuel/oxidant ratio, as discussed in detail below, which typically includes an exothermic chemical reaction that consumes substantially all of the fuel and oxidant, resulting in substantially no residual oxidant or unburned fuel. .

With regard to premixed combustion, the fuel and oxidant are mixed at one or more locations upstream of the premixed flame, which is essentially the combustion of the premix of fuel and oxidant. Typically, the exothermic chemical reaction of the fuel and oxidant in the premixed flame is limited by the fuel/oxidant ratio of the premix upstream of the premixed flame. In many configurations (particularly when one or more diluents are premixed with the fuel and oxidant), it may be more difficult to maintain the premixed flame at a substantially stoichiometric fuel/oxidant ratio, and thus may be more difficult to stabilize the flame. maximize. In some configurations, the available fuel lean premixed flame fuels / oxidant ratio of which reduce the flame temperature and thus help reduce the nitrogen oxides (NO _X) (e.g., nitric oxide (NO) and nitrogen dioxide (NO ₂ )) emissions. Reduce NO _X emissions system and the regulations relating to emissions, reduced flame temperature also leads to reduced flame stability. In the specific examples disclosed in these, the system may be controlled to provide a substantially stoichiometric fuel / oxidant ratio (e.g., increase the flame temperature and flame stability), and in order to control the emission (e.g., to reduce NO _X emissions), using One or more diluents to reduce the temperature. In particular, as discussed below, a diluent can be provided separately from the fuel and oxidant (eg, after the point of combustion and/or downstream of the premixed flame) to enable more precise control of the fuel/oxidant ratio for stoichiometry combustion, but also to control the temperature and diluent emissions (e.g., NO _X emissions). In other words, the fuel and oxidant streams can be controlled independently of each other with the diluent stream to provide a more precisely controlled fuel/oxidant ratio in the premix to the location of the premixed flame.

With regard to diffusion combustion, the fuel and oxidant are typically not mixed upstream of the diffusion flame, but rather where the fuel and oxidant mix and react directly on the surface of the flame and/or the surface of the flame is present between the fuel and the oxidant. In particular, the fuel and oxidant are separately adjacent to the flame surface (or diffusion boundary/interface) and then diffused (eg, via molecular and viscous diffusion) along the flame surface (or diffusion boundary/interface) to create a diffusion flame. It is worth noting that the fuel and oxidant may be substantially stoichiometric along the surface of the flame (or diffusion boundary/interface), which may produce a higher flame temperature (eg, the highest flame temperature) along the surface of the flame. Likewise, stoichiometric fuel/oxidant ratios typically produce higher flame temperatures (eg, highest flame temperatures) than lean fuel or fuel rich fuel to oxidant ratios. As a result, the diffusion flame can be substantially more stable than the premixed flame because the diffusion of fuel and oxidant helps maintain a stoichiometric ratio (and higher temperature) along the surface of the flame. Although higher flame temperatures also lead to greater emissions, such as NO _X emissions, but the specific examples disclosed the use of one or more of such diluents to help control the temperature and emissions while still avoiding any pre of fuel and oxidant Mixed. For example, such disclosed embodiments may incorporate one or more diluents separate from the fuel and oxidant (eg, after the point of combustion and/or downstream of the diffusion flame) to help reduce temperature and reduce the generation of diffusion flames. emissions (e.g., NO _X emissions).

In the disclosed embodiments, the exhaust gas provided by exhaust gas recirculation (EGR) acts as at least one of the diluents. The exhaust gas (as one of the diluents) is substantially separated from the streams of oxidant and fuel so that the fuel, oxidant, and diluent (eg, exhaust gas) streams can be independently controlled. In certain instances, the exhaust gas may be, and / or after combustion flame point (e.g., premixed flame and / or a diffusion flame) is injected downstream of the turbine combustor, helping to reduce the temperature and reducing emissions, e.g., NO _X emissions. However, other diluents (eg, steam, nitrogen, or other inert gases) may also be used for temperature and/or emissions control, either alone or in combination with exhaust gases. If a difference is produced between the premixed flame and the diffusion flame, the amount of EGR may vary significantly between the gas turbine system operating with the premixed fuel nozzle relative to the diffusion fuel nozzle. The premixed flame may be limited to a premix upstream of the premixed flame (eg, including a mixture of diluent and fuel and oxidant), and thus, the premixed flame may not be able to maintain flame stability above certain EGR levels. In other words, in a premixed flame configuration of a gas turbine system, increasing the amount of exhaust gas (eg, EGR) premixed with fuel and oxidant may increasingly reduce the temperature and flame stability of the premixed flame, and thus excessive The EGR may cause the premixed flame to become unstable. However, in the diffusion flame configuration of a gas turbine system, it is believed that an increased amount of exhaust gas (e.g., EGR) can be used with the diffusion flame, well beyond any limitations associated with premixed flame configurations. For example, in a substantially stoichiometric EGR gas turbine system, the amount of exhaust gas (eg, EGR) that can be used to diffuse the flame configuration can be at least about 10 greater than the amount of exhaust gas (eg, EGR) that can be used in the premixed flame configuration. , 20, 30, 40, 50, 60, 70, 80, 90, or 100 percent. In a further example, in a substantially stoichiometric EGR gas turbine system, the amount of exhaust gas (eg, EGR) that can be used to diffuse the flame configuration can be greater than about 35, 40, 45, 50, 55, 60, 65, 70. , or 75 volume percent of exhaust (eg, EGR) relative to the total flow through the combustor and turbine section (eg, total flow of oxidant, fuel, and diluent). A result, CO ₂ can be significantly improved by generation of a diffusion flame (e.g., diffusion fuel nozzles), together with a substantially stoichiometric EGR gas turbine system reached.

Although the fuel diffusion nozzle may particularly help to improve the amount of EGR and produced CO _2, but the specific disclosed example of such various controls to assist in controlling the fuel / oxidant ratio, flame stability, emissions, and power output, Whether the system is operated with a premixed flame, a diffused flame, or a combination thereof. For example, such disclosed embodiments may include a combustor having one or more diffusion fuel nozzles and premixed fuel nozzles that are independently controllable through different fluid supply circuits to provide both a premixed flame configuration and a diffused flame configuration. benefit.

Figure 1 is related to the service system 14 based on the turbine. Schematic representation of a specific example of system 10 of hydrocarbon generation system 12. As described below As further discussed in detail, specific examples of various turbine-based service systems 14 are configured to provide various services (such as electrical, mechanical, and fluid (eg, exhaust)) to the hydrocarbon generation system 12 to promote oil and / or the production or extraction of gas. In the illustrated embodiment, the hydrocarbon generation system 12 includes an oil/gas extraction system 16 and an enhanced oil recovery (EOR) system 18 that are coupled to an underground reservoir 20 (eg, an oil, gas, or hydrocarbon storage tank). . The oil/gas extraction system 16 includes various ground equipment 22, such as a Christmas tree or production tree 24, connected to an oil/gas well 26. Again, the well 26 may include one or more tubular members 28 that extend through the borehole 30 in the earth 32 to the subterranean reservoir 20. The tree 24 includes one or more valves, chokes, isolation sleeves, blowout preventers, and various flow control devices that regulate pressure and control pressure to and from the underground reservoir 20. While the tree 24 is typically used to control the flow of production fluid (e.g., oil or gas) from the subterranean reservoir 20, the EOR system 18 can increase oil or gas by injecting one or more fluids into the subterranean reservoir 20. Produced.

Thus, the EOR system 18 can include a fluid injection system 34, having one or more tubes 36 extending through holes 38 in the earth 32 to the subterranean reservoir 20. For example, the EOR system 18 can send one or more fluids 40 (such as gases, steam, water, chemicals, or any combination thereof) into the fluid injection system 34. For example, as discussed in further detail below, the EOR system 18 can be coupled to a turbine-based service system 14 such that the system 14 sends exhaust gas 42 (eg, substantially or completely free of oxygen) to the EOR system 18 for use as The fluid 40 is injected. Fluid injection System 34 sends fluid 40 (e.g., exhaust gas 42) through one or more tubes 36 into underground reservoir 20, as indicated by arrow 44. The injection fluid 40 enters the underground reservoir 20 through a tubular member 36 that is offset from the tubular member 28 of the oil/gas well 26. Thus, the injection fluid 40 replaces the oil/gas 48 disposed in the subterranean reservoir 20 and drives the oil/gas 48 up through the tubular member 28 of one or more hydrocarbon generating systems 12, as indicated by arrow 50. As discussed in further detail below, the injection fluid 40 can include exhaust gas 42 derived from the turbine-based service system 14, which can generate exhaust gas on-site as desired by the hydrocarbon generation system 12. . In other words, the turbine-based system 14 can simultaneously produce one or more services for use by the hydrocarbon generation system 12 (eg, electrical, mechanical, steam, water (eg, desalinated), and exhaust (eg, Substantially anaerobic)), thereby reducing or eliminating dependence on external sources of such services.

In the illustrated embodiment, the turbine-based service system 14 includes a stoichiometric exhaust gas recirculation (SEGR) gas turbine system 52 and an exhaust (EG) treatment system 54. The gas turbine system 52 can be configured to operate in a stoichiometric combustion mode (eg, a stoichiometric control mode) and an operational non-stoichiometric combustion mode (eg, a non-stoichiometric control mode), such as a lean fuel control mode or fuel rich Control mode to operate. In stoichiometric control mode, combustion typically occurs at a substantially stoichiometric ratio of fuel to oxidant, resulting in substantially stoichiometric combustion. In particular, stoichiometric combustion typically involves the consumption of substantially all of the fuel and oxidant in the combustion reaction such that the combustion products are substantially or completely free of unburned fuel and oxidant. One of stoichiometric combustion is measured as an equivalence ratio, or phi ( ), which is the ratio of the actual fuel to oxidant ratio to the stoichiometric fuel/oxidant ratio. An equivalence ratio greater than 1.0 results in fuel rich combustion of the fuel and oxidant, while an equivalent ratio of less than 1.0 results in lean fuel combustion of the fuel and oxidant. In contrast, an equivalent ratio of 1.0 results in a combustion that is not rich or lean fuel, thereby substantially consuming all of the fuel and oxidant in the combustion reaction. In the case of the specific examples disclosed, the term stoichiometric or substantially stoichiometric may mean an equivalent ratio of from about 0.95 to about 1.05. However, the specific examples disclosed may also include 1.0 plus or minus an equivalent ratio of 0.01, 0.02, 0.03, 0.04, 0.05, or more. Likewise, stoichiometric combustion of fuel and oxidant in a turbine-based service system 14 can result in substantially no combustion products or exhaust gases (eg, 42) that remain unburned fuel or oxidant. For example, the exhaust gas 42 may have a less than 3, 4, or 5 volume percent of an oxidizing agent (e.g., oxygen), the unburned fuel or hydrocarbons (e.g., HCs in), nitrogen oxides (e.g., NO _X), Carbon monoxide (CO), sulfur oxides (e.g., SO _X), hydrogen, and other products of incomplete combustion. In a further example, the exhaust gas 42 can have less than about 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or 5000. parts per million by volume (ppmv) of an oxidant (e.g., oxygen), the unburned fuel or hydrocarbons (e.g., HCs in), nitrogen oxides (e.g., NO _X), carbon monoxide (CO), sulfur oxides (e.g., SO _X ), hydrogen, and other products of incomplete combustion. However, such disclosed embodiments may also produce other ranges of residual fuel, oxidant, and other emissions levels in the exhaust gas 42. As used herein, the term emissions, emission levels, and emissions targets may refer to certain combustion products _{(e.g., NO X, CO, SO X} , O 2, N 2, H 2, HCs, etc.) the levels It may be present in the recycle gas stream, the exhaust gas stream (e.g., vented to the atmosphere), and the gas stream used in various target systems (e.g., hydrocarbon generation system 12).

Although in different specific examples, the SEGR gas turbine system The system 52 and the EG processing system 54 may include various components, but the illustrated EG processing system 54 includes a heat recovery steam generator (HRSG) 56 and an exhaust gas recirculation (EGR) system 58 that may receive and process derived from the SEGR Exhaust gas 60 of gas turbine system 52. The HRSG 56 may include one or more heat exchangers, condensers, and various heat recovery devices that operate together to transfer heat from the exhaust gas 60 to the water stream to produce steam 62. This steam 62 can be used in one or more steam turbines, EOR system 18, or other portions of any hydrocarbon production system 12. For example, the HRSG 56 can generate low pressure, medium pressure, and/or high pressure steam 62 that can be selectively applied to low, medium, and high pressure steam turbine stages, or different applications of the EOR system 18. In addition to the steam 62, treated water 64, such as desalinated water, may be produced by the HRSG 56, the EGR system 58, and/or another portion of the EG processing system 54 or the SEGR gas turbine system 52. The treated water 64 (e.g., desalinated water) is particularly useful in water-deficient areas such as inland or desert areas. The treated water 64 is at least partially generated as a result of the large amount of air driving the combustion of the fuel within the SEGR gas turbine system 52. In many applications, including hydrocarbon generation system 12, steam 62 and water 64 On-site production may be advantageous, and on-site generation of exhaust gases 42, 60 may be particularly advantageous for EOR system 18 due to its low oxygen content, high pressure, and heat from the SEGR gas turbine system 52. Accordingly, the HRSG 56, the EGR system 58, and/or another portion of the EG processing system 54 may output or recirculate the exhaust gas 66 to the SEGR gas turbine system 52 while also sending the exhaust gas 42 to the EOR system 18 for the hydrocarbon generation system. 12 use. Likewise, the exhaust gas 42 may be extracted directly from the SEGR gas turbine system 52 (ie, not through the EG processing system 54) for use in the EOR system 18 for the hydrocarbon generation system 12.

Exhaust gas recirculation is performed by the EGR system of the EG treatment system 54 58 control. For example, the EGR system 58 includes one or more conduits, valves, blowers, exhaust gas treatment systems (eg, filters, degranulation units, gas separation units, gas purification units, heat exchangers, heat recovery units, dehumidification units, touch a media unit, a chemical injection unit, or any combination thereof, and controlled to recirculate exhaust gas from an output of the SEGR gas turbine system 52 (eg, exhaust gas 60) along an exhaust gas recirculation path to an input (eg, an inlet exhaust gas) 66). In the illustrated embodiment, the SEGR gas turbine system 52 draws exhaust gas 66 into a compressor section having one or more compressors to compress the exhaust gas 66 with the inhaled oxidant 68 and one or more fuels 70. It is used in the burner section. The oxidant 68 can include ambient air, pure oxygen, oxygen-enriched air, oxygen-reduced air, an oxygen-nitrogen mixture, or any suitable oxidant that promotes combustion of the fuel 70. Fuel 70 may include one or more gaseous fuels, liquid fuels, or any combination thereof. For example, fuel 70 may include natural gas, liquefied natural gas (LNG), syngas, methane, Ethane, propane, butane, petroleum brain, kerosene, diesel, ethanol, methanol, biofuel, or any combination thereof.

The SEGR gas turbine system 52 mixes and combusts the exhaust gas 66, oxidant 68, and fuel 70 in the combustor section to produce hot combustion gases or exhaust gases 60 to drive one or more turbine stages in the turbine section. In certain embodiments, each combustor in the combustor section includes one or more premixed fuel nozzles, one or more diffusion fuel nozzles, or any combination thereof. For example, each premixed fuel nozzle can be configured to partially mix the oxidant 68 and the fuel 70 internally and/or upstream of the fuel nozzle in the fuel nozzle to inject the oxidant-fuel mixture from the fuel nozzle for premixed combustion. Burning zone (eg, premixed flame). In a further example, each diffusion fuel nozzle can be configured to isolate a flow of oxidant 68 and fuel 70 within the fuel nozzle to separately inject oxidant 68 and fuel 70 from the fuel nozzle into a combustion zone for diffusion combustion (eg, , diffusion flame). In particular, the diffusion combustion provided by the diffusion fuel nozzle delays the mixing of the oxidant 68 and the fuel 70 until the point of initial combustion, i.e., the flame zone. In a specific example of using a diffusion fuel nozzle, the diffusion flame can provide increased flame stability because the diffusion flame is typically at a stoichiometric point between the separate streams of oxidant 68 and fuel 70 (ie, when oxidant 68 and fuel 70 are mixed) Time) formed. In certain embodiments, one or more diluents (eg, exhaust gas 60, steam, nitrogen, or another inert gas) may be in the diffusion fuel nozzle or premixed fuel nozzle with oxidant 68, fuel 70, or both. Premixed. Additionally, one or more diluents (eg, exhaust gas 60, steam, nitrogen, or another inert gas) may be injected into the combustor at or near the point of combustion within each combustor. The use of such diluents may help the flame (e.g., a diffusion flame or a premixed flame) alleviated, thereby helping to reduce NO _X emissions, such as nitric oxide (NO) and nitrogen dioxide (NO _2). Regardless of the type of flame, combustion produces hot combustion gases or exhaust gases 60 to drive one or more turbine stages. When each turbine stage is driven by exhaust gas 60, SEGR gas turbine system 52 produces mechanical power 72 and/or electric power 74 (eg, via a generator). System 52 also outputs exhaust gas 60 and may further output water 64. Likewise, water 64 can be treated water, such as desalinated water, which can be used on-site or off-site for a variety of applications.

Exhaust gas extraction is also provided by a SEGR gas turbine system 52 that uses one or more extraction points 76. For example, the illustrated specific example includes an exhaust (EG) supply system 78 having an exhaust (EG) extraction system 80 and an exhaust (EG) treatment system 82 that receives exhaust gas 42 from extraction point 76, processes exhaust gas 42, and then Exhaust gas 42 is supplied or distributed to various target systems. The target system may include an EOR system 18 and/or other systems, such as line 86, storage tank 88, or carbon sequestration system 90. The EG extraction system 80 can include one or more conduits, valves, controls, and flow separations that promote separation of the exhaust gases 42 from the oxidant 68, fuel 70, and other contaminants while also controlling the temperature and pressure of the extracted exhaust gases 42. , and flow rate. The EG processing system 82 can include one or more heat exchangers (eg, a heat recovery unit such as a heat recovery steam generator, a condenser, a cooler, or a heater), a catalyst system (eg, an oxidation catalyst system), Granules and/or water removal systems (eg, gas dehydration units, inertial separators, combined filters, water-impermeable filters, and other filters), chemical injection systems, solvent-based processing systems (eg, absorption) , flash tank, etc.), carbon capture system, gas separation system, gas purification system, and/or solvent based processing system, exhaust gas compressor, any combination thereof. The secondary systems of such EG processing systems 82 are capable of controlling temperature, pressure, flow rate, moisture content (eg, amount of water removed), particulate content (eg, amount of particulate removal), and gas composition (eg, CO ₂ , N). ₂ , etc.).

Depending on the target system, the extracted exhaust gas 42 is processed by one or more secondary systems of the EG processing system 82. For example, EG processing system 82 can direct all or a portion of exhaust gas 42 through a carbon capture system, a gas separation system, a gas purification system, and/or a solvent-based processing system that is controlled for separation and purification for various The carbon dioxide gas (e.g., carbon dioxide) 92 and/or nitrogen (N ₂ ) 94 of the target system. For example, a specific example of EG processing system 82 may perform gas separation and purification to produce a plurality of different streams 95 of exhaust gas 42 (such as first stream 96, second stream 97, and third stream 98). 96 may have a first stream rich in carbon dioxide and / or nitrogen, depleted first composition (e.g., CO ₂ rich stream lean N _2). The second stream 97 can have a second concentration of carbon dioxide and/or nitrogen at an intermediate concentration level (eg, an intermediate concentration of CO ₂ and N ₂ streams). 98 may have a third carbon dioxide-lean stream and / or the third nitrogen enriched composition (e.g., the CO ₂ lean stream enriched N _2). Each stream 95 (e.g., 96, 97, and 98) can include a gas dehydration unit, a filter, a gas compressor, or any combination thereof to facilitate delivery of stream 95 to the target system. In certain instances, the N ₂ lean CO ₂ rich stream 96 may be greater than about 70,75,80,85,90,95,96,97,98, or 99 percent by volume CO ₂ concentration or the purity level, And less than about 1, 2, 3, 4, 5, 10, 15, 20, 25, or 30 volume percent N ₂ purity or concentration levels. In contrast, N ₂ enriched CO ₂ lean stream may have less than about 98 1,2,3,4,5,10,15,20,25, or 30 percent by volume of CO ₂ concentration or the purity level of greater than about 70, 75, 80, 85, 90, 95, 96, 97, 98, or 99 volume percent N ₂ purity or concentration level. The intermediate concentration CO ₂ and N ₂ stream 97 can have a CO ₂ purity or concentration level and/or N ₂ purity or concentration level between about 30 to 70, 35 to 65, 40 to 60, or 45 to 55 volume percent. . While the foregoing ranges are only non-limiting examples, the CO ₂ lean N ₂ stream 96 and the CO ₂ rich N ₂ stream 98 may be particularly suitable for use with the EOR system 18 and other systems 84. However, any such rich, lean, or an intermediate concentration of 95 CO ₂ stream may be used alone or in various combinations with other EOR systems 18 and 84 of the systems used. For example, EOR system 18 and other systems 84 (eg, line 86, storage tank 88, and carbon sequestration system 90) each can receive one or more CO ₂ lean N ₂ streams 96, one or more lean CO ₂ rich The N ₂ stream 98, one or more intermediate concentrations of CO ₂ and N ₂ streams 97, and one or more untreated exhaust gas streams 42 (ie, bypassing the EG processing system 82).

The EG extraction system 80 is along the compressor section, the combustor section, And/or the turbine section extracts the exhaust gas 42 at one or more extraction points 76 such that the exhaust gas 42 can be used in the EOR system 18 and other systems 84 at appropriate temperatures and pressures. The EG extraction system 80 and/or EG processing system 82 may also circulate fluid streams (e.g., exhaust gas 42) into and out of the EG processing system 54. For example, a portion of the exhaust gas 42 passing through the EG processing system 54 may be passed through an EG extraction system. The system 80 is extracted for use in the EOR system 18 and other systems 84. In some embodiments, the EG supply system 78 and the EG processing system 54 can be integrated independently or with each other, and thus they can use separate or shared subsystems. For example, EG processing system 82 can be used by both EG supply system 78 and EG processing system 54. Exhaust gas 42 extracted from the EG processing system 54 may be subjected to multiple stages of gas processing, such as one or more stages of gas processing in the EG processing system 54, followed by additional one or more stages of gas processing in the EG processing system 82. .

At each extraction point 76, the extracted off-gas 42 may be substantially free of oxidant 68 and fuel 70 (eg, unburned fuel or hydrocarbons due to substantially stoichiometric combustion and/or gas treatment performed in EG processing system 54). ). Further, depending on the target system, the extracted exhaust gas 42 is further processed in the EG processing system 82 of the EG supply system 78 to further reduce any residual oxidant 68, fuel 70, or other undesirable combustion products. For example, the extracted exhaust gas 42 may have less than 1, 2, 3, 4, or 5 volume percent oxidant (eg, oxygen), unburned fuel, or hydrocarbons before or after processing in the EG processing system 82 (eg, HCs in), nitrogen oxides (e.g., nO _X), carbon monoxide (CO), sulfur oxides (e.g., SO _X), hydrogen, and other products of incomplete combustion. In a further example, the extracted exhaust gas 42 may have less than about 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400 before or after processing in the EG processing system 82. , 500,1000,2000,3000,4000, or 5000 parts per million by volume (ppmv) of an oxidant (e.g., oxygen), the unburned fuel or hydrocarbons (e.g., HCs in), nitrogen oxides (e.g., NO _X ) carbon monoxide (CO), sulfur oxides (eg, SO _X ), hydrogen, and other products of incomplete combustion. Therefore, the exhaust gas 42 is particularly suitable for use with the EOR system 18.

The EGR operation of the turbine system 52 is specifically allowed in many positions Set 76 to extract the exhaust gas. For example, the compressor section of system 52 can be used to compress exhaust gas 66 without any oxidant 68 (i.e., only compression of exhaust gas 66) such that substantially oxygen-free exhaust gas 42 can exit the compressor section prior to the inlet of oxidant 68 and fuel 70. And / or burner section extraction. The extraction point 76 can be located between the interstage ports between adjacent compressor stages, at the ports along the compressor discharge shroud, along the ports of the burners in the combustor section, or any combination thereof. In some embodiments, the exhaust gas 66 can be mixed with the oxidant 68 and the fuel 70 after reaching the head end portion of each combustor in the combustor section and/or the fuel nozzle. Further, one or more flow separators (eg, walls, dividers, baffles, or the like) can be used to isolate oxidant 68 and fuel 70 from extraction point 76. Using these flow separators, the extraction point 76 can be configured directly along the walls of each combustor in the combustor section.

Once the exhaust gas 66, the oxidant 68, and the fuel 70 flow through the head The end portion (e.g., through a fuel nozzle) enters a combustion portion (e.g., a combustion chamber) of each combustor, and the SEGR gas turbine system 52 is controlled to provide substantially stoichiometric combustion of the exhaust gas 66, the oxidant 68, and the fuel 70. For example, system 52 can maintain an equivalent ratio of from about 0.95 to about 1.05. As a result, the combustion products of the mixture of exhaust gas 66, oxidant 68, and fuel 70 in each combustor are substantially oxygen free and unburned. Therefore, combustion products (or exhaust) may be extracted from the turbine section of the SEGR gas turbine system 52 Used as exhaust gas 42 to the EOR system 18. Along the turbine section, the extraction point 76 can be located at any turbine stage, such as an interstage port between adjacent turbine stages. Thus, using any of the aforementioned extraction points 76, the turbine-based service system 14 can generate, extract, and deliver exhaust gas 42 to a hydrocarbon generation system 12 (e.g., EOR system 18) for use in producing oil from the underground storage 20. Gas 48.

2 is an illustration of a specific example of the system 10 of FIG. A control system 100 coupled to a turbine-based service system 14 and a hydrocarbon generation system 12 is illustrated. In the illustrated embodiment, the turbine-based service system 14 includes a combined cycle system 102 that includes a SEGR gas turbine system 52 as a top cycle, a steam turbine 104 as a bottom cycle, and a recovery from exhaust gas 60. Heat is generated to generate HRSG 56 for driving steam 62 of steam turbine 104. Similarly, SEGR gas turbine system 52 receives, mixes, and stoichiometrically combusts exhaust gas 66, oxidant 68, and fuel 70 (eg, premixed and/or diffused flames) to produce exhaust gas 60, mechanical power 72, electrical power 74, And / or water 64. For example, SEGR gas turbine system 52 can drive one or more loads or machines 106, such as generators, oxidant compressors (eg, main air compressors), gearboxes, pumps, equipment of hydrocarbon generation system 12, or any thereof combination. In some embodiments, machine 106 may include other drives in series with SEGR gas turbine system 52, such as an electric motor or steam turbine (eg, steam turbine 104). Thus, the output of machine 106 driven by SEGR gas turbine system 52 (and any additional drives) may include mechanical power 72 and electricity Force 74. Mechanical power 72 and/or power 74 may be used on-site to power hydrocarbon production system 12, and power 74 may be distributed to the power grid, or any combination thereof. The output of machine 106 may also include a compressed fluid for introducing a combustion section of SEGR gas turbine system 52, such as a compressed oxidant 68 (eg, air or oxygen). Such outputs (e.g., exhaust gas 60, mechanical power 72, power 74, and/or water 64) may each be considered to be services of a turbine-based service system 14.

SEGR gas turbine system 52 produces exhaust gases 42, 60, which This may be substantially oxygen free and the exhaust gases 42, 60 are sent to the EG processing system 54 and/or the EG supply system 78. The EG supply system 78 can process and deliver the exhaust gas 42 (eg, stream 95) to the hydrocarbon generation system 12 and/or other systems 84. As discussed above, EG processing system 54 may include HRSG 56 and EGR system 58. The HRSG 56 may include one or more heat exchangers, condensers, and various heat recovery devices that may be used to recover or transfer heat from the exhaust gas 60 to the water 108 to produce steam 62 for driving the steam turbine 104. Similar to the SEGR gas turbine system 52, the steam turbine 104 can drive one or more loads or machines 106 to generate mechanical power 72 and electrical power 74. In the illustrated embodiment, the SEGR gas turbine system 52 and steam turbine 104 are arranged in series to drive the same machine 106. However, in other embodiments, SEGR gas turbine system 52 and steam turbine 104 may separately drive different machines 106 to independently generate mechanical power 72 and/or power 74. When steam turbine 104 is driven by steam 62 from HRSG 56, the temperature and pressure of steam 62 gradually decreases. Thus, steam turbine 104 recirculates used steam 62 and/or water 108 back to HRSG 56. Additional steam generation is provided via heat recovery from the exhaust gas 60. In addition to steam generation, HRSG 56, EGR system 58, and/or another portion of EG processing system 54 may generate water 64, exhaust gas 42 that may be used with hydrocarbon generation system 12, and may be used as an input SEGR gas turbine system 52. Exhaust gas 66. For example, water 64 can be treated water 64 for other applications, such as desalinated water. Demineralized water is particularly useful in areas where low water availability is available. With respect to exhaust gas 60, a specific example of EG processing system 54 may be configured to recirculate exhaust gas 60 through EGR system 58 with or without exhaust gas 60 through HRSG 56.

In the specific example illustrated, the SEGR gas turbine system 52 has an exhaust gas recirculation path 110 that extends from the exhaust gas outlet of system 52 to the exhaust gas inlet. Along this path 110, exhaust gas 60 passes through an EG processing system 54, which in the illustrated embodiment includes an HRSG 56 and an EGR system 58. The EGR system 58 may include one or more conduits, valves, blowers, gas treatment systems (eg, filters, degranulation units, gas separation units, gas purification units, heat) arranged in series and/or in parallel along the path 110. An exchanger, a heat recovery unit such as a heat recovery steam generator, a dehumidification unit, a catalyst unit, a chemical injection unit, or any combination thereof. In other words, EGR system 58 may include any flow control assembly, pressure control assembly, temperature control assembly, moisture control assembly, and gas composition control along the exhaust gas recirculation path 110 between the exhaust gas outlet and exhaust gas inlet of system 52. Component. Thus, in a particular example having HRSG 56 along path 110, HRSG 56 may be considered a component of EGR system 58. However, in some specific examples, the HRSG 56 may be along and waste The gas recirculation path 110 has an unrelated discharge path configuration. Regardless of whether the HRSG 56 is along a different path or a shared path than the EGR system 58, the HRSG 56 and the EGR system 58 draw in the exhaust gas 60 and output the recirculated exhaust gas 66, the exhaust gas 42 available for use with the EG supply system 78 (eg, The hydrocarbon generation system 12 and/or other system 84), or another output of exhaust gas. Likewise, SEGR gas turbine system 52 inhales, mixes, and stoichiometrically combusts exhaust gas 66, oxidant 68, and fuel 70 (eg, premixed and/or diffused flame) to produce a hydrocarbon for distribution to EG processing system 54, A substantially oxygen-free and fuel-free exhaust gas 60 of system 12, or other system 84, is produced.

As described above with reference to Figure 1, the hydrocarbon generation system 12 can include various An apparatus that facilitates recovery or production of oil/gas 48 from underground storage 20 through oil/gas well 26. For example, hydrocarbon generation system 12 can include an EOR system 18 having a fluid injection system 34. In the illustrated embodiment, the fluid injection system 34 includes an exhaust gas injection EOR system 112 and a steam injection EOR system 114. While fluid injection system 34 can receive fluids from a variety of sources, the illustrated embodiment can receive exhaust gas 42 and steam 62 from a turbine-based service system 14. Exhaust gas 42 and/or steam 62 produced by the turbine-based service system 14 may also be sent to the hydrocarbon generation system 12 for use in other oil/gas systems 116.

The amount, mass, and flow of exhaust gas 42 and/or steam 62 may be Control system 100 controls. The control system 100 can be fully utilized for the turbine-based service system 14, or the control system 100 can optionally provide control (or at least some data to the hydrocarbon generation system 12 and/or other systems 84). For control). In the illustrated embodiment, the control system 100 includes a controller 118 having a processor 120, a memory 122, a steam turbine control 124, a SEGR gas turbine system control 126, and a machine control 128. Processor 120 may include a single processor or two or more redundant processors, such as a triple redundant processor for controlling a turbo-based service system 14. Memory 122 can include volatile and/or non-volatile memory. For example, memory 122 can include one or more hard disks, flash memory, read only memory, random access memory, or any combination thereof. Controls 124, 126, and 128 may include software and/or hardware controls. For example, controls 124, 126, and 128 can include various instructions or code stored in memory 122 and executed by processor 120. Control 124 is configured to control operation of steam turbine 104, SEGR gas turbine system control 126 is configured to control system 52, and machine control 128 is configured to control machine 106. Accordingly, controller 118 (eg, controls 124, 126, and 128) may be configured to integrate various exhaust systems of turbine-based service system 14 to provide a suitable exhaust gas stream 42 to hydrocarbon generation system 12.

In some specific examples of the control system 100, in the illustration Each of the elements (eg, systems, subsystems, and components) described or described herein includes (eg, directly within, upstream, or downstream of the element) one or more via an industrial control network and controller 118 Industrial control features that are communicatively coupled to one another, such as sensors and controls. For example, the control device associated with each component can include a dedicated device controller (eg, including a processor, memory, and control instructions), one or more The actuators, valves, switches, and industrial control devices are capable of being controlled based on sensor feedback 130, control signals from the controller 118, control signals from the user, or any combination thereof. Thus, any of the control functions described herein can be implemented by control instructions stored and/or executed by controller 118, a dedicated device controller associated with each component, or a combination thereof.

To facilitate this control function, control system 100 includes one or more sensors distributed throughout system 10 to obtain sensor feedback 130 for performing various controls (eg, controls 124, 126, and 128). For example, sensor feedback 130 may be distributed throughout SEGR gas turbine system 52, machine 106, EG processing system 54, steam turbine 104, hydrocarbon generation system 12, or any turbine-based service system 14 or hydrocarbon Sensors that generate other components in system 12 are obtained. For example, sensor feedback 130 may include temperature feedback, pressure feedback, flow rate feedback, flame temperature feedback, combustion dynamics feedback, inlet oxidant composition feedback, inlet fuel composition feedback, emissions composition feedback, output level of mechanical power 72, power The output level of 74, the output of exhaust gases 42, 60, the output or quality of water 64, or any combination thereof. For example, sensor feedback 130 may include a composition of exhaust gases 42, 60 to facilitate stoichiometric combustion in SEGR gas turbine system 52. For example, sensor feedback 130 may include an inlet oxidant sensor from one or more oxidant supply paths along oxidant 68, one or more inlet fuel sensors along a fuel supply path of fuel 70, and a Feedback of a plurality of exhaust emission sensors disposed along the exhaust gas recirculation path 110 and/or within the SEGR gas turbine system 52. The inlet oxidant sensor, the inlet fuel sensor, and the exhaust emission sensor can include a temperature sensor, a pressure sensor, a flow rate sensor, and a component sensor. Emissions sensor may include a nitrogen oxide (e.g., NO _X sensor), carbon oxides (e.g., CO and CO ₂ sensors sensor), sulfur oxides (e.g., SO _X sensor ), hydrogen (eg, H ₂ sensor), oxygen (eg, O ₂ sensor), unburned hydrocarbon (eg, HC sensor), or other incompletely combusted product, or any combination thereof Sensor.

Using this feedback 130, the control system 100 can adjust (eg, increase, decrease, or maintain) the exhaust gas 66, the oxidant 68, and/or the fuel 70 into the inlet flow of the SEGR gas turbine system 52 (among other operating parameters) to The equivalent ratio is maintained within a suitable range, for example, between about 0.95 and about 1.05, between about 0.95 and about 1.0, between about 1.0 and about 1.05, or substantially 1.0. For example, control system 100 can analyze feedback 130 to monitor exhaust emissions (eg, nitrogen oxides, carbon oxides such as CO and CO ₂ , sulfur oxides, hydrogen, oxygen, unburned hydrocarbons, and other products that are not completely combusted). The concentration level) and/or determine the equivalence ratio, and then control one or more components to adjust exhaust emissions (eg, concentration levels in the exhaust gas 42) and/or equivalence ratios. The control assembly can include any of the components illustrated and described with reference to the drawings, including but not limited to valves along the supply path for oxidant 68, fuel 70, and exhaust 66; oxidant compressor, fuel pump, or EG processing system Any of the components of 54; any component of the SEGR gas turbine system 52, or any combination thereof. The control assembly can adjust (eg, increase, decrease, or maintain) the flow rate, temperature, pressure, or percentage (eg, equivalence ratio) of the oxidant 68, fuel 70, and exhaust 66 combusted within the SEGR gas turbine system 52. The control assembly may also include one or more gas treatment systems, such as a catalytic unit (eg, an oxidation catalyst unit), a supply for the catalyst unit (eg, oxidizing fuel, heat, electricity, etc.), gas purification, and/or Or a separation unit (for example, a solvent-based separator, an absorber, a flash tank, etc.), and a filtration unit. The gas treatment system can help reduce various exhaust emissions along the exhaust gas recirculation path 110, the exhaust path (eg, vented to the atmosphere), or to the extraction path of the EG supply system 78.

In some embodiments, the control system 100 can analyze the feedback 130 and control one or more components to maintain or reduce emissions levels (eg, concentration levels of exhaust gases 42, 60, 95) to a target range, such as less than about 10 20, 30, 40, 50, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, 5000, or 10,000 parts by volume (ppmv). These target ranges may be the same or different for each exhaust gas emission (eg, concentration levels of nitrogen oxides, carbon monoxide, sulfur oxides, hydrogen, oxygen, unburned hydrocarbons, and other products that are not completely combusted). For example, depending on the equivalence ratio, control system 100 can selectively control exhaust emissions (eg, concentration levels): the oxidant (eg, oxygen) is less than about 10, 20, 30, 40, 50, 60, 70, 80, Within the target range of 90, 100, 250, 500, 750, or 1000 ppmv; carbon monoxide (CO) in the target range of less than about 20, 50, 100, 200, 500, 1000, 2500, or 5000 ppmv; and nitrogen oxides ( NO _X) in less than about 50,100,200,300,400 or 500ppmv the target range. In certain embodiments operating with a substantially stoichiometric equivalent ratio, the control system 100 can selectively control exhaust emissions (eg, concentration levels): the oxidant (eg, oxygen) is less than about 10, 20, 30, 40, Within the target range of 50, 60, 70, 80, 90, or 100 ppmv; and carbon monoxide (CO) within a target range of less than about 500, 1000, 2000, 3000, 4000, or 5000 ppmv. In certain embodiments operating with a lean fuel equivalent ratio (eg, between about 0.95 and 1.0), control system 100 can selectively control exhaust emissions (eg, concentration levels): oxidant (eg, oxygen) at Within a target range of less than about 500, 600, 700, 800, 900, 1000, 1100, 1200, 1300, 1400, or 1500 ppmv; carbon monoxide (CO) is less than about 10, 20, 30, 40, 50, 60, 70, 80,90,100,150 within target range, or of 200ppmv; and nitrogen oxides (e.g., NO _X) within less than about 50,100,150,200,250,300,350, or the target range 400ppmv. The foregoing range of objectives is only an example and is not intended to limit the scope of the specific examples disclosed.

Control system 100 can also be connected to close interface 132 and far Cheng Jie 134. For example, the proximity interface 132 can include a computer workstation that is field configured on the turbine-based service system 14 and/or the hydrocarbon generation system 12. In contrast, the remote interface 134 can include a computer workstation that is remotely deployed to the turbine-based service system 14 and the hydrocarbon generation system 12, such as via an internet connection. These interfaces 132 and 134 facilitate monitoring and control of the turbine-based service system 14, such as a graphical display that passes through one or more sensor feedbacks 130, operational parameters, and the like.

Likewise, as described above, the controller 118 includes various controls 124, 126, and 128 are implemented to facilitate control of the turbine-based service system 14. Steam turbine control 124 may receive sensor feedback 130 and output control commands to facilitate operation of steam turbine 104. For example, steam turbine control 124 can receive temperature and pressure sensors from HRSG 56, machine 106, a path along steam 62, temperature and pressure sensors along the path of water 108, and various indicating mechanical powers 72 and Sensor feedback 130 of the sensor of power 74. Likewise, SEGR gas turbine system control 126 can receive sensor feedback 130 from one or more sensors configured along the SEGR gas turbine system 52, machine 106, EG processing system 54, or any combination thereof. . For example, sensor feedback 130 may be derived from a temperature sensor, pressure sensor, gap sensor, vibration sensor, flame sensor, fuel composition configured within or external to SEGR gas turbine system 52. The detector, the exhaust gas composition sensor, or any combination thereof. Finally, machine control 128 can receive various sensor responses from mechanical power 72 and power 74, as well as sensor feedback 130 of the sensors disposed within machine 106. These controls 124, 126, and 128 each use sensor feedback 130 to improve the operation of the turbine-based service system 14.

In the illustrated embodiment, SEGR gas turbine system control 126 may execute instructions to control exhaust gases 42, 60, 95 of EG processing system 54, EG supply system 78, hydrocarbon generation system 12, and/or other systems 84. Quantity and quality. For example, the SEGR gas turbine system control 126 may maintain the level of oxidant (eg, oxygen) and/or unburned fuel in the exhaust gas 60 below a threshold suitable for use with the exhaust gas injection EOR system 112. In certain embodiments, the threshold level can be less than 1, 2, 3, 4, or 5 percent of oxidant (eg, oxygen) and/or unburned fuel, or oxidant (eg, by volume of exhaust gases 42, 60) , oxygen) and/or unburned fuel (and other exhaust emissions) may have a threshold level in the exhaust gases 42, 60 of less than about 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300. , 400, 500, 1000, 2000, 3000, 4000, or 5000 parts per million (ppmv). In a further example, to achieve such low levels of oxidant (eg, oxygen) and/or unburned fuel, SEGR gas turbine system control 126 may maintain a combustion equivalent ratio in SEGR gas turbine system 52 of between about 0.95. And about 1.05. The SEGR gas turbine system control 126 can also control the EG extraction system 80 and the EG processing system 82 to maintain the temperature, pressure, flow rate, and gas composition of the exhaust gases 42, 60, 95 in the exhaust gas injection EOR system 112, line 86. The storage tank 88, and the carbon sequestration system 90 are within an appropriate range. As discussed above, EG processing system 82 may be controlled to 42 purified exhaust gas and / or separated into one or more gas flow 95, such as a CO ₂ rich lean N ₂ stream 96, intermediate concentrations of CO ₂ and N ₂ stream 97, and The CO ₂ rich N ₂ stream 98. In addition to the controls for exhaust gases 42, 60, and 95, controls 124, 126, and 128 can execute one or more commands to maintain mechanical power 72 within an appropriate power range, or maintain power 74 at an appropriate frequency and power. Within the scope.

3 is an illustration of a specific example of system 10, further Details of the gas turbine engine 52 for use with the hydrocarbon generation system 12 and/or other systems 84 are illustrated. In the illustrated embodiment, the SEGR gas turbine system 52 includes a gas turbine engine coupled to the EG processing system 54 150. The illustrated gas turbine engine 150 includes a compressor section 152, a combustor section 154, and an expander section or turbine section 156. Compressor section 152 includes one or more exhaust gas compressor or compressor stages 158, such as 1 to 20 stages of rotary compressor blades arranged in series. Likewise, the combustor section 154 includes one or more combustors 160, such as 1 to 20 combustors 160 circumferentially distributed about the axis of rotation 162 of the SEGR gas turbine system 52. Further, each combustor 160 can include one or more fuel nozzles 164 configured to inject exhaust gas 66, oxidant 68, and/or fuel 70. For example, the head end portion 166 of each combustor 160 can house 1, 2, 3, 4, 5, 6, or more fuel nozzles 164 that can flow the exhaust gas 66, the oxidant 68, and/or the fuel 70 or The mixture is injected into a combustion portion 168 (e.g., a combustion chamber) of the combustor 160.

Fuel nozzle 164 may include a premixed fuel nozzle 164 (eg, oxidant 68 and fuel 70 configured to premix oxidant/fuel premixed flame) and/or a diffusion fuel nozzle 164 (eg, configured to inject for production) Any combination of oxidant/fuel diffusion flame oxidant 68 and separate flow of fuel 70). Specific examples of the premixed fuel nozzle 164 may include a swirl vane, a mixing chamber, or other features to internally mix the oxidant 68 and the fuel 70 in the nozzle 164. The premixed fuel nozzle 164 can also receive at least some of the partially mixed oxidant 68 and fuel 70. In some embodiments, each diffusion fuel nozzle 164 can isolate the flow of oxidant 68 and fuel 70 up to the point of injection while also isolating one or more diluents (eg, exhaust gas 66, steam, nitrogen, or another inert gas). The flow until the injection point. In other embodiments, each diffusion fuel nozzle 164 can isolate the flow of oxidant 68 and fuel 70 until the point of injection while partially mixing one or more diluents (eg, exhaust gas 66, steam, nitrogen, or Another inert gas) is with the oxidant 68 and/or the fuel 70. Additionally, one or more diluents (eg, exhaust gas 66, steam, nitrogen, or another inert gas) may be injected into the combustor or downstream (eg, injected into the hot product of combustion) to help reduce the heat of combustion the temperature of the product and reduce the NO _X (e.g., NO, and NO ₂₎ of the discharge. Regardless of the type of fuel nozzle 164, the SEGR gas turbine system 52 can be controlled to provide substantially stoichiometric combustion of the oxidant 68 and fuel 70.

In operation, as shown, compressor section 152 receives and Exhaust gas 66 from EG processing system 54 is compressed, and compressed exhaust gas 170 is output to each combustor 160 in combustor section 154. Once fuel 60, oxidant 68, and exhaust gas 170 are combusted within each combustor 160, additional combustion exhaust or product 172 (ie, combustion gases) is sent to turbine section 156. Similar to compressor section 152, turbine section 156 includes one or more turbine or turbine stages 174, which may include a series of rotating turbine blades. These turbine blades are then driven by combustion products 172 produced in the combustor section 154 to drive rotation of the shaft 176 that is coupled to the machine 106. Likewise, machine 106 may include various devices coupled to either end of SEGR gas turbine system 52, such as machines 106, 178 coupled to turbine section 156 and/or machines 106, 180 coupled to compressor section 152. In some embodiments, the machine 106, 178, 180 can include one or more generators, an oxidant compressor for the oxidant 68, a fuel pump for the fuel 70, a gearbox, or a SEGR gas turbine. Additional drivers for system 52 (eg steam turbine 104, electric motor, etc.). As shown, the vortex The wheel section 156 outputs exhaust gas 60 to recirculate from the exhaust gas outlet 182 of the turbine section 156 to the exhaust gas inlet 184 along the exhaust gas recirculation path 110 into the compressor section 152. As discussed in detail above, along the exhaust gas recirculation path 110, the exhaust gas 60 passes through an EG processing system 54 (eg, HRSG 56 and/or EGR system 58).

Similarly, each burner 160 in the combustor section 154 is connected The compressed exhaust gas 170, oxidant 68, and fuel 70 are combusted, mixed, and stoichiometrically combusted to produce additional combustion exhaust gases or products 172 to drive the turbine section 156. In some embodiments, the oxidant 68 is compressed by an oxidant compression system 186, such as a primary air compression (MAC) system. The oxidant compression system 186 includes an oxidant compressor 188 that is coupled to a driver 190. For example, drive 190 can include an electric motor, a combustion engine, or any combination thereof. In some embodiments, the driver 190 can be a turbine engine, such as a gas turbine engine 150. Thus, the oxidant compression system 186 can be an integral part of the machine 106. In other words, the compressor 188 can be driven, directly or indirectly, by mechanical power 72 provided by the shaft 176 of the gas turbine engine 150. In this particular example, the driver 190 can be eliminated because the compressor 188 is dependent on the power output from the turbine engine 150. However, in the particular embodiment illustrated, the oxidant compression system 186 is separate from the machine 106. In either embodiment, compression system 186 compresses and supplies oxidant 68 to fuel nozzle 164 and combustor 160. As discussed in further detail below, oxidant 68 and fuel 70 may be provided to gas turbine engine 150 at a particular selected location to facilitate pressure Isolation and extraction of the reduced exhaust gas 170 without any oxidant 68 or fuel 70 that degrades the quality of the exhaust gas 170.

As shown in Figure 3, the EG supply system 78 is configured to burn Between the gas turbine engine 150 and a target system (e.g., hydrocarbon generation system 12 and other systems 84). In particular, an EG supply system 78 (eg, an EG extraction system (EGES) 80) can be coupled to the combustion section along the compressor section 152, the combustor section 154, and/or the turbine section 156 at one or more extraction points 76. Gas turbine engine 150. For example, the extraction point 76 can be located between adjacent compressor stages, such as between 2, 3, 4, 5, 6, 7, 8, 9, or 10 stages between compressor stages. This inter-stage extraction point 76 each provides an extracted exhaust gas 42 of varying temperature and pressure. Similarly, the extraction point 76 can be located between adjacent turbine stages, such as between 2, 3, 4, 5, 6, 7, 8, 9, or 10 interstage extraction points 76 between turbine stages. This inter-stage extraction point 76 each provides an extracted exhaust gas 42 of varying temperature and pressure. In a further example, the extraction points 76 can be located at numerous locations throughout the combustor section 154 to provide different temperatures, pressures, flow rates, and gas compositions. Each of the extraction points 76 can include an EG extraction conduit, one or more valves, a sensor, and a control that can be used to selectively control the flow of the extracted exhaust gas 42 to the EG supply system 78.

The extracted exhaust gas 42 (which is distributed by the EG supply system 78) has a control composition suitable for the target system (e.g., the hydrocarbon production system 12 and other systems 84). For example, at each of these extraction points 76, the exhaust gas 170 can be substantially isolated from the injection point (or flow) of the oxidant 68 and the fuel 70. In other words, the EG supply system 78 can be specifically designed to extract the exhaust gas 170 from the gas turbine engine 150 without any added oxidant 68 or fuel 70. Moreover, in view of the stoichiometric combustion in each combustor 160, the extracted exhaust gas 42 can be substantially oxygen free and fuel. The EG supply system 78 can send the extracted exhaust gas 42 directly or indirectly to the hydrocarbon generation system 12 and/or other system 84 for use in various methods, such as enhanced oil recovery, carbon sequestration, storage, or to an off-site location. . However, in some embodiments, EG supply system 78 includes an EG processing system (EGTS) 82 for further processing of exhaust gas 42 prior to use with the target system. For example, EG processing system 82 may be 42 purified exhaust gas and / or separated into one or more streams 95, such as a CO ₂ rich lean N ₂ stream 96, intermediate concentrations of CO ₂ and N ₂ stream 97, and the CO ₂ lean-rich N ₂ stream 98. These treated exhaust streams 95 can be used with the hydrocarbon production system 12 and other systems 84 (e.g., line 86, storage tank 88, and carbon sequestration system 90), either individually or in any combination.

Similar to the exhaust gas treatment performed in the EG supply system 78, The EG processing system 54 may include a plurality of exhaust gas (EG) processing components 192, such as those represented by component numbers 194, 196, 198, 200, 202, 204, 206, 208, and 210. These EG processing components 192 (e.g., 194-210) may be disposed along the exhaust gas recirculation path 110 in one or more series, parallel, or any combination of series and parallel arrangements. For example, EG processing component 192 (eg, 194-210) can include any of the following series and/or parallel arrangements in any order: one or more heat exchangers (eg, heat recovery units such as heat recovery steam generators, condensation) , cooler, or heater), catalyst system (eg, oxidation catalyst) System, degranulation and/or water removal systems (eg, inertial separators, combined filters, water-impermeable filters, and other filters), chemical injection systems, solvent-based treatment systems (eg, absorption) , flash tank, etc.), carbon capture system, gas separation system, gas purification system, and/or solvent based processing system, or any combination thereof. In some embodiments, the catalyst system may include an oxidation catalyst, a carbon monoxide reduction catalyst, a nitrogen oxide reduction catalyst, aluminum oxide, zirconium oxide, hafnium oxide, titanium oxide, platinum oxide, palladium oxide, cobalt oxide, Or a mixed metal oxide, or a combination thereof. The specific examples disclosed are intended to include any and all permutations of the series and parallel arrangements of the aforementioned components 192. As shown below, Table 1 describes a non-limiting example of some of the components 192 being aligned along the exhaust gas recirculation path 110.

As shown in Table 1, the catalyst unit is represented by CU, oxidized The catalyst unit is represented by OCU, the booster blower is indicated by BB, the heat exchanger is represented by HX, the heat recovery unit is represented by HRU, the heat recovery steam generator is represented by HRSG, and the condenser is represented by COND, steam The turbine system is denoted by ST, the degranulation unit is represented by PRU, the dehumidification unit is represented by MRU, the filter is represented by FIL, and the combined filter system Expressed in terms of CFIL, the water-impermeable filter is represented by WFIL, the inertial separator is represented by INER, and the diluent supply system (eg, steam, nitrogen, or other inert gas) is represented by DIL. While Table 1 illustrates component 192 in the order from exhaust gas outlet 182 of turbine section 156 to exhaust gas inlet 184 of compressor section 152, Table 1 is also intended to encompass the reverse sequence of illustrated assembly 192. In Table 1, any square comprising two or more components is intended to encompass integrated units, parallel arrangements of components, or any combination thereof. Furthermore, in the scope of Table 1, HRU, HRSG, and COND are examples of HE; HRSG is an example of HRU; COND, WFIL, and CFIL are examples of WRU; and INER, FIL, WFIL, and CFIL are examples of PRU; And WFIL and CFIL are examples of FIL. Similarly, Table 1 is not intended to exclude any arrangement of components 192 that are not illustrated. In some embodiments, illustrated components 192 (eg, 194 through 210) may be partially or fully integrated into HRSG 56, EGR system 58, or any combination thereof. These EG processing components 192 can provide feedback control of temperature, pressure, flow rate, and gas composition while also removing moisture and particulates from the exhaust gas 60. Further, the treated exhaust gas 60 may be extracted at one or more extraction points 76 for use in the EG supply system 78 and/or recycled to the exhaust gas inlet 184 of the compressor section 152.

When the treated recirculated exhaust gas 66 passes through the compressor section 152. The SEGR gas turbine system 52 can exhaust a portion of the compressed exhaust gas along one or more lines 212 (eg, an exhaust conduit or a bypass conduit). Each line 212 can send exhaust gas into one or more heat exchangers 214 (eg, a cooling unit) for cooling for recirculation back to the SEGR gas vortex Exhaust gas from wheel system 52. For example, after passing through the heat exchanger 214, a portion of the cooled exhaust gas may be sent to the turbine section 156 along a line 212 for cooling and/or sealing of the turbine shroud, turbine shroud, bearings, and other components. In this particular example, the SEGR gas turbine system 52 will not send any oxidant 68 (or other possible contaminant) through the turbine section 156 for cooling and/or sealing purposes, and thus any leaking cooling exhaust will not It will contaminate the combustion heat products (e.g., working exhaust gases) that flow through and drive the turbine stages of the turbine section 156. In a further example, after passing through heat exchanger 214, a portion of the cooled exhaust gas may be sent along line 216 (eg, a return conduit) to the upstream compressor stage of compressor section 152, thereby improving the efficiency of compression with compressor section 152. . In this particular example, heat exchanger 214 can be configured for an interstage cooling unit of compressor section 152. In this manner, cooling the exhaust gases helps increase the operational efficiency of the SEGR gas turbine system 52 while helping to maintain the purity of the exhaust gases (eg, substantially free of oxidant and fuel).

4 is an operation method of the system 10 shown in FIGS. 1-3 A flow chart of a specific example of 220. In some embodiments, method 220 can be a computer-implemented method of accessing one or more instructions stored in memory 122 and executing instructions on processor 120 of controller 118 shown in FIG. For example, steps in method 220 may include instructions that may be executed by controller 118 of control system 100 described with reference to FIG.

Method 220 can initiate the SEGR gas turbine system of Figures 1-3 The startup mode of system 52 begins as indicated by block 222. For example, the startup mode may include stepping up the SEGR gas turbine system 52 to bring the hot ladder Degrees, vibrations, and gaps (eg, between rotating and securing components) remain within acceptable thresholds. For example, during startup mode 222, method 220 may begin supplying compressed oxidant 68 to combustor 160 and fuel nozzle 164 of combustor section 154 as indicated by block 224. In certain embodiments, the compressed oxidant can include compressed air, oxygen, oxygen-enriched air, oxygen-reduced air, an oxygen-nitrogen mixture, or any combination thereof. For example, oxidant 68 can be compressed by oxidant compression system 186 as shown in FIG. Method 220 may also begin to supply fuel to combustor 160 and fuel nozzle 164 during start mode 222 as indicated by block 226. During the startup mode 222, the method 220 may also begin to supply exhaust gas (when available) to the combustor 160 and the fuel nozzle 164 as indicated by block 228. For example, fuel nozzle 164 can produce one or more diffusion flames, premixed flames, or a combination of diffused and premixed flames. During startup mode 222, exhaust gas 60 being produced by gas turbine engine 156 may be insufficient or unstable in quantity and/or quality. Thus, during the startup mode, method 220 may supply exhaust gas 66 from one or more storage units (eg, storage tank 88), line 86, other SEGR gas turbine system 52, or other source of exhaust.

Method 220 can then burn compressed oxygen in combustor 160 A mixture of chemicals, fuel, and exhaust gases to produce hot combustion gases 172, as indicated by block 230. In particular, method 220 can be controlled by control system 100 of FIG. 2 to promote stoichiometric combustion of the mixture in combustor 160 of combustor section 154 (eg, stoichiometric diffusion combustion, premixed combustion, or both). However, during startup mode 222, it may be particularly difficult to maintain stoichiometric combustion of the mixture (and thus low levels of oxidant and unburned Fuel may be present in the hot combustion gases 172). As a result, as discussed in further detail below, in startup mode 222, hot combustion gases 172 may have a greater amount of residual oxidant 68 and/or fuel 70 than during steady state mode. For this reason, method 220 can execute one or more control commands during the startup mode to reduce or eliminate residual oxidant 68 and/or fuel 70 in hot combustion gases 172.

Method 220 then drives the turbine section with hot combustion gases 172 156, as indicated by block 232. For example, hot combustion gases 172 may drive one or more turbine stages 174 disposed within turbine section 156. Downstream of the turbine section 156, the method 220 can process the exhaust gas 60 from the last turbine stage 174 as indicated by block 234. For example, exhaust gas treatment 234 can include filtration, catalyst reaction of any residual oxidant 68 and/or fuel 70, chemical treatment, heat recovery with HRSG 56, and the like. The method 220 may also recirculate at least some of the exhaust gas 60 back to the compressor section 152 of the SEGR gas turbine system 52, as indicated by block 236. For example, exhaust gas recirculation 236 may include passage through an exhaust gas recirculation path 110 having an EG processing system 54 as shown in FIGS. 1-3.

Thus, the recirculated exhaust gas 66 can be in the compressor section 152 Compressed as indicated by block 238. For example, the SEGR gas turbine system 52 may successively compress the recirculated exhaust gas 66 in the compressor stage 158 of one or more compressor sections 152. Compressed exhaust gas 170 may then be provided to the combustor 160 and fuel nozzle 164 as indicated by block 228. Steps 230, 232, 234, 236, and 238 may then be repeated until method 220 eventually transitions to a steady state mode, as indicated by block 240. When changing After 240, the method 220 may proceed to steps 224 through 238, but may also begin to extract the exhaust gas 42 via the EG supply system 78, as indicated by block 242. For example, exhaust gas 42 may be extracted from one or more extraction points 76 along the compressor section 152, combustor section 154, and turbine section 156, as indicated in FIG. Thus, method 220 may supply extracted exhaust gas 42 from the EG supply system 78 to hydrocarbon generation system 12 as indicated by block 244. Hydrocarbon production system 12 may then inject exhaust gas 42 into soil 32 to enhance oil recovery, as indicated by block 246. For example, the extracted exhaust gas 42 can be used by the EOR system 112 of the EOR system 18 shown in Figures 1-3.

Figure 5 is an EG processing system 54 as shown in Figures 1-3 A block diagram of a specific example. In the illustrated embodiment, EG processing system 54 has a control system 100 coupled to a plurality of gas processing subsystems 300, valves 302, and sensors (S) 304 distributed along the exhaust gas recirculation path 110. For example, each subsystem 300 and its components 192 can include one or more valves 302 and sensors 304 disposed internal, upstream, and/or downstream of individual subsystems 300 or 192. Although not shown in FIG. 5, one or more valves 302 can be located at or near the locations of the various sensors 304 to provide greater flow control through the EG processing system 54. In operation, control system 100 may obtain sensor feedback 130 from the sensor 304 and provide control signals 306 to valve 302, subsystem 300, and component 192 for controlling EG processing system 54. Sensor feedback 130 may also include various sensors from components of SEGR gas turbine system 52, EG supply system 78, and other turbine-based service systems 14 Feed.

The gas processing subsystems 300 can each include one or more components To control temperature, pressure, gas composition, moisture content, particulate content, or any combination thereof. As shown in FIG. 5, gas treatment subsystem 300 includes a catalyst and heat recovery (CHR) system 308, a dehumidification system (MRS) 310, and a degranulation system (PRS) 312. The gas processing subsystem 300 also includes one or more booster blowers 314 to help increase the flow and pressure of the exhaust gases 42 along the exhaust gas recirculation path 110. Although CHR 308, booster blower 314, MRS 310, and PRS 312 are arranged in series in the illustrated embodiment, other embodiments may rearrange such components in other series and/or parallel configurations.

The CHR system 308 includes one or more catalyst units 316 and heat exchangers (HX) 318 that are arranged in series, in parallel, or in an integrated configuration. For example, CHR system 308 can include a series of catalyst units 316, such as catalyst units 320, 322, 324, 326, and 328. The CHR system 308 can also include a series of heat exchangers 318, such as heat exchangers 330 and 332. The catalyst units 316 can be the same or different from each other. For example, one or more of the catalyst units 316 can include an oxidation catalyst unit (OCU) 334 that uses oxidant fuel 336 to drive an oxidation reaction to convert carbon monoxide (CO) and unburned hydrocarbons (HCs) to carbon dioxide ( CO ₂ ) and water vapor. One or more of the catalyst units 316 can also drive a reduction reaction to convert nitrogen oxides (NO _x ) to carbon dioxide (CO ₂ ), nitrogen (N ₂ ), and water. In the illustrated embodiment, the catalyst unit 320 is disposed upstream of the heat exchanger 330, the catalyst unit 322 is integrated in the heat exchanger 330, and the catalyst unit 324 is disposed in the heat exchanger 330 and heat exchange. Between the devices 332, the catalyst unit 326 is integrated in the heat exchanger 332, and the catalyst unit 328 is disposed downstream of the heat exchanger 332. However, various specific examples of CHR system 308 may exclude or include any one or more of catalyst units 316, or catalyst unit 316 may be configured in other arrangements in CHR system 308.

Heat exchanger 318 is configured to divert heat from the exhaust gas 42 Move to one or more gases, liquids, or other fluids, such as water. In the illustrated embodiment, each heat exchanger 318 includes a heat recovery unit (HRU) 338 that is configured to recover heat from the exhaust gas 42 for use in one or more other applications. For example, the illustrated heat recovery units 338 each include a heat recovery steam generator (HRSG) 340 that is configured to recover heat from the exhaust gas 42 for use in generating steam 342. The steam 342 can be used in various processes in the EG processing system 54, the EOR system 18, or other locations within the turbine-based service system 14. In the illustrated embodiment, each HRSG 340 supplies steam 342 to one or more steam turbines (ST) 344 that can drive one or more loads 346 to generate mechanical power 348 and/or power 350. For example, the loads 346 can include a generator capable of producing electricity 350. While the CHR system 308 illustrates the catalyst cells 316 and heat exchangers 318 arranged in series, other specific examples of the CHR system 308 can arrange two or more catalyst units 316 and heat exchangers 318 in parallel. After the exhaust gas 42 passes through the CHR system 308, the exhaust gas 42 may then pass through the dehumidification system 310 and the degranulation system 312 after flowing through one or more booster blowers 314.

The dehumidification system (MRS) 310 can include one or more dehumidification Units (MRU) 352, such as MRUs 354 and 356. In the illustrated embodiment, the MRU 354 includes a heat exchanger 358 that can be configured to transfer heat from the exhaust gas 42 to other gases, liquids, or other fluids to cool the exhaust gas 42 for dehumidification. For example, heat exchanger 358 can include or be configured as a condenser 360 that functions to sufficiently cool exhaust gas 42 to condense moisture in exhaust gas 42 and to remove condensate from water 362. However, the MRU 354 can include various cooling units (eg, 2, 3, 4, or more condensers, chillers, etc.) to condense moisture from the exhaust gas 42 to produce water 362. The MRS 310 may also include other water removal techniques, such as a filtration unit. For example, the MRU 356 can include one or more dehumidification separators or filters 364, such as a water gas separator (WGS) 366, a watertight filter (WFIL) 368, and a combined filter (CFIL) 370, which can be The exhaust gas 42 captures and removes moisture to produce an output of the water 372. While MRS 310 illustrates MRU 354 upstream of MRU 356, other specific examples of MRS 310 may place MRU 356 upstream of MRU 354 or parallel to MRU 354. Further, the MRS 310 can include an additional dehumidification filter 364, a heat exchanger 358, or any other dehumidification assembly. After the exhaust gas 42 is removed by treatment with the MRS 310, the exhaust gas 42 can then pass through the degranulation system 312.

Degranulation system (PRS) 312 may include one or more degranulation sheets Meta (PRU) 374, which may be arranged in series, in parallel, or any combination thereof. For example, the PRS 312 can include PRUs 376 and PRUs 378 configured in a series arrangement. PRU 376 can include inertial separator 380, gravity separation The device 382, or any other type of separation unit, or any combination thereof, forces the particles 384 to separate from the flow of the exhaust gas 42. For example, the inertial separator 380 can include a centrifugal separator that uses centrifugal force to drive the flow of particulates 384 away from the exhaust gas 42. Similarly, gravity separator 382 can use gravity to drive particles 384 out of the flow of exhaust gas 42. The PRU 378 can include one or more degranulation filters 386, such as a first staging filter 388 and a second staging filter 390. Such grading filters 388 and 390 can include tapered filter media, such as membrane filters. However, the staged filters 388 and 390 can include a water impermeable filter (WFIL), a combined filter (CFIL), a membrane filter, or any combination thereof. As the exhaust gas 42 passes through the first and second staged filters 388 and 390, the filter 386 captures or removes particles 392 from the exhaust gas 42. While the PRS 312 is shown placing the PRU 376 upstream of the PRU 378, other specific examples may place the PRU 378 upstream of or parallel to the PRU 376. After the exhaust gas 42 is treated with the PRS 312, the exhaust gas 42 may then be recycled back to the SEGR gas turbine system 52 as indicated by arrow 110.

Along the exhaust gas recirculation path 110, the CHR system 308, the MRS 310, the PRS 312, and the booster blower 314 may be controlled by the control system 100 to first adjust the temperature, pressure, flow rate, moisture level, particulate level, and gas of the exhaust gas 42. The composition is returned to the SEGR gas turbine system 52. For example, the control system 100 may receive feedback from the various sensors of the sensor 130 along the path to the configuration of the exhaust gas recirculation 110,304 so as to provide oxygen, carbon monoxide, hydrogen, nitrogen oxides (NO _X), unburned hydrocarbons Feedback indication of emissions (eg, concentration levels) of the class (HCs), sulfur oxides (SO _X ), moisture, or any combination thereof. The control system 100 can adjust (e.g., increase, decrease, or maintain) the pressure, temperature, and temperature of the exhaust gas 66, oxidant 68, and fuel 70 that are fed to the SEGR gas turbine system 52 for combustion, as a result of the sensor feedback 130. , or flow rate. For example, control system 100 can adjust valve 302 along the exhaust gas recirculation path 110, inlet guide vanes within compressor section 152 of gas turbine engine 150, to exhaust system 396 as a function of sensor feedback 130. The bleed valve 394, or any combination thereof, adjusts the flow of exhaust gas 42 into the combustor section 154 of the gas turbine engine 150.

In the CHR system 308, the control system 100 can adjust the flow of the oxidant fuel 336 into the respective catalyst units 316 in response to the sensor feedback 130, thereby increasing or decreasing the oxidation reaction within each of the catalyst units 316 to change the recirculation back. The gas composition to the exhaust gas 42 of the SEGR gas turbine system 52. For example, the control system 100 may increase the oxidant flow of fuel 336 to increase the oxidation reaction in each of UCU 334, thereby reducing carbon monoxide (CO) and unburned hydrocarbons (HCs in) and increased levels of carbon dioxide (CO ₂₎ of the level. The control system 100 may also reduce the fuel oxidizer 336 flow into each of UCU 334, thereby reducing carbon dioxide (CO ₂₎ and increased levels of carbon monoxide (CO) and unburned hydrocarbons (HCs in) of levels. Control system 100 can also selectively increase or decrease the amount of exhaust gas flow through each catalyst unit 316, bypassing one or more catalyst units 316, or any combination thereof. Control system 100 can also selectively circulate, partially bypass, or completely bypass one or more heat exchangers 318, such as heat recovery unit 338. In this manner, control system 100 can increase or decrease the temperature of exhaust gas 42 while also increasing or decreasing the amount of steam generated to drive steam turbine 344.

In the MRS 310 and the PRS 312, the control system 100 can The sensor feedback 130 is responsive to ensure adequate removal of moisture and particulates. For example, control system 100 may control MRU 352 within MRS 310 to increase or decrease moisture removal from exhaust gas 42 in response to sensor feedback 130 indicating moisture content. In response to the sensor feedback 130 indicating the particulate content, the control system 100 can adjust the PRU 374 within the PRS 312 to increase or decrease the amount of particulate removal from the exhaust gas 42. These control actions by the control system 100 may each be based on feedback 130 from the EG processing system 54, the SEGR gas turbine system 52, or other locations within the turbine-based service system 14. In some embodiments, the control system 100 is configured to be in each subsystem and/or component, such as the CHR system 308, the MRS 310, the PRS 312, or any other component thereof (eg, the catalyst unit 316, heat) Within, upstream or downstream of exchanger 318, MRU 352, PRU 374, etc., along the exhaust gas recirculation path 110, the temperature, pressure, and/or flow rate of exhaust gas 42 are maintained within individual target ranges (eg, Within the target temperature range, target pressure range, and target flow rate range. Control system 100 can be configured to vary temperature, pressure, and during various control changes in SEGR gas turbine system 52, including changing the flow rate of oxidant 68, fuel 70, and diluent to fuel nozzle 164 and combustor 160. / or the flow rate remains within these target ranges.

Figure 6 is an illustration of extracting, processing, and delivering an exhaust stream 95 to Specific to system 420 of EG supply system 78 of various target systems 422 An illustration of an example. As discussed above, the EG supply system 78 includes an exhaust gas extraction system 80 and an EG processing system 82. Exhaust gas extraction system 80 receives exhaust gas 42 from one or more extraction points 76 along the SEGR gas turbine system 52, EG processing system 54, or other location within any turbine-based service system 14. The EG processing system 82 then processes the extracted exhaust gas 42 with a plurality of processing subsystems 424, such as compression system 426, dehumidification/dewatering system 428, degranulation/filtration system 430, gas separation system 432, and gas purification system 434.

The illustrated processing subsystems 424 can be configured in series, in parallel, or any combination thereof. The compression system 426 can include one or more rotary compressors, reciprocating compressors, or any combination thereof in one or more compression stages. The dehumidification/dewatering system 428 can include one or more heat exchangers, a heat recovery unit such as a heat recovery steam generator, a condenser, a water gas separator such as a centrifugal water gas separator, a filter, a desiccant, or other dewatering medium, or Any combination of them. Degranulation/filtration system 430 can include one or more inertial separators, gravity separators, filters, or any combination thereof. For example, the filter can include a membrane filter, a water impermeable filter, a combined filter, or any combination thereof. Gas separation system 432 can include one or more solvent-based separation systems that can include one or more absorbers, flash tanks, or any combination thereof. For example, gas separation system 432 can be configured to separate carbon dioxide (CO ₂ ) and/or nitrogen (N ₂ ) from the exhaust gas 42. In a further example, gas separation system 432 can include a CO ₂ /N ₂ separator and/or a carbon capture system. Gas purification system 432 may also include one or more solvent-based gas purifier, and can be further reduced from the gas separation gas separation system 432 (e.g., CO ₂ and / or N ₂₎ of the impurities. For example, any carbon dioxide (CO ₂₎ 434 may be separated further purified by the gas purification system, thereby increasing the separation of carbon dioxide (CO ₂₎ levels of purity. Similarly, the gas purification system 434 can be further purified and isolated nitrogen (N _2), thereby removing the separation of nitrogen (N ₂₎ of any impurity. In certain embodiments, the separated carbon dioxide and the separated nitrogen can have a purity level of at least about 70, 80, 90, 95, 96, 97, 98, 99 or greater volume percent purity. In some embodiments, the gas separation system 432 can generate a plurality of exhaust streams 95, such as a first stream 96, a second stream 97, and a third stream 98. For example, the first stream 96 may comprise CO ₂ rich stream 436, the second flow stream 97 can include intermediate concentrations of 438, and the third stream 98 may comprise 440 CO ₂ lean stream.

One or more of these exhaust streams 95 can then lead to one or more Secondary gas treatment system 442 and/or energy recovery system 444. For example, the first stream 96 can lead to the secondary gas processing system 446, the second stream 97 can lead to the secondary gas processing system 448, and the third stream 98 can lead to the secondary gas processing system 450. Similarly, the first stream 96 can lead to an energy recovery system 452, the second stream 97 can lead to an energy recovery system 454, and the third stream 98 can lead to an energy recovery system 456. The secondary gas treatment systems 442 can each include a compression system 458, a dehumidification/dewatering system 460, or any other suitable processing component. Likewise, compression system 458 can include one or more rotary compressors, reciprocating compressors, or any combination thereof, arranged in a series or parallel arrangement. Dehumidification/dewatering system 460 can include a water gas separator, a condenser, a filter, or any combination thereof to remove any moisture remaining in stream 96, 97, or 98 after compression by compression system 458. Similarly, streams 96, 97, and 98 may each share a secondary gas treatment system 442 by its own dedicated secondary gas treatment system 442, or two or more of such streams. After the secondary treatment in this system 442, the treated exhaust streams 96, 97, and 98 can then be passed to one or more target systems 422, such as hydrocarbon generation system 12, line 86, storage tank 88, and/or carbon. Solid storage system 90. In other words, any one or more of the individual streams 96, 97, and 98 can be used independently or collectively by one or more target systems 422.

In energy recovery system 444, streams 96, 97, and 98 are each Energy may be recovered in one or more turbines or expanders 462, which then drive one or more loads 464 to generate mechanical power 466 and/or power 468. For example, load 464 can include one or more generators to generate electrical power 468. Likewise, each stream 96, 97, and 98 can independently or collectively drive its own turbine or expander 462 in its dedicated energy recovery system 452, 454, or 456. This recovered energy can be used to drive other equipment throughout the turbine-based service system 14.

7 is a combustor section 154 of gas turbine engine 150 An illustration of a specific example. As shown, the combustor section 154 has a shroud 490 disposed about one or more combustors 160 to define a compressor discharge cavity 492 between the shroud 490 and the combustor 160. Each combustor 160 includes a head end portion 166 and a combustion portion 168. The combustion portion 168 can include a chamber 494, a first wall or gasket 496 disposed about the chamber 494, and a second wall or flow sleeve 498 disposed offset from the first wall 496. For example, the first and second walls 496 and 498 can generally be coaxial with each other to define a hollow circumferential space or flow passage 500 that leads from the combustion portion 168 to the head end portion 166. The second wall or flow sleeve 498 can include a plurality of channels or perforations 502 that allow the compressed exhaust gas 170 to enter the flow passage 500 from the compressor portion 152. Exhaust gas 170 then flows along passage 496 to head end portion 166 through passage 500, as indicated by arrow 504, to flow into exhaust chamber 170 to head end portion 166 and into chamber 494 (e.g., through one or more fuel nozzles 164). The liner 496 is cooled.

In some embodiments, the liner 496 can also include one or more channels or perforations 506 to enable a portion of the exhaust gas 170 to be injected directly into the chamber 494, as indicated by the arrow 508. For example, exhaust gas injection 508 can act as a diluent injection that can be configured to control temperature, pressure, flow rate, gas composition (eg, effluent levels), or any combination thereof, within chamber 494. In particular, exhaust gas injection 508 can help control the temperature within chamber 494 such that nitrogen oxide (NO _x ) emissions can be substantially reduced in the hot products of combustion. One or more additional diluents (such as nitrogen, steam, other inert gases) or additional exhaust gases may be injected through one or more diluent injectors 510, as indicated by arrow 512. At the same time, exhaust gas injection 508 and diluent injection 512 can be controlled to adjust the temperature of the hot combustion gases flowing through chamber 494, the concentration level of the emissions, or other characteristics.

In the head end portion 166, one or more fuel nozzles 164 Exhaust gas 170, oxidant 68, fuel 70, and one or more diluents 514 (eg, exhaust, steam, nitrogen, other inert gases, or any combination thereof) may be sent to chamber 494 for combustion. For example, each combustor 160 can include 1, 2, 3, 4, 5, 6, 7, 8, or more fuel nozzles 164, each configured as a diffusion fuel nozzle and/or a premixed fuel nozzle. E.g, Each fuel nozzle 164 can feed oxidant 68, fuel 70, diluent 514, and/or exhaust gas 170 into chamber 494 in a premixed or separate stream to produce a flame 516. The premixed flow of oxidant 68 and fuel 70 produces a premixed flame, while the separate flow of oxidant 68 and fuel 70 produces a diffusion flame.

Control system 100 is coupled to one or more fluid supply systems System 518 controls the pressure, temperature, flow rate, and/or mixture of oxidant 68, fuel 70, diluent 514, and/or exhaust gas 170. For example, the control system 100 can independently control the flow of oxidant 68, fuel 70, diluent 514, and/or exhaust gas 170 to control equivalence ratios, emissions levels (eg, carbon monoxide, nitrogen oxides, sulfur oxides, unburned, Hydrocarbons, hydrogen, and/or oxygen), power output, or any combination thereof. In operation, control system 100 can control fluid supply system 518 to increase the flow of oxidant 68 and fuel 70 while maintaining substantially stoichiometric combustion, or control system 100 can control fluid supply system 518 to reduce the flow of oxidant 68 and fuel 70 simultaneously Maintain substantial stoichiometric combustion. Control system 100 may perform an increase or decrease in the flow rate of each of such oxidant 68 and fuel 70 in incremental steps (eg, 1, 2, 3, 4, 5, or more steps), continuously, or any combination thereof. . Further, control system 100 can control fluid supply system 518 to increase or decrease the flow of oxidant 68 and fuel 70 to provide a rich fuel mixture of oxidant 68 and fuel 70, a lean fuel mixture, or any other mixture, into chamber 494, thereby The hot product or EGR of combustion 520 has a low oxygen concentration, a high oxygen concentration, or any other concentration of unburned hydrocarbons, carbon monoxide, nitrogen oxides, sulfur oxides, and the like of any other oxygen. In controlling the flow of oxidant 68 and fuel 70 Control system 100 can also control fluid supply system 518 to increase or decrease the flow of diluent 514 (eg, steam, exhaust, nitrogen, or any other inert gas) to help control the heat of combustion through chamber 494 toward turbine section 156. The temperature, pressure, flow rate, and/or gas composition (e.g., effluent level) of product 520.

Control system 100 can also control including EG extraction system 80 And the EG supply system 78 of the EG processing system 82. For example, control system 100 can selectively open or close one or more valves 522 disposed along extraction line 524 between the combustor section 154 and EG extraction system 80. Control system 100 can selectively open or close such valves 522 to increase or decrease the flow of exhaust gas 42 to EG extraction system 80, while also selectively extracting exhaust gases from different locations such that different temperatures and/or pressures are to be applied. The exhaust gas is sent to the EG extraction system 80. Control system 100 can also control one or more valves 526 disposed along line 528 leading to exhaust system 530. For example, control system 100 can selectively open valve 526 to vent a portion of the exhaust gases into the atmosphere through exhaust system 530, thereby reducing the pressure in EG supply system 78.

As discussed above, each burner in the combustor section 154 160 may include one or more fuel nozzles 164 that may be configured as premixed fuel nozzles and/or diffusion fuel nozzles. For example, Figures 8, 9, and 10 illustrate specific examples of fuel nozzles 164 that are configured to operate to produce premixed fuel nozzles 550 of premixed flames 516, 552, while Figures 11-16 illustrate configurations that are operable to produce a diffusion flame. A specific example of a fuel nozzle 164 of a diffusion fuel nozzle 554 of 516, 556. These fuel nozzles 550 and 554 can be single They are used alone or in any combination with each other in each combustor 160, as discussed in further detail below with respect to FIG. For example, each combustor 160 may include only any combination of premixed fuel nozzles 550, only diffused fuel nozzles 554, or premixed fuel nozzles 550 and diffused fuel nozzles 554.

The premixed fuel nozzle 550 can have various configurations to premix the oxidant 68 and the fuel 70 completely or partially and at the same time optionally premix one or more diluents 514 such as exhaust gas 170, steam, nitrogen, or any other suitable inert gas. FIG. 8 is an illustration of a specific example of a premixed fuel nozzle 550 having a mixing portion 558 coupled to an injection portion 560. The mixing portion 558 includes at least one mixing chamber 562 surrounded by at least one outer casing 564, and the injection portion 560 includes at least one injection passage 566 surrounded by at least one conduit 568. For example, the outer casing 564 of the mixing portion 558 can include one or more conduits, injection holes, scroll vanes, flow disruptors, or other structures to promote mixing between the oxidant 68 and the fuel 70. Mixing portion 558 can also receive a stream of one or more diluents 514, such as exhaust gas 170, steam, nitrogen, or another inert gas, such that diluent 514 is mixed with oxidant 68 and fuel 70. Once oxidant 68 and fuel 70 Intimately mixed within the mixing chamber 562, the premixed fuel nozzle 550 sends the fuel oxidant mixture through the injection passage 566 to at least one injection outlet 570. The oxidant 68 and fuel 70 (and optionally one or more diluents 514) can then be The effluent mixture is ignited to produce a premixed flame 552. In some embodiments, the control system 100 can selectively control the fluid supply system 518 to increase or decrease the oxidant 68 and fuel 70 (and optionally one or more diluents 514). The flow rate, thereby adjusting the equivalence ratio, the level of emissions produced by the premixed flame 552, the power output of the gas turbine engine 150, or any combination thereof. In some embodiments, the premixed fuel nozzle 550 is shown as not premixed. Any diluent and oxidant 68 and fuel 70, but may provide one or more diluents (eg, exhaust, steam, nitrogen, after the combustion point and/or downstream of the premixed flame 552) Another inert gas). In this manner, the flow rates of oxidant 68 and fuel 70 can be independently controlled to more precisely control the fuel/oxidant ratio to help achieve stoichiometric combustion to improve flame stability while controlling temperature and emissions (eg, , NO _X emissions) also downstream of the diluent used.

Figure 9 is a premix of a multi-stage configuration with a hybrid portion 558 An illustration of a specific example of a fuel nozzle 550. As shown, the mixing portion 558 includes first and second mixing chambers 580 and 582 that are bounded by first and second outer casing portions 584 and 586 of the outer casing 564. The first and second mixing chambers 580 and 582 are illustrated in a series configuration, although other embodiments of the mixing portion 558 can arrange the first and second mixing chambers 580 and 582 in parallel. Mixing portion 558 can also include additional mixing chambers in combination with first and second mixing chambers 580 and 582. For example, mixing portion 558 can include 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or more mixing chambers in a series configuration, a parallel configuration, or a combination thereof. Each mixing chamber 580 and 582 can include one or more mixing devices, such as scroll blades, flow disruptors, tortuous paths, channels of incremental and decreasing diameters, or any combination thereof. In operation, mixing portion 558 receives one or more streams of oxidant 68, fuel 70, and one or more diluents 514 from the fluid supply system 518. Likewise, diluent 514 can include exhaust gas 170, steam, nitrogen, or One or more other inert gases. Each mixing chamber 580 and 582 can receive and mix two or more different fluids from the fluid supply system 518. For example, the first mixing chamber 580 can receive and mix one or more streams of oxidant 68 and fuel 70, while the second mixing chamber 582 can receive and mix one or more of oxidant 68 and diluent 514 or fuel 70 and diluent 514. Stream. In other words, the first and second mixing chambers 580 and 582 can receive and mix the same fluid stream from two or more of the fluid supply systems 518, or two or more different fluid streams. In this manner, the first and second mixing chambers 580 and 582 can sequentially mix the various fluids from the fluid supply system 518 and then direct the mixture to the injection channel 566 for delivery to the chamber 494 of the combustor 160. When a mixture of oxidant 68, fuel 70, and one or more diluents 514 flows through injection port 570 of injection passage 566, the mixture ignites and forms a premixed flame 552. Likewise, control system 100 can selectively control fluid supply system 518 to increase, decrease, or maintain flow of oxidant 68, fuel 70, and one or more diluents 514 to adjust the equivalence ratio of gas turbine engine 150, Emission levels, power output, or any combination thereof.

Figure 10 is a hierarchical mixing section with a series of vortex segments 592 An illustration of a specific example of a premixed fuel nozzle 550 of subsection 558 having a parallel mixing section 590. As discussed above with reference to FIG. 9, parallel mixing section 590 includes first and second mixing chambers 580 and 582, wherein the first and second mixing chambers 580 and 582 are disposed in parallel with one another upstream of scroll section 592. The vortex section 592 includes an inner conduit or hub 594, a conduit 596 disposed about the inner conduit 594, and a plurality of inner conduits 594 and A swirling vane 598 extending radially between the conduits 596. Each scroll blade 598 can be angled or curved to force fluid flow to form a vortex in a circumferential direction 600 about the longitudinal axis 602 of the premixed fuel nozzle 550. The inner conduit 594 defines an inner passage 604, the outer conduit 596 defines an outer passage 606, and each of the swirl vanes 598 defines a radial passage 608. The one or more scroll vanes 598 also include a plurality of injection ports 610 that may be disposed directly on or upstream of the trailing edge of each of the scroll vanes 598.

In the illustrated embodiment, the fluid supply system 518 A stream of one or more oxidant 68 and diluent 514 is sent to the first mixing chamber 580 while one or more streams of fuel 70 and diluent 514 are also fed to the second mixing chamber 582. The first mixing chamber 580 substantially mixes the stream of oxidant 68 and diluent 514, and then sends the mixture into the outer passage 606 between the inner and outer conduits 594 and 596, as indicated by arrow 612. Mixture 614 of oxidant 68 and diluent 514 then flows to a plurality of swirl vanes 598 in scroll section 592, wherein swirl vanes 598 force mixture 614 to form a swirl about axis 602, as indicated by arrow 600.

At the same time, the second mixing chamber 582 will fuel 70 and diluent The premixed stream of 514 is sent into the inner passage 604 defined by the inner conduit 594, as indicated by arrow 616. Mixture 618 of fuel 70 and diluent 514 then flows longitudinally along the inner passage 604 and then radially into the plurality of scroll vanes 598 as indicated by arrow 620. Once the plurality of injection ports 610 are reached, the mixture 618 of fuel 70 and diluent 514 enters the outer passage 606 through the injection port 610, as indicated by arrow 622. Two mixtures (i.e., premixed oxidant and diluent stream 614 and premixed fuel and diluent stream 622) Further mixing is then performed within the injection channel 566 as indicated by arrow 624. Mixture 624 of oxidant 68, fuel 70, and diluent 514 then exits premixed fuel nozzle 550 through injection outlet 570 and is subsequently ignited to form premixed flame 552. Likewise, control system 100 can selectively control fluid supply system 518 to independently control the flow of oxidant 68, fuel 70, and diluent 514 to increase, decrease, or maintain the equivalence ratio, emissions level of gas turbine engine 150. , power output, or any combination thereof.

11 is a diagram of a specific example of a diffusion fuel nozzle 554. It is shown with a plurality of individual channels 640 for feeding oxidant 68 and fuel 70 into chamber 494 of combustor 160. The independent channel 640 can include a plurality of concentric annular channels, a central channel surrounded by a plurality of peripheral channels, or any combination thereof. In the illustrated embodiment, the independent passage 640 includes one or more fuel passages 642 and one or more oxidant passages 644. For example, the illustrated fuel passage 642 is a central fuel passage surrounded by an inner conduit 646 and the one or more oxidant passages 644 are external oxidant passages disposed between the inner conduit 646 and the outer conduit or structure 648. In a further example, the oxidant passage 644 can include an annular oxidant passage or a plurality of separate oxidant passages disposed about the fuel passage 642 between the inner and outer conduits 646 and 648. In these specific examples, the oxidant and fuel passages 642 and 644 can be isolated from each other along the entire length of the diffusion fuel nozzle 554. The inner and outer conduits 646 and 648 can act as a dividing wall that maintains separation between the oxidant 68 and the fuel 70. Fuel passage 642 terminates at fuel outlet 650 and one or more oxidant passages 644 terminate at one or more oxidant outlets 652. These fuel and oxidant outlets 650 and 652 can be diffused along The common or downstream end 654 of the fuel nozzle 554 is configured to retard mixing of the oxidant 68 and the fuel 70 until after injection from the fuel nozzle 554 into the chamber 494 of the combustor 160.

As the oxidant 68 and fuel 70 mix or diffuse into each other in chamber 494, a diffusion flame 556 as shown by profile or boundary 656 is formed. Profile 656 can represent a diffusion wall or flame wall in which oxidant 68 and fuel 70 are mixed and combusted in a substantially stoichiometric manner (eg, substantially stoichiometric combustion). In other words, the contour or boundary 656 can represent a stable flame wall of the diffusion flame 556, wherein the equivalence ratio is between about 1.0 or between about 0.95 and 1.05. Similar to the premixed fuel nozzles 550 discussed above with respect to FIGS. 8-10, the diffusion fuel nozzles 554 can control the system 100 control to vary the equivalence ratio of the gas turbine engine 150, exhaust emissions, power output, or any combination thereof. For example, the illustrated control system 100 selectively controls the fluid supply system 518 to increase, decrease, or maintain the flow of oxidant 68 and fuel 70 in response to sensor feedback 130.

12 is an illustration of a specific example of a diffusion fuel nozzle 554 having a plurality of independent channels 670 and an injection portion 672 and a mixing portion 674. Mixing portion 674 can include one or more inner mixing chambers 676 and one or more outer mixing chambers 678. For example, the internal mixing chamber 676 can be a fuel/diluent mixing chamber configured to mix one or more streams of fuel 70 and diluent 514. The outer mixing chamber 676 can include one or more oxidant/diluent mixing chambers configured to mix one or more streams of oxidant 68 and diluent 514. Each of the mixing chambers may include a peripheral structure such as a housing or an outer conduit. For example, the mixing chamber 676 can be surrounded by an inner or inner casing 680, while mixing The housing 678 can be surrounded by an outer conduit or housing 682. In some embodiments, the mixing chamber 678 can be enclosed between the inner and outer conduits 680 and 682.

Similarly, the injection portion 672 includes one or more fuel-thin Release channel 684 and one or more oxidant-diluent channels 686. Each fuel-diluent channel 684 is fluidly coupled to one or more mixing chambers 678, and each oxidant-diluent channel 686 is fluidly coupled to one or more mixing chambers 678. The fuel-diluent channel 684 can be surrounded by an inner conduit 688, and one or more oxidant-diluent channels 686 can be surrounded by an outer conduit 690. For example, the illustrated fuel-diluent channel 684 can be a central fuel-diluent channel 684 that is surrounded by one or more external oxidant-diluent channels 686. For example, the inner and outer conduits 688 and 690 can be concentric annular conduits that define channels 684 and 686 in a coaxial or concentric annular arrangement. However, the fuel-diluent passage 684 can represent a single central passage or a plurality of separate passages disposed within the inner conduit 688. Likewise, the oxidant-diluent passage 686 can represent a single annular passage or a plurality of separate passages spaced apart from each other around the fuel dilution passage 684, with the remainder being isolated from each other by the inner and outer conduits 688 and 690. In certain embodiments, inner conduits 680 and 688 form a single continuous inner conduit, and outer conduits 682 and 690 form a single continuous outer conduit.

In operation, control system 100 selectively controls fluid The supply system 518 is configured to increase, decrease, or maintain the flow of fuel 70 and diluent 514 into the mixing chamber 676, which mixes the fuel 70 and diluent 514 before the mixture passes into the fuel-diluent passage 684. Similarly, control system 100 selectively controls fluid supply system 518 to increase, decrease, Or maintaining a flow of oxidant 68 and diluent 514 into one or more mixing chambers 678 that mix oxidant 68 and diluent 514 before the mixture is delivered into one or more oxidant-diluent channels 686. The diffusion fuel nozzle 554 then separately flows the fuel-diluent mixture 698 along the passage 684 to the outlet 692 and simultaneously flows the oxidant-diluent mixture 700 along the passage 686 to the one or more outlets 694. Similar to the embodiment of FIG. 11, outlets 692 and 694 can be aligned along a common or downstream end 696 of diffusion fuel nozzle 554 to maintain oxidant-diluent mixture 700 in passage 686 and fuel-dilution in passage 684. Isolation between the agent mixture 698. This isolation delays mixing between the oxidant 68 and the fuel 70 until downstream of the common plane 696.

When fuel-diluent mixture 698 and oxidant-diluent are mixed As the composition 700 flows from the diffusion fuel nozzle 554 into the chamber 494 of the combustor 160, the mixtures 698 and 700 generally diffuse and combust with each other along a contour or boundary 702 of the diffusing or flame wall that may define the diffusion flame 556. Likewise, control system 100 can selectively control fluid supply system 518 to independently control the flow of oxidant 68, fuel 70, and diluent 514 to each of mixing chambers 676 and 678 to control mixing within mixing chambers 676 and 678. At the same time, the diffusion and combustion in the chamber 494 of the burner 160 is also controlled. For example, control system 100 can selectively control fluid supply system 518 to adjust the ratio of oxidant 68 to fuel 70, the ratio of diluent 514 to combined flow of oxidant 68 and fuel 70, and the oxidant 68 relative to one or more mixtures. The ratio of diluent 514 in each of chamber 678 and corresponding passage 686, and fuel 70 relative to one or more mixing chambers 676 and corresponding passages The ratio of diluent 514 in each of the lanes 684. Accordingly, control system 100 can adjust each of these ratios, flow rates, temperatures, and fluid compositions (eg, the composition of oxidant 68, fuel 70, and diluent 514) to adjust the equivalence ratio of the gas turbine engine 150, exhaust. Emissions, and power output.

FIG. 13 is a diagram of a specific example of the diffusion fuel nozzle 554. Shown, it illustrates a plurality of independent channels 720. Channel 640 is shown to include a fluid A channel 722, one or more fluid B channels 724, and one or more fluid C channels 726. The fluid A channel 722 can be separated or isolated from the one or more fluid B channels 724 by conduits or structures 728 that can be separated from the one or more fluid C channels 726 by conduits or structures 730, The one or more fluid C-channels 726 can be surrounded or supported by an outer conduit or structure 732.

For example, as shown in Figure 14, fluid channels 722, 724 And 726 can be configured in a concentric arrangement wherein the conduit 728 surrounds a fluid A channel 722 that is a central fluid channel, the fluid B channel 724 is disposed between the conduits 728 and 730, and the fluid C channel 726 is disposed at the conduits 730 and 732. between. Likewise, conduits 728, 730, and 732 can be configured in a concentric arrangement such that fluid B channel 724 and fluid C channel 726 each represent a continuous annular passage.

However, the diffusion fuel nozzles 554 can arrange the channels 722, 724, and 726 in other arrangements, such as the individual channels shown in FIG. In the embodiment of Figure 15, fluid A channel 722 represents a central fluid channel, while fluid B channel 724 and fluid C channel 726 represents a plurality of fueling A separate channel within the nozzle 554 that is spaced apart from each other. For example, fluid B channel 724 can include 2, 3, 4, 5, 6, 7, 8, or more separate fluid channels spaced apart from one another along central fluid A channel 722. Likewise, fluid C-channel 726 can include a plurality of separate channels that are spaced apart from each other along the circumference of fluid B-channel 724. For example, fluid B channels 724 can be arranged in a first loop or circular pattern of channels 724, while fluid C channels 726 can be arranged in a second loop or circular pattern of channels 726.

In any of these configurations, the diffusion fuel nozzle of Figure 13 The 554 is configured to flow fluid A 734 through fluid A channel 722, fluid B 736 through one or more fluid B channels 724, and fluid C 738 through one or more fluid C channels 726, respectively. These fluids 734, 736, and 738 can each include one or more fluids, such as oxidant 68, fuel 70, and diluent 514. However, fluids 734, 736, and 738 may not mix any oxidant 68 and fuel 70 within diffusion fuel nozzle 554, thereby delaying mixing between oxidant 68 and fuel 70 until fluid is injected into burner 160 from channels 740, 742, and 744. Room 494. Likewise, such channels 740, 742, and 744 can be disposed along a common or downstream end 746 of the diffusion fuel nozzle 554. The various fluids are then mixed and combusted to form a diffusion flame 556, as discussed above. Table 2 below illustrates some possible non-limiting examples of fluids A, B, and C that can be used with the diffusion fuel nozzles 554 of Figures 13-15.

As indicated above, the diffusion fuel nozzle 554 can be various combinations Fluid (eg, oxidant 68, fuel 70, and diluent 514) flows through passages 722, 724, and 726 to create a diffusion flame 556. Likewise, oxidant 68 can include oxygen, ambient air, oxygen-enriched air, oxygen-reduced air, a mixture of nitrogen and oxygen, or any combination thereof. Fuel 70 may comprise a liquid fuel and/or a gaseous fuel, such as natural gas, syngas, or any other fuel described herein. Diluent 514 can include exhaust gas 170, steam, nitrogen, or another inert gas, or any combination thereof. While Table 2 describes some possible examples of fluids, any combination of fluids can be used with the diffusion fuel nozzles 554 of Figures 13-15. Moreover, while the specific example described does not mix any fuel 70 and oxidant 68 within the diffusion fuel nozzle 554, other embodiments may be small (eg, less than 1, 2, 3, 4, 5, 6, 7, 8) 9, 9, or 10 volume percent of the oxidant 68 mixes the fuel 70, or mixes a small amount (eg, less than 1, 2, 3, 4, 5, 6, 7, 8, 9, or 10 volume percent) of the fuel 70 Oxidizer 68.

Figure 16 is a diffusion fuel disposed within a combustor 160 An illustration of a specific example of a combustor section 154 of one of the nozzles 554. Similar to the diffusion fuel nozzle 554 shown in Figures 13-15, the diffusion fuel nozzle 554 of Figure 16 includes a fluid A channel 724 surrounded by a conduit 728, a fluid B channel 724 surrounded by a conduit 730, surrounded by a conduit 732. Fluid C channel 726, and fluid D channel 760 surrounded by outer conduit or structure 762. Fluid D channel 760 is configured to receive fluid D 764 from fluid supply system 518 and to deliver fluid D 764 to chamber 494 through one or more outlets 766. Channels 722, 724, 726, and 760 can have individual outlets 740, 742, 744, and 766 disposed along a common or downstream end 746 of diffusion fuel nozzle 554 to isolate fluids 734, 736, 738, and 764. Until the fluid reaches chamber 494. In this manner, the diffusion fuel nozzle 554 promotes the formation of the diffusion flame 556. Each fluid 734, 736, 738, and 764 can include an oxidant 68, a fuel 70, and one or more diluents 514, such as exhaust gas 170, steam, nitrogen, and/or one or more other inert gases. However, fluid passages 722, 724, 726, and 760 may not mix any oxidant 68 and fuel 70 within diffusion fuel nozzle 554, thereby promoting isolation of oxidant 68 from fuel 70 until fluid reaches chamber 494. Oxidant 68 and fuel 70 may flow through separate fluid passages 722, 724, 726, and 760, separately or partially premixed with one or more diluents 514. Similar to the previous specific example, control system 100 can selectively control fluid supply system 518 to increase, decrease, or maintain flow of fluids 734, 736, 738, and 764 to adjust the fluid in gas turbine engine 150. Fluid flow ratio, equivalence ratio, emission level, power Output, or any combination thereof.

The burner 160 shown in Figure 16 is also included along the burner The diluent portion 168 of the 160 is configured to inject the diluent into the system 770 such that one or more diluents (eg, exhaust gas 170, steam, nitrogen, or other inert gas) can be injected into the chamber 494 to control the combustion formed by the diffusion flame 556. Temperature, pressure, flow rate, gas composition (e.g., effluent level) of the thermal product of 772, or any combination thereof. For example, the diluent injection system 770 can include a bore disposed in the first wall or bore 506 of the liner 496, and a plurality of diluent injectors 510 extending through the first and second walls 496 and 498 to the chamber 494 of the combustor 160. . In operation, the channels or perforations 506 can be configured to inject fluid E 774, such as exhaust gas 170, as indicated by arrow 508. Diluent injector 510 can be configured to inject fluid F 776 and/or fluid G 778 into chamber 494 as indicated by arrow 512. For example, fluid F 776 and fluid G 778 can include additional exhaust gas 170, steam, nitrogen, one or more other inert gases, or any combination thereof. The implant diluents 508 and 512 can be configured to control the temperature, pressure, flow rate, gas composition (e.g., effluent level) of the combusted thermal product 772 produced from the diffusion flame 556, or any combination thereof. In certain embodiments, the control system 100 can selectively control the fluid supply system 518 to increase, decrease, or maintain flow of various fluids 734, 736, 738, 764, 774, 776, and 778 to control the oxidant 68. The ratio to fuel 70, the ratio of one or more diluents 514 to oxidant 68 and fuel 70, or any combination thereof. Thus, the control adjustment of such fluids can change the equivalence ratio, emissions level, and power output of the gas turbine engine 150. Table 3 below shows some Possible non-limiting examples of fluids A, B, C, D, E, F, and G used with diffusion fuel nozzle 554 and burner 160 of FIG.

As shown above, the diffusion fuel nozzle 554 and the burner 160 Various combinations of fluids (eg, oxidant 68, fuel 70, and diluent 514) may be flowed through passages 722, 724, 726, and 760, channels 506, and diluent injector 510 to create a diffusion flame 556. Similarly, oxidant 68 can include oxygen, ambient air, oxygen-enriched air, oxygen depletion a mixture of gas, nitrogen and oxygen, or any combination thereof. Fuel 70 may include liquid fuels and/or gaseous fuels such as natural gas, syngas, or any of the other fuels disclosed herein. Diluent 514 can include exhaust gas 170, steam, nitrogen, or another inert gas, or any combination thereof. While Table 3 describes some possible examples of fluids, any combination of fluids can be used with the diffusion fuel nozzles 554 and burners 160 of FIG. Moreover, while the specific example described does not mix any fuel 70 and oxidant 68 within the diffusion fuel nozzle 554, other embodiments may be small (eg, less than 1, 2, 3, 4, 5, 6, 7, 8) 9, 9, or 10 volume percent of the oxidant 68 mixes the fuel 70, or mixes a small amount (eg, less than 1, 2, 3, 4, 5, 6, 7, 8, 9, or 10 volume percent) of the fuel 70 Oxidizer 68.

Figure 17 is a burner taken along line 17-17 of Figure 7 A cross-sectional schematic view of 160 further illustrates the multiple nozzle arrangement of fuel nozzle 164 and the multiple injector arrangement of diluent injector 510. The illustrated fuel nozzle 164 includes a fuel nozzle A 790, a fuel nozzle B 792, a fuel nozzle C 794, a fuel nozzle D 796, a fuel nozzle E 798, a fuel nozzle F 800, and a fuel nozzle G 802. In the illustrated embodiment, the nozzle 790 is a central fuel nozzle that is surrounded by the remaining fuel nozzles 792, 794, 796, 798, 800, and 802 as outer or peripheral fuel nozzles. While the specific examples illustrated include a single central fuel nozzle 164 and six outer fuel nozzles 164, other specific examples may include any number of central and outer fuel nozzles. The illustrated fuel nozzle 164 may include one or more premixed fuel nozzles 550 and/or diffusion fuel sprays as shown and described with respect to Figures 8-16. Mouth 554. For example, all of the fuel nozzles 164 may be configured as premixed fuel nozzles 550, all of the fuel nozzles 164 may be configured as diffusion fuel nozzles 554, or the fuel nozzles 164 may include one or more of premixed fuel nozzles 550 and diffusion fuel nozzles 554. . The fluid flow to the fuel nozzles 164 can be independently controlled for each fuel nozzle 164, or the fluid flow can be controlled by a group of fuel nozzles 164. For example, the central fuel nozzle 790 can be independently controlled by one or more groups of outer fuel nozzles 792, 794, 796, 798, 800, and 802. In a further example, one or more premixed fuel nozzles 550 can be independently controlled by one or more diffusion fuel nozzles 554. These different control schemes facilitate different modes of operation, effectively providing stoichiometric combustion and reducing emissions from exhaust gases 42.

As further illustrated in FIG. 17, the fuel nozzle 164 The diluent injector 510 can be coupled to the fluid supply system 518 through a plurality of fluid supply circuits 810, such as one or more diluent supply circuits 812 and one or more fuel nozzle supply circuits 814. For example, the diluent supply circuit 812 can include 1, 2, 3, 4, 5, 6, 7, 8, or more separate diluent supply circuits 812 to enable the diluent injector 510 to have multiple diluent injection modes. . Similarly, the fuel nozzle supply circuit 814 can include 1, 2, 3, 4, 5, 6, 7, 8, or more independent fuel nozzle supply circuits 814 to enable the fuel nozzles 164 to have multiple fluid supply modes. For example, fuel nozzle supply circuit 814 can include a first nozzle circuit 816, a second nozzle circuit 818, and a third nozzle circuit 820. These fuel nozzle supply circuits 814 (eg, 816, 818, and 820) may each include one or more fuel lines, oxidant lines, and/or diluent lines (eg, For example, an exhaust line, a steam line, a nitrogen line, and/or other inert gas lines) are fluidly coupled to at least one fuel nozzle 164. In the illustrated embodiment, the first nozzle circuit 816 is coupled to a first set of fuel nozzles 164 (eg, central fuel nozzles 790) and the second nozzle circuit 818 is coupled to a second set of fuel nozzles 164 (eg, The outer fuel nozzles 794, 798, and 802), and the third nozzle circuit 820 are coupled to the third set of fuel nozzles 164 (eg, outer fuel nozzles 792, 796, and 800). In some embodiments, each set of fuel nozzles 164 connected to one of the nozzle supply circuits 814 can be all diffusion fuel nozzles, all premixed fuel nozzles, or any combination of diffusion fuel nozzles and premixed fuel nozzles. However, any number or configuration of fuel nozzles 164 may be coupled to each fuel nozzle supply circuit 814, and any number of nozzle supply circuits 814 may be coupled to fuel nozzles 164. Likewise, fuel nozzle supply circuit 814 is coupled to fluid supply system 518, which may include valves, flow regulators, and other flow controls to control flow rate and pressure to fuel nozzles 164.

Thus, the fluid supply system 518 is connected to the control system 100, which can use controller 118 to receive sensor feedback 130 and provide control signal 306 to fluid supply system 518 to control the operation of loops 812 and 814. In the illustrated embodiment, controller 118 of system 100 can store and execute stoichiometric control mode 822 and non-stoichiometric control mode 824 (eg, computer instructions or code associated therewith), which can further include lean fuel control Mode 826 and rich fuel control mode 828. The controller 118 of the system 100 can also store and execute including the first stream The fluid circuit control 830 of the body loop control 832, the second fluid circuit control 834, and the third fluid circuit control 836 (eg, computer instructions or code associated therewith). For example, the first fluid circuit control 832 can be configured to control various flow rates to the first nozzle circuit 816 (eg, oxidant 68, fuel 70, and/or diluent 514), and the second fluid circuit control 834 can be configured to control Various flow rates to the second nozzle circuit 818 (eg, oxidant 68, fuel 70, and/or diluent 514), and third fluid circuit control 836 can be configured to control various flow rates to the third nozzle circuit 820 (eg, Oxidizer 68, fuel 70, and/or diluent 514).

In some embodiments, the stoichiometric control mode 822 Is configured to vary the flow rate of the at least one fuel 70 and the at least one oxidant 68 and provide a substantial stoichiometric ratio of the fuel 70 to the oxidant 68, while the non-stoichiometric control mode 824 is configured to vary the flow rate, and A non-stoichiometric ratio of fuel 70 to oxidant 68 is provided. For example, stoichiometric control mode 822 can be configured to provide a substantially stoichiometric ratio of about 1.0, or an equivalence ratio between about 0.95 and about 1.05. Conversely, the non-stoichiometric control mode 824 can be configured to provide a non-stoichiometric ratio of less than about 0.95 or greater than about 1.05. In some specific examples, the control system 100 can be configured to change the equal flow rates from a first set of flow rates to a second set of flow rates, wherein the first and second flow rates are different from one another (eg, One of them is larger or smaller than the other). The change in control of the flow rates may also include a transition between the stoichiometric control mode 822 and the non-stoichiometric control mode 824, or the control change of the flow rates may include maintaining a substantial stoichiometric ratio. Control changes to such flow rates may also include SEGR gas The power output (or load) of the turbine system 52 changes from a first power output (or first load) to a second power output (or second load), wherein the first and second power outputs (eg, loads) are each other Different (for example, one of them is smaller or larger than the other). For example, a change in control of the power output may include a change in control of the turbine load, for example, from a nominal or normal load (eg, 100 percent) to a partial load (eg, 50 percent). The controlled change in the flow rates may also include maintaining emissions in the exhaust gas within one or more target emissions ranges, wherein the emissions may include carbon monoxide, oxygen, nitrogen oxides, sulfur oxides, unburned hydrocarbons , hydrogen, or any combination thereof. In some embodiments, the one or more target emission ranges include an oxygen range of less than about 50 parts per million (ppmv) and/or a range of carbon monoxide of less than about 5000 ppmv. In other embodiments, the one or more target emission ranges comprise a range of oxygen of less than about 10 parts per million (ppmv) and/or a range of carbon monoxide of less than about 1000 ppmv.

In some specific examples, in the stoichiometric control mode Control system 100 of 822 is configured to maintain the substantially stoichiometric ratio while gradually reducing flow rates in multiple sets of flow rates (eg, oxidant 68 and fuel 70), gradually reducing the number of SEGR gas turbine systems 52 One of the power outputs (eg, full load, first partial load, second partial load, etc.) is one of the power outputs (eg, load), and the emissions in the exhaust are maintained within one or more target emissions ranges. Control system 100 can also be configured to transition from the stoichiometric control mode 822 to non-chemical after gradually reducing the flow rate, gradually reducing the power output, and maintaining emissions. Metered control mode 824. After transitioning from the stoichiometric control mode 822 to the non-stoichiometric control mode 824, the control system 100 can also be configured to operate with the rich fuel control mode or the lean fuel control mode of the non-stoichiometric control mode 824. Control system 100 can also be configured to maintain emissions in the exhaust gas within a target emission range of the first group (eg, when operating in stoichiometric control mode 822) and a target emission range of the second group (eg, when The stoichiometric control mode 824 operates when the target emission ranges of the first and second sets are different from each other. While the foregoing examples provide some control schemes for the SEGR gas turbine engine 52, it should be understood that any number of control schemes may be implemented by the control system 100 using a diffusion fuel nozzle, a premixed fuel nozzle, or any combination thereof.

Figure 18 shows exhaust gas recirculation (EGR) flow rate and gas turbine A plot of load 840 versus fuel/oxidant ratio 842 for SEGR gas turbine system 52 illustrates diffusion flame operability curve 844 and premixed flame operability curve 846. The EGR flow rate through the SEGR gas turbine system 52 is typically proportional to the load on the gas turbine engine 150, and thus the Y-axis 840 typically indicates both the EGR flow rate and the gas turbine load. Typically, the regions above and to the left of each of curves 844 and 846 represent unstable regions of each flame configuration of SEGR gas turbine system 52. It is worth noting that the diffusion flame operability curve 844 substantially exceeds the premixed flame operability curve 846, indicating that the SEGR gas turbine system 52 operating with diffusion combustion has significantly greater EGR flow rate and load range. As shown in FIG. 18, the diffusion flame operability curve 844 may correspond to a combustor 160 equipped with a diffusion fuel nozzle 554, wherein the exhaust gas (eg, diluent) is ignited Downstream of the diffusion fuel nozzle 554 after the burn point and/or downstream of the diffusion flame 556 generated by the nozzle 554. An example of such a diffusion combustion configuration is shown in FIG. In contrast, the premixed flame operability curve 846 can correspond to the combustor 160 equipped with the premixed fuel nozzle 550, wherein the oxidant 68, fuel 70, and diluent 514 (eg, exhaust gas) are before the combustion point ( That is, premixed upstream of the premixed flame 552). Similarly, the diffusion flame operability curve 844 indicates that the EGR flow rate through the SEGR gas turbine system 52 is much greater, also indicating that more carbon dioxide is produced for use in the target system 422. The SEGR gas turbine system 52 operating using the aforementioned diffusion combustion configuration may also have substantially reduced emissions of oxygen and carbon monoxide. These reductions in emissions may be due, at least in part, to the independent control of the flow of oxidant 68, fuel 70, and diluent 514 (e.g., exhaust). It is believed that various configurations of diffusion fuel nozzle 554 and diluent injection (eg, diluent injection system 770 of FIG. 16) can substantially increase the operational range of the gas turbine load, the amount of exhaust gas produced, and the exhaust gas 42 (eg, flow) The output of 95) is for use in a target system 422 (such as hydrocarbon generation system 12).

Additional information

For example, the following is provided as a further illustration of the present disclosure: Embodiment 1. A system comprising: a turbine combustor including a first diffusion fuel nozzle, wherein the first diffusion fuel nozzle is configured to generate diffusion a flame; a turbine driven by a combustion product from a diffusion flame in a turbine combustor; an exhaust gas compressor, wherein the exhaust gas a compressor is configured to compress exhaust gas from the turbine and along the exhaust gas recirculation path to the turbine combustor; and a control system configured to control at least one of a stoichiometric control mode and a non-stoichiometric control mode a flow rate of the oxidant and the at least one fuel to the turbine combustor, wherein the stoichiometric control mode is configured to vary the flow rate and provide a substantially stoichiometric ratio of the at least one fuel to the at least one oxidant, and the non-chemical The metered control mode is configured to vary the flow rates and provide a non-stoichiometric ratio of the at least one fuel to the at least one oxidant.

Specific Example 2. The system of Concrete Example 1, wherein the chemistry The metered control mode is configured to provide an equivalent stoichiometric ratio of about 1.0 to the substantially stoichiometric ratio.

Specific example 3. The system of any of the preceding specific examples, wherein The stoichiometric control mode is configured to provide the substantially stoichiometric ratio of the equivalence ratio between about 0.95 and about 1.05.

Specific example 4. The system of any of the preceding specific examples, wherein The non-stoichiometric control mode is configured to provide the non-stoichiometric ratio of an equivalence ratio of less than about 0.95 or greater than about 1.05.

Specific example 5. The system of any of the preceding specific examples, wherein The control system is configured to change the flow rate from the first set of flow rates to the second set of flow rates and to change the conversion between the stoichiometric control mode and the non-stoichiometric control mode.

Specific example 6. The system of any of the preceding specific examples, wherein The second set of flow rates is less than the first set of flow rates.

Specific example 7. The system of any of the preceding specific examples, wherein The second set of flow rates is greater than the first set of flow rates.

Specific example 8. The system of any of the preceding specific examples, wherein The control system in the stoichiometric control mode is configured to change the equal flow rates from the first set of flow rates to the second set of flow rates while maintaining the substantially stoichiometric ratio.

Specific example 9. The system of any of the preceding specific examples, wherein The second set of flow rates is less than the first set of flow rates.

Specific example 10. The system of any of the preceding specific examples, wherein The second set of flow rates is greater than the first set of flow rates.

Specific example 11. The system of any of the preceding specific examples, wherein The control system in the stoichiometric control mode is configured to change the power output of the turbine from the first power output to the first by changing the equal flow rate from the first set of flow rates to the second set of flow rates, respectively Two power outputs.

Embodiment 12. The system of any of the preceding specific examples, wherein The second set of flow rates is less than the first set of flow rates, and the second power output is less than the first power output.

Specific example 13. The system of any of the preceding specific examples, wherein The second set of flow rates is greater than the first set of flow rates, and the second power output is greater than the first power output.

Specific example 14. The system of any of the preceding specific examples, wherein The control system in the stoichiometric control mode is configured to maintain emissions in the exhaust gas within one or more target emissions ranges while changing the equal flow rates from the first set of flow rates to the second set of flow rates .

Embodiment 15. The system of any of the preceding specific examples, wherein The emissions comprise carbon monoxide, oxygen, nitrogen oxides, sulfur oxides, unburned hydrocarbons, hydrogen, or any combination thereof.

Specific example 16. The system of any of the preceding specific examples, wherein The one or more target emission ranges comprise a range of oxygen of less than about 50 parts per million (ppmv) and/or a range of carbon monoxide of less than about 5000 ppmv.

Specific example 17. The system of any of the preceding specific examples, wherein The one or more target emission ranges comprise a range of oxygen of less than about 10 parts per million (ppmv) and/or a range of carbon monoxide of less than about 1000 ppmv.

Embodiment 18. The system of any of the preceding specific examples, wherein The control system in the stoichiometric control mode is configured to gradually change the flow rate in the plurality of sets of flow rates while maintaining the substantially stoichiometric ratio.

Embodiment 19. The system of any of the preceding specific examples, wherein The plurality of sets of flow rates comprise flow rates of at least three sets.

Specific example 20. The system of any of the preceding specific examples, wherein The plurality of sets of flow rates comprise flow rates of at least four sets.

Specific example 21. The system of any of the preceding specific examples, wherein The control system in the stoichiometric control mode is configured to maintain the substantially stoichiometric ratio while simultaneously: gradually reducing the flow rate in the plurality of sets of flow rates; gradually reducing the plurality of power outputs of the turbine a power output; and maintaining emissions in the exhaust gas within one or more target emissions ranges.

Embodiment 22. The system of any preceding embodiment, wherein the emission comprises carbon monoxide, oxygen, nitrogen oxides, sulfur oxides, unburned Hydrocarbons, hydrogen, or any combination thereof.

Specific example 23. The system of any of the preceding specific examples, wherein The one or more target emission ranges comprise a range of oxygen of less than about 50 parts per million (ppmv) and/or a range of carbon monoxide of less than about 5000 ppmv.

Specific example 24. The system of any of the preceding specific examples, wherein The one or more target emission ranges comprise a range of oxygen of less than about 10 parts per million (ppmv) and/or a range of carbon monoxide of less than about 1000 ppmv.

Specific example 25. The system of any preceding specific example, wherein The control system is configured to transition from the stoichiometric control mode to the non-stoichiometric control mode after gradually reducing the flow rate, gradually reducing the power output, and maintaining emissions.

Specific example 26. The system of any preceding specific example, wherein After switching from the stoichiometric control mode to the non-stoichiometric control mode, the control system is configured to operate in a fuel rich control mode that is not in a stoichiometric control mode.

Specific example 27. The system of any preceding embodiment, wherein After switching from the stoichiometric control mode to the non-stoichiometric control mode, the control system is configured to operate in a lean fuel control mode of a non-stoichiometric control mode.

Specific example 28. The system of any preceding embodiment, wherein The control system is configured to maintain emissions in the exhaust gas within a target emission range of the first group when operating in a stoichiometric control mode, the control system The system is configured to maintain emissions in the exhaust gas within a target emission range of the second group when operating in a non-stoichiometric control mode, and the target emission ranges of the first and second groups are different from each other.

Specific example 29. The system of any preceding specific example, wherein The non-stoichiometric control mode includes a lean fuel control mode having a target emission range of oxygen emissions of at least about 1000 parts per million (ppmv).

Specific example 30. The system of any preceding specific example, wherein The non-stoichiometric control mode includes a lean fuel control mode with a target emission range of carbon monoxide emissions of less than about 100 parts per million (ppmv).

Specific example 31. The system of any preceding embodiment, wherein The non-stoichiometric control mode includes a lean fuel control mode having a target emission range of carbon monoxide emissions of less than about 20 parts per million (ppmv).

Specific example 32. The system of any preceding embodiment, wherein The non-stoichiometric control mode includes a lean fuel control mode having a target emission range of nitrogen oxide emissions of less than about 200 parts per million (ppmv).

Specific example 33. The system of any preceding embodiment, wherein The non-stoichiometric control mode includes a lean fuel control mode having a target emission range of nitrogen oxide emissions of less than about 100 parts per million (ppmv).

Specific example 34. The system of any preceding embodiment, wherein The control system is configured to: gradually change the flow rate in the plurality of sets of flow rates; gradually change one of the plurality of power outputs of the turbine due to a change in the flow rate; before changing the flow rate and Thereafter, the emissions in the exhaust gas are maintained within one or more target emission ranges; before and after the flow rate is changed, the temperature of the exhaust gases along the exhaust gas recirculation path is maintained within a target temperature range; and the flow is changed Before and after the rate, the pressure of the exhaust gas along the exhaust gas recirculation path is maintained within the target temperature range.

Specific example 35. The system of any preceding embodiment, wherein The control system is configured to maintain the temperature within the target temperature range along the exhaust gas recirculation path downstream of the at least one catalyst unit.

Specific example 36. The system of any preceding embodiment, wherein The control system is configured to adjust an operating rate of an exhaust gas extraction valve, an exhaust gas discharge valve, an exhaust gas compressor or an oxidant compressor, a position of an exhaust gas compressor inlet baffle, an exhaust gas compressor recirculation valve, or any combination thereof At least one of them maintains this pressure.

Specific example 37. The system of any preceding embodiment, wherein The turbine combustor includes a first set of fuel nozzles coupled to the first fluid supply circuit and a second set of fuel nozzles coupled to the second fluid supply circuit, the first diffusion nozzle being a portion of the first or second set of fuel nozzles And the second control system is configured to independently control fluid flow through the first and second fluid supply circuits.

Specific example 38. The system of any preceding embodiment, wherein The first set of fuel nozzles includes a single fuel nozzle, and the second set of fuel nozzles includes a plurality of fuel nozzles.

Specific example 39. The system of any preceding embodiment, wherein The first set of fuel nozzles includes a first plurality of fuel nozzles, and the second set of fuel nozzles includes a second plurality of fuel nozzles.

Specific example 40. The system of any preceding embodiment, wherein The turbine combustor includes a third set of fuel nozzles coupled to a third fluid supply circuit, and the control system is configured to independently control fluid flow through the first, second, and third fluid supply circuits.

Specific example 41. The system of any preceding specific example, wherein The control system is configured to independently change the fluid at different rates through the first and second fluid supply circuits.

Specific example 42. The system of any preceding embodiment, wherein The control system is configured to independently change the fluid at the same rate through the first and second fluid supply circuits.

Specific example 43. The system of any preceding embodiment, wherein The first set of fuel nozzles includes at least a first diffusion fuel nozzle, and the second set of fuel nozzles includes a second diffusion fuel nozzle.

Specific example 44. The system of any preceding embodiment, wherein The first set of fuel nozzles includes at least a first diffusion fuel nozzle, and the second set of fuel nozzles includes a first premixed fuel nozzle.

Concrete example 45. The system of any of the preceding specific examples, the package thereof A first catalyst unit disposed along the exhaust gas recirculation path.

Specific example 46. The system of any preceding embodiment, wherein The first catalyst unit is configured to control the concentration of oxygen, carbon monoxide, carbon dioxide, nitrogen oxides, unburned hydrocarbons, or any combination thereof in the exhaust gas Degree level.

Specific example 47. The system of any preceding specific example, wherein The first catalyst unit comprises an oxidation catalyst, a carbon monoxide reduction catalyst, a nitrogen oxide reduction catalyst, aluminum oxide, zirconium oxide, hafnium oxide, titanium oxide, platinum oxide, palladium oxide, cobalt oxide, or a mixed metal oxide. Or a combination thereof.

Specific example 48. The system of any preceding embodiment, wherein The first catalyst unit is configured to drive an oxidation reaction with the exhaust gas and the oxidant fuel.

Specific example 49. The system of any preceding embodiment, wherein The control system is configured to adjust the flow of oxidant fuel to control the oxidation reaction system.

Specific example 50. The system of any preceding embodiment, wherein The control system is configured to adjust the flow of oxidant fuel in response to sensor feedback, and the sensor feedback includes a gas composition indicative of oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons, or any combination thereof Feedback.

Specific example 51. The system of any of the foregoing specific examples, the package thereof A first heat recovery unit, a second heat recovery unit, or a combination thereof disposed along the exhaust gas recirculation path.

Specific example 52. The system of any of the foregoing specific examples, the package thereof A first catalyst unit, a second catalyst unit, or a combination thereof disposed along the exhaust gas recirculation path.

Specific example 53. The system of any preceding specific example, wherein The first or second catalyst unit is configured upstream, downstream, or integrated with the first or second heat recovery unit.

Concrete example 54. The system of any of the preceding specific examples, the package thereof A first heat recovery unit having a first heat recovery steam generator.

Specific example 55. The system of any of the preceding specific examples, the package thereof A first steam turbine coupled to the first heat recovery steam generator.

Specific example 56. The system of any of the preceding specific examples, the package thereof A second heat recovery unit having a second heat recovery steam generator, a first steam turbine coupled to the first heat recovery steam generator, and a second steam turbine coupled to the second heat recovery steam generator.

Concrete example 57. The system of any of the preceding specific examples, the package thereof A dehumidification system and/or a degranulation system disposed along the exhaust gas recirculation path.

Specific example 58. The system of any preceding embodiment, wherein The dehumidification system comprises a heat exchanger, a condenser, a water gas separator, a first filter, or any combination thereof, wherein the degranulation system comprises an inertial separator, a gravity separator, a second filter, or any combination thereof.

Specific example 59. The system of any of the foregoing specific examples, the package thereof A booster blower disposed along the exhaust gas recirculation path.

Specific Example 60. The system of any of the foregoing specific examples, the package thereof A heat recovery unit, a booster blower, a dehumidifying unit, and a degranulation unit disposed along the exhaust gas recirculation path.

Specific example 61. The system of any preceding embodiment, wherein The first diffusion fuel nozzle includes a first fuel passage and a first oxidant passage that are isolated from each other along the first diffusion fuel nozzle.

Specific example 62. The system of any preceding embodiment, wherein The first diffusion fuel nozzle includes a first diluent passage.

Specific example 63. The system of any preceding embodiment, wherein The first diluent passage is configured to flow a portion of the exhaust gas through the first diffusion fuel nozzle.

Specific example 64. The system of any preceding specific example, wherein The diluent passage is configured to flow a portion of the exhaust gas, steam, nitrogen, another inert gas, or a combination thereof through the first diffusion fuel nozzle.

Specific example 65. The system of any preceding embodiment, wherein The turbine combustor includes a diluent injection system disposed downstream of the first diffusion fuel nozzle.

Specific example 66. The system of any preceding specific example, wherein The diluent injection system is configured to inject a portion of the exhaust gas, steam, nitrogen, or another inert gas, or a combination thereof, into a chamber of a turbine combustor downstream of the first diffusion fuel nozzle.

Specific example 67. The system of any preceding embodiment, wherein The diluent injection system includes a plurality of cells in a liner of the turbine combustor, and the plurality of cells are configured to inject the portion of exhaust gas into the chamber of the turbine combustor.

Specific example 68. The system of any preceding embodiment, wherein The turbine combustor includes a first wall disposed about the chamber, a second wall disposed about the first wall, and an exhaust passage disposed between the first and second walls, wherein the diluent injection system A diluent injector comprising a plurality of first and second walls through the turbine combustor.

Specific example 69. The system of any preceding embodiment, wherein The plurality of diluent injectors are configured to inject a portion of the exhaust, steam, nitrogen, or another inert gas into the chamber of the turbine combustor.

Embodiment 70. The system of any preceding embodiment, comprising an exhaust gas extraction system configured to extract a portion of the exhaust gas.

Embodiment 71. The system of any preceding embodiment, comprising an exhaust gas treatment system configured to treat the portion of the exhaust.

The system of any preceding embodiment, wherein the exhaust gas treatment system comprises a gas separation system configured to separate a portion of the exhaust gas into a plurality of gas streams.

73. Specific examples of the system of any of the foregoing specific examples, wherein the carbon dioxide-rich stream comprises a plurality of gas (CO ₂₎ and the first flow-lean carbon dioxide (CO ₂₎ of the second stream.

The system of any preceding embodiment, wherein the exhaust treatment system comprises a gas compression system, a dehumidification system, a degranulation system, or a combination thereof configured to receive at least one of the first or second streams.

The system of any preceding embodiment, wherein the exhaust gas treatment system comprises a gas purification system configured to purify at least one of the plurality of gas streams.

Embodiment 76. The system of any preceding embodiment, comprising a target system configured to receive at least one of the plurality of streams, wherein the target system comprises a hydrocarbon generation system, an underground storage, a carbon storage system, a pipeline, Storage tank, or any combination thereof.

Embodiment 77. The system of any preceding embodiment, wherein The exhaust treatment system includes a compression system configured to compress a portion of the exhaust.

The system of any preceding embodiment, wherein the exhaust gas treatment system comprises a dehumidification system and/or a degranulation system.

Embodiment 79. The system of any preceding embodiment, comprising a control system that adjusts one or more operating parameters to control an equivalence ratio or effluent level in the exhaust gas in response to sensor feedback.

The system of any preceding embodiment, wherein the one or more operational parameters comprise an oxidant flow rate and/or a fuel flow rate to the turbine combustor.

Embodiment 81. The system of any preceding embodiment, wherein the control system is configured to maintain the equivalence ratio between about 0.95 and 1.05.

Embodiment 82. The system of any preceding embodiment, wherein the sensor feedback comprises gas composition feedback relating to oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons, or any combination thereof.

Embodiment 83. The system of any preceding embodiment, wherein the control system is coupled to a plurality of sensors configured to obtain sensor feedback, and the plurality of sensors are along the exhaust gas recirculation path, turbine Burner, turbine, exhaust gas compressor, or a combination thereof.

Embodiment 84. The system of any preceding embodiment, comprising a bypass line from an exhaust gas compressor to a turbine, wherein the bypass line comprises a heat exchanger configured to cool a bypass flow of exhaust gas from the exhaust gas compressor to the turbine .

Specific example 85. The system of any of the preceding specific examples, the package thereof A gas turbine engine having a turbine combustor, a turbine, and an exhaust gas compressor, wherein the gas turbine engine is a stoichiometric exhaust gas recirculation (SEGR) gas turbine engine.

Specific example 86. The system of any of the foregoing specific examples, the package thereof An exhaust gas extraction system coupled to the gas turbine engine, an exhaust gas treatment system coupled to the exhaust gas extraction system, and a hydrocarbon production system coupled to the exhaust gas treatment system.

Specific example 87. A method comprising: at least one An oxidant and at least one fuel are injected into the chamber of the turbine combustor, wherein the at least one oxidant and the at least one fuel are mixed and combusted to form a diffusion flame to produce a combustion product; the combustion product is used to drive the turbine and output the exhaust gas; Recycling path is recirculated to the exhaust gas compressor; exhaust gas is compressed and sent to the turbine combustor; flow rate of the at least one oxidant and the at least one fuel to the turbine combustor is controlled in a stoichiometric control mode, wherein the stoichiometry Control mode is configured to vary the flow rates and provide a substantially stoichiometric ratio of the at least one fuel to the at least one oxidant; and control the at least one oxidant and the at least one fuel to the turbine in a non-stoichiometric control mode The flow rate of the device, wherein the non-stoichiometric control mode is configured to vary the flow rates and provide a non-stoichiometric ratio of the at least one fuel to the at least one oxidant.

Specific example 88. The method of any preceding embodiment, wherein Control of the stoichiometric control mode includes providing the substantially stoichiometric ratio of an equivalent ratio of about 1.0.

Specific example 89. The method of any preceding embodiment, wherein Control of the stoichiometric control mode includes providing the substantially stoichiometric ratio of the equivalence ratio between about 0.95 and about 1.05.

Embodiment 90. The method of any of the preceding embodiments, wherein Control of the non-stoichiometric control mode includes providing the non-stoichiometric ratio of an equivalence ratio of less than about 0.95 or greater than about 1.05.

Specific Example 91. The method of any of the foregoing specific examples, the package thereof There is a transition between changing the flow rate from the first set of flow rates to the second set of flow rates and between the stoichiometric control mode and the non-stoichiometric control mode.

Specific example 92. The method of any preceding embodiment, wherein The second set of flow rates is less than the first set of flow rates.

Specific example 93. The method of any preceding embodiment, wherein The second set of flow rates is greater than the first set of flow rates.

Embodiment 94. The method of any preceding embodiment, wherein Control of the stoichiometric control mode includes changing the flow rates from the first set of flow rates to the second set of flow rates while maintaining the substantially stoichiometric ratio.

Specific example 95. The method of any preceding embodiment, wherein The second set of flow rates is less than the first set of flow rates.

Specific example 96. The method of any preceding embodiment, wherein The second set of flow rates is greater than the first set of flow rates.

Embodiment 97. The method of any preceding embodiment, wherein Control of the stoichiometric control mode includes changing the power output of the turbine from the first power output to the second power output by changing from the first set of flow rates to the second set of flow rates, respectively.

Specific example 98. The method of any preceding embodiment, wherein The second set of flow rates is less than the first set of flow rates, and the second power output is less than the first power output.

Embodiment 99. The method of any preceding embodiment, wherein The second set of flow rates is greater than the first set of flow rates, and the second power output is greater than the first power output.

Specific example 100. The method of any of the preceding specific examples, Control of the stoichiometric control mode includes maintaining the emissions in the exhaust within one or more target emissions ranges while changing the flow rates from the first set of flow rates to the second set of flow rates.

Specific example 101. The method of any of the preceding specific examples, The emissions include carbon monoxide, oxygen, nitrogen oxides, sulfur oxides, unburned hydrocarbons, hydrogen, or any combination thereof.

Specific example 102. The method of any of the preceding specific examples, The one or more target emission ranges comprise a range of oxygen of less than about 50 parts per million (ppmv) and/or a range of carbon monoxide of less than about 5000 ppmv.

Specific example 103. The method of any of the preceding specific examples, The one or more target emission ranges comprise a range of oxygen of less than about 10 parts per million (ppmv) and/or a range of carbon monoxide of less than about 1000 ppmv.

Specific example 104. The method of any of the preceding specific examples, Control of the stoichiometric control mode involves gradually changing the flow rate in the plurality of sets of flow rates while maintaining the substantially stoichiometric ratio.

Specific example 105. The method of any of the preceding specific examples, The multi-group flow rate includes at least three sets of flow rates.

Specific example 106. The method of any of the preceding specific examples, The multi-group flow rate includes flow rates of at least four groups.

Specific example 107. The method of any of the preceding specific examples, Controlling the stoichiometric control mode includes maintaining a substantially stoichiometric ratio while simultaneously: gradually reducing the flow rate in the plurality of sets of flow rates; gradually reducing one of the plurality of power outputs of the turbine; and The emissions are maintained in the exhaust gas within one or more target emissions ranges.

Specific example 108. The method of any of the preceding specific examples, The emissions include carbon monoxide, oxygen, nitrogen oxides, sulfur oxides, unburned hydrocarbons, hydrogen, or any combination thereof.

Specific example 109. The method of any of the preceding specific examples, The one or more target emission ranges comprise a range of oxygen of less than about 50 parts per million (ppmv) and/or a range of carbon monoxide of less than about 5000 ppmv.

Specific example 110. The method of any of the preceding specific examples, The one or more target emission ranges comprise a range of oxygen of less than about 10 parts per million (ppmv) and/or a range of carbon monoxide of less than about 1000 ppmv.

Specific example 111. The method of any of the preceding specific examples, The transition from the stoichiometric control mode to the non-stoichiometric control mode is included after gradually reducing the flow rate, gradually reducing the power output, and maintaining the emissions.

Specific example 112. The method of any of the preceding specific examples, Control of the non-stoichiometric control mode includes operating in a rich fuel control mode after switching from the stoichiometric control mode to the non-stoichiometric control mode.

Specific example 113. The method of any of the preceding specific examples, Control of the non-stoichiometric control mode includes operating in a lean fuel control mode after switching from the stoichiometric control mode to the non-stoichiometric control mode.

Specific example 114. The method of any of the preceding specific examples, The control of the stoichiometric control mode includes maintaining emissions in the exhaust gas within the target emission range of the first group, wherein control of the non-stoichiometric control mode includes maintaining the emissions in the exhaust gas in the second group of target emissions Within the scope, wherein the target emission ranges of the first and second groups are different from each other.

Specific example 115. The method of any of the preceding specific examples, Control of the non-stoichiometric control mode includes operating in a lean fuel control mode having a target emission range of oxygen emissions of at least about 1000 parts per million (ppmv).

Specific example 116. The method of any of the preceding specific examples, Control of the non-stoichiometric control mode includes operation in a lean fuel control mode having a target emission range of carbon monoxide emissions of less than about 100 parts per million (ppmv).

Specific example 117. The method of any of the preceding specific examples, The control of the non-stoichiometric control mode includes a target emission range with carbon monoxide emissions of less than about 20 parts per million (ppmv) The lean fuel control mode operates.

Specific example 118. The method of any of the preceding specific examples, Control of the non-stoichiometric control mode includes operation in a lean fuel control mode having a target emission range of nitrogen oxide emissions of less than about 200 parts per million (ppmv).

Specific example 119. The method of any of the preceding specific examples, Control of the non-stoichiometric control mode includes operation in a lean fuel control mode having a target emission having a nitrogen oxide emission range of less than about 100 parts per million (ppmv).

Specific example 120. The method of any of the preceding specific examples, Including controlling one or more operational parameters for: gradually changing the flow rate in the plurality of sets of flow rates; gradually changing one of the plurality of power outputs of the turbine in response to changing the flow rate; changing the flow Before and after the rate, the emissions in the exhaust gas are maintained within one or more target emission ranges; before and after the flow rate is changed, the temperature of the exhaust gases along the exhaust gas recirculation path is maintained within a target temperature range; The pressure of the exhaust gas along the exhaust gas recirculation path is maintained within the target temperature range before and after the flow rate is changed.

Specific example 121. The method of any of the preceding specific examples, The medium control includes maintaining the temperature along the exhaust gas recirculation path within a target temperature range downstream of the at least one catalyst unit.

Specific example 122. The method of any of the preceding specific examples, The medium control includes adjusting the operating rate of the exhaust gas extraction valve, the exhaust gas discharge valve, the exhaust gas compressor or the oxidant compressor, and the exhaust gas compressor inlet baffle The pressure is maintained by at least one of a position, an exhaust gas compressor recirculation valve, or any combination thereof.

Specific example 123. The method of any of the preceding specific examples, Including independently controlling fluid flow through first and second fluid supply circuits, wherein the turbine combustor includes a first set of fuel nozzles coupled to the first fluid supply circuit and a second set of fuel coupled to the second fluid supply circuit A nozzle, wherein at least one of the first or second set of fuel nozzles comprises a first diffusion fuel nozzle configured to generate a diffusion flame.

Specific example 124. The method of any of the preceding specific examples, The first set of fuel nozzles includes a single fuel nozzle, and the second set of fuel nozzles includes a plurality of fuel nozzles.

Specific example 125. The method of any of the preceding specific examples, The first set of fuel nozzles includes a first plurality of fuel nozzles, and the second set of fuel nozzles includes a second plurality of fuel nozzles.

Specific example 126. The method of any of the preceding specific examples, The fluid flow is independently controlled by the first fluid supply circuit, the second fluid supply circuit, and the third fluid supply circuit, wherein the turbine combustor includes a third set of fuel nozzles coupled to the third fluid supply circuit.

Specific example 127. The method of any of the preceding specific examples, The fluid flow is independently varied at different rates through the first and second fluid supply circuits.

Specific example 128. The method of any of the preceding specific examples, The fluid flow is independently varied at the same rate through the first and second fluid supply circuits.

Specific example 129. The method of any of the preceding specific examples, The first set of fuel nozzles includes at least a first diffusion fuel nozzle, and the second set of fuel nozzles includes a second diffusion fuel nozzle.

Specific example 130. The method of any of the preceding specific examples, The first set of fuel nozzles includes at least a first diffusion fuel nozzle, and the second set of fuel nozzles includes a first premixed fuel nozzle.

Specific example 131. The method of any of the preceding specific examples, The medium injection includes separately injecting the at least one oxidant and the at least one fuel from the individual first and second passages that are isolated from each other along the first diffusion fuel nozzle.

Specific example 132. The method of any of the preceding specific examples, The first and second channels are arranged in a concentric arrangement.

Specific example 133. The method of any of the preceding specific examples, The first passage extends around the second passage.

Specific example 134. The method of any of the preceding specific examples, The second channel extends around the first channel.

Specific example 135. The method of any of the preceding specific examples, Injecting at least one diluent into the chamber.

Specific example 136. The method of any of the preceding specific examples, The at least one diluent comprises a portion of the offgas, steam, nitrogen, another inert gas, or a combination thereof.

Specific example 137. The method of any of the preceding specific examples, Injecting the at least one oxidant and the at least one fuel separately from the respective first and second channels isolated from each other along the first diffusion fuel nozzle, and A diluent stream is sent through the first diffusion fuel nozzle.

Specific example 138. The method of any of the preceding specific examples, A chamber is provided for feeding a stream of diluent downstream of the first diffusion fuel nozzle.

Specific example 139. The method of any of the preceding specific examples, A stream of diluent is injected through a plurality of channels in a liner of a turbine combustor, and the diluent stream contains a portion of the offgas.

Specific example 140. The method of any of the preceding specific examples, A diluent stream is injected through a plurality of diluent injectors through at least one wall of the turbine combustor, and the diluent stream comprises a portion of exhaust gas, steam, nitrogen, or another inert gas.

Specific example 141. The method of any of the preceding specific examples, The treatment of the exhaust gas with the first catalyst unit along the exhaust gas recirculation path is included.

Specific example 142. The method of any of the preceding specific examples, The middle treatment involves controlling the concentration levels of carbon monoxide, carbon dioxide, and unburned hydrocarbons in the exhaust.

Specific example 143. The method of any of the preceding specific examples, The middle treatment involves driving the oxidation reaction with the exhaust gas and the oxidant fuel.

Specific example 144. The method of any of the preceding specific examples, A flow rate that controls the oxidant fuel to the first catalyst unit is included to control the oxidation reaction.

Specific example 145. The method of any of the preceding specific examples, A flow rate comprising oxidant fuel is controlled in response to sensor feedback, and the second sensor feedback includes gas composition feedback indicative of oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons, or any combination thereof.

Specific example 146. The method of any of the preceding specific examples, Recovering heat from the exhaust gas along the exhaust gas recirculation path using the first heat recovery unit, the second heat recovery unit, or a combination thereof.

Specific example 147. The method of any of the preceding specific examples, The first catalyst unit included within, upstream or downstream of the first or second heat recovery unit drives the first catalyst reaction.

Specific example 148. The method of any of the preceding specific examples, The second catalyst unit included within, upstream or downstream of the first or second heat recovery unit drives a second catalyst reaction.

Specific example 149. The method of any of the preceding specific examples, A first heat recovery steam generator comprising a first heat recovery unit is used to generate a first steam, a second heat recovery steam generator of the second heat recovery unit is used to generate a second steam, or a combination thereof.

Specific example 150. The method of any of the preceding specific examples, Either driving the first steam turbine with the first steam or driving the second steam turbine with the second steam.

Specific example 151. The method of any of the preceding specific examples, It includes removing moisture from the exhaust gas by a dehumidification system disposed along the exhaust gas recirculation path.

Specific example 152. The method of any of the preceding specific examples, The dehumidification system comprises a heat exchanger, a condenser, a water gas separator, a filter, or any combination thereof.

Specific example 153. The method of any of the preceding specific examples, Including the removal of exhaust gas by a degranulation system disposed along the exhaust gas recirculation path Remove the particles.

Specific example 154. The method of any of the preceding specific examples, The degranulation system comprises an inertial separator, a gravity separator, a filter, or any combination thereof.

Specific example 155. The method of any of the preceding specific examples, A step of boosting the flow of exhaust gas with a booster blower disposed along the exhaust gas recirculation path.

Specific example 156. The method of any of the preceding specific examples, A heat recovery unit, a booster blower, a dehumidification unit, and a degranulation unit disposed along the exhaust gas recirculation path are included.

Specific example 157. The method of any of the preceding specific examples, It includes extracting a portion of the exhaust gas with an exhaust gas extraction system.

Specific example 158. The method of any of the preceding specific examples, This includes treating the portion of the exhaust with an exhaust gas treatment system.

Specific example 159. The method of any of the preceding specific examples, The process of treating the portion of the off-gas comprises separating the portion of the off-gas into a plurality of gas streams.

Specific examples of the method according to any of the preceding 160. Specific examples, wherein the carbon dioxide-rich stream comprises a plurality of gas (CO ₂₎ and the first flow-lean carbon dioxide (CO ₂₎ of the second stream.

Specific example 161. The method of any of the preceding specific examples, The process of treating the portion of the off-gas comprises compressing the portion of the off-gas, the first stream, or the second stream with a gas compression system.

Specific example 162. The method of any of the preceding specific examples, The treatment of the portion of the off-gas comprises removing moisture from the portion of the off-gas, the first stream, or the second vapor with a dehumidification system.

Specific example 163. The method of any of the preceding specific examples, The treatment of the portion of the off-gas comprises removing the particulates from the portion of the offgas, the first stream, or the second vapor by a degranulation system.

Specific example 164. The method of any of the preceding specific examples, The exhaust gas comprising the portion, the first stream, or the second vapor delivery target system, wherein the target system comprises a hydrocarbon generation system, an underground storage, a carbon storage system, a pipeline, a storage tank, or any combination thereof.

Specific example 165. The method of any of the preceding specific examples, One or more operating parameters are adjusted in response to sensor feedback to control the equivalence ratio or effluent level in the exhaust.

Specific example 166. The method of any of the preceding specific examples, Sensor feedback is obtained by monitoring the gas composition of the exhaust gases related to oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons, or any combination thereof.

Specific example 167. The method of any of the preceding specific examples, Obtaining sensor feedback in the middle includes monitoring a plurality of sensors along the exhaust gas recirculation path, turbine combustor, turbine, exhaust gas compressor, or a combination thereof.

Specific example 168. The method of any of the preceding specific examples, A bypass stream comprising the exhaust gas is sent from the exhaust gas compressor to the turbine along a bypass line.

Specific example 169. The method of any of the preceding specific examples, A bypass stream that cools the exhaust gas along the bypass line is included, and a bypass flow using the exhaust gas cools the turbine.

Specific example 170. The method of any of the preceding specific examples, A gas turbine engine operating with a turbine combustor, a turbine, and the exhaust gas compressor is included to achieve substantial stoichiometric combustion based on sensor feedback during the stoichiometric control mode.

Specific example 171. The method of any of the preceding specific examples, A portion of exhaust gas is extracted with an exhaust gas extraction system coupled to the gas turbine engine, and the portion of the exhaust gas is sent to a hydrocarbon generation system, a carbon sequestration system, a pipeline, a storage tank, or any combination thereof.

Specific Example 172. A method comprising: oxidizing an oxidant Leading to at least one oxidant compressor to produce a compressed oxidant stream; directing the recycled low oxygen content gas stream to a compressor section of the gas turbine engine to produce a compressed low oxygen content gas stream; the first portion of the first compressed oxidant flow rate The compressed oxidant stream and the fuel stream of the first fuel flow rate are directed to the at least one turbine combustor at a substantially stoichiometric ratio, and the compressed oxidant stream and the fuel stream are mixed at a point of combustion, and the compressed oxidant stream and the fuel are combusted a mixture of streams; directing a first portion of the compressed low oxygen content gas stream of the low oxygen content gas flow rate to the at least one turbine combustor and mixing it with the compressed oxidant and the combustion stream of the fuel after the combustion point, and Generating a high temperature, high pressure, low oxygen content stream; directing the high temperature, high pressure, low oxygen content stream to the expander section of the gas turbine engine, and expanding the high temperature, high pressure, low oxygen content stream to produce a first mechanical power and having a first recycle low An oxygen content gas flow rate recycling a low oxygen content gas stream, wherein the recycled low oxygen content gas stream contains a first Circulating a low oxygen content gas effluent level; using a first portion of the first mechanical power to drive the compressor section of the gas turbine engine; using a second portion of the first mechanical power to drive at least one of: a generator, The at least one oxidant compressor or at least one other mechanical device; recycling the recirculated low oxygen content gas stream from the outlet of the expander section to the inlet of the compressor section of the gas turbine engine in a recirculation loop; from the gas turbine The engine extracts at least a second portion of the compressed low oxygen content gas stream, and delivers the at least a second portion of the compressed low oxygen content gas stream to the first at least one oxidation catalyst unit, and produces a product comprising the first low oxygen content product a low oxygen content product stream having a level of matter within the target range; reducing the fuel stream flow rate to a second fuel stream flow rate that is less than the first fuel stream flow rate, and reducing the first portion of the compressed oxidant stream flow rate to less than a second compressed oxidant flow rate of the first compressed oxidant flow rate, wherein the substantially stoichiometric ratio is maintained, resulting in a second less than the first mechanical power Mechanical power, and producing a low oxygen content product stream having a second low oxygen content product effluent level within a target range; reducing the fuel flow rate to a third fuel flow rate less than the second fuel flow rate, and Reducing the first portion of the compressed oxidant flow rate to a third compressed oxidant flow rate that is less than the second compressed oxidant flow rate, wherein maintaining the substantially stoichiometric ratio produces a third mechanical power that is less than the second mechanical power, And generating a low oxygen content product stream comprising a third low oxygen content product effluent level within the target range; and reducing the fuel flow rate to a fourth fuel flow rate that is less than the third fuel flow rate, and The first portion of the compressed oxidant flow rate is reduced to a fourth compressed oxidant flow rate that is less than the third compressed oxidant flow rate, wherein the substantially stoichiometric ratio is not maintained, and lean fuel is achieved Combustion produces a fourth mechanical power that is less than the third mechanical power and produces a high oxygen content product stream comprising a high oxygen content product effluent level.

Specific example 173. The method of any of the preceding specific examples, The first recycled low oxygen content gas discharge comprises at least one of oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons, or similar products of incomplete combustion.

Specific example 174. The method of any of the preceding specific examples, The first, second, and third low oxygen content product emissions comprise at least one of oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons, or similar products of incomplete combustion.

Specific example 175. The method of any of the preceding specific examples, The high oxygen content product discharge comprises at least one of oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons or similar products of incomplete combustion.

Specific example 176. The method of any of the preceding specific examples, The limit of the low oxygen content product effluent level is at least one of 50 ppmv oxygen and 5000 ppmv carbon monoxide.

Specific example 177. The method of any of the preceding specific examples, The limit of the low oxygen content product effluent level is at least one of 10 ppmv oxygen and 1000 ppmv carbon monoxide.

Specific example 178. The method of any of the preceding specific examples, The high oxygen content product effluent level comprises at least 1000 ppmv oxygen.

Specific example 179. The method of any of the preceding specific examples, The high oxygen content product effluent level contains less than 100 ppmv oxidized carbon.

Specific example 180. The method of any of the preceding specific examples, The high oxygen content product effluent level comprises less than 20 ppmv carbon monoxide.

Specific example 181. The method of any of the preceding specific examples, The high oxygen content product effluent level comprises less than 200 ppmv oxynitride.

Specific example 182. The method of any of the preceding specific examples, The high oxygen content product effluent level comprises less than 100 ppmv oxynitride.

Specific example 183. The method of any of the preceding specific examples, Including introducing a second portion of the compressed oxidant stream to the first at least one oxidation catalyst unit to oxidize at least a portion of the carbon monoxide, hydrogen, unburned hydrocarbons, or incomplete contained in the compressed low oxygen content stream of the second portion At least one of the similar products of combustion.

Specific example 184. The method of any of the preceding specific examples, Including introducing an oxidizing fuel to the first at least one oxidation catalyst unit, and reducing at least a portion of residual oxygen contained in the compressed low oxygen content stream of the second portion.

Specific example 185. The method of any of the preceding specific examples, The oxidant consists essentially of ambient air and a recycle low oxygen content gas stream comprising nitrogen.

Specific example 186. The method of any preceding embodiment, wherein the equivalence ratio (phi, ) is equal to (fuel mol% / oxidizer mol%) _actual / (fuel mol% / oxidizer mol%) _{stoichiometry} .

Embodiment 187. The method of any preceding embodiment, comprising controlling a flow rate of the first portion of the compressed oxidant stream and at least one of the fuel streams to achieve a combustion equivalent ratio of about 1, and producing the first portion of the compressed oxidant The flow and the substantial stoichiometric ratio of the fuel stream.

Embodiment 188. The method of any preceding embodiment, comprising a sensor installed in the recirculation loop and measuring a component within the recycled low oxygen content stream.

The method of any preceding embodiment, wherein the measured component is at least one of the group consisting of oxygen, carbon monoxide, hydrogen, nitrogen oxides, and unburned hydrocarbons.

Embodiment 190. The method of any preceding embodiment, comprising determining an equivalence ratio by analyzing a component measurement.

Embodiment 191. The method of any preceding embodiment, comprising at least one of the extracted and measured upstream of the first at least one oxidation catalyst unit, downstream of the first at least one oxidation catalyst unit, or both A sensor for a component of a two-part compressed low oxygen content gas stream.

The method of any preceding embodiment, wherein the measured component is at least one of the group consisting of oxygen, carbon monoxide, hydrogen, nitrogen oxides, and unburned hydrocarbons.

Embodiment 193. The method of any preceding embodiment, comprising at least one compression oxidation ratio for adjusting a combustion equivalent ratio, the second portion At least one of a flow rate of the agent stream or a flow rate of the oxidizing fuel and a controller that achieves a desired level of at least one of the measured components downstream of the first at least one oxidation catalyst unit.

Specific example 194. The method of any of the preceding specific examples, A first heat recovery unit is included downstream of the first at least one oxidation catalyst unit.

Specific example 195. The method of any of the preceding specific examples, The first heat recovery unit includes a steam generator.

Specific example 196. The method of any of the preceding specific examples, Included is a steam generator that produces steam delivered to at least one steam turbine, and at least one of a generator or another mechanical device that drives power generation.

Specific example 197. The method of any of the preceding specific examples, A second heat recovery unit is included in the recirculation loop between the outlet of the expander section and the inlet to the compressor section of the gas turbine engine, and heat is removed from the recycle low oxygen content gas stream.

Specific example 198. The method of any of the preceding specific examples, The second heat recovery unit includes a steam generator.

Specific example 199. The method of any of the preceding specific examples, Included is a steam generator that produces steam delivered to at least one steam turbine, and at least one of a generator or another mechanical device that drives power generation.

Specific example 200. The method of any of the preceding specific examples, Containing a third portion of the compressed low oxygen content gas stream from the gas turbine engine The compressor section is delivered to the turbine as a secondary flow path for the secondary flow, and a third portion of the compressed low oxygen content gas stream is delivered to the recirculation loop after cooling and sealing the turbine.

Specific example 201. The method of any of the preceding specific examples, A booster blower that increases the pressure of the recycled low oxygen content gas stream downstream of the second heat recovery unit is included in the recycle loop.

Specific example 202. The method of any of the preceding specific examples, A regenerative circuit upstream of the compressor section of the gas turbine engine includes a heat exchanger that cools the recirculated low oxygen content gas stream prior to entering the inlet of the compressor section of the gas turbine engine.

Specific example 203. The method of any of the preceding specific examples, It is included to condense and remove water from the recycled low oxygen content gas stream with the heat exchanger.

Specific example 204. The method of any of the preceding specific examples, A delivery of at least a portion of the low oxygen content product stream to an underground reservoir for enhanced hydrocarbon recovery is included.

Specific example 205. The method of any of the preceding specific examples, The at least a portion of the low oxygen content product stream is compressed with at least one inert gas product compressor prior to delivering the at least a portion of the low oxygen content product stream to an underground reservoir for enhanced hydrocarbon recovery.

Specific example 206. The method of any of the preceding specific examples, The cooling of the low oxygen content product stream is comprised by a first heat recovery unit.

Specific example 207. The method of any of the preceding specific examples, Insulating the at least a portion of the low oxygen content product stream to gas dehydration unit.

Specific example 208. The method of any of the preceding specific examples, A method of delivering at least a portion of the low oxygen content product stream to a carbon dioxide separation unit to produce a carbon dioxide lean stream and a carbon dioxide rich stream.

Specific example 209. The method of any of the preceding specific examples, This includes delivering at least a portion of the carbon dioxide lean stream to an underground reservoir for enhanced hydrocarbon recovery.

Specific example 210. The method of any of the preceding specific examples, This includes delivering at least a portion of the carbon dioxide rich stream to an underground reservoir for enhanced hydrocarbon recovery.

Specific example 211. The method of any of the preceding specific examples, A method of delivering at least a portion of the carbon dioxide rich stream to a carbon sequestration unit.

Specific example 212. The method of any of the preceding specific examples, The compressing the at least a portion of the carbon dioxide lean stream to at least one lean product compressor is included prior to delivering the at least a portion of the lean carbon dioxide stream to the subterranean reservoir for enhanced hydrocarbon recovery.

Specific example 213. The method of any of the preceding specific examples, The at least a portion of the carbon dioxide rich stream is compressed to at least one rich product compressor prior to delivering the at least a portion of the carbon dioxide rich stream to an underground reservoir for enhanced hydrocarbon recovery.

Specific example 214. The method of any of the preceding specific examples, The compressing the at least a portion of the carbon dioxide rich stream to at least one rich product compressor is included prior to delivering the at least a portion of the carbon dioxide rich stream to the carbon sequestration unit.

Specific example 215. The method of any of the preceding specific examples, A delivery of at least a portion of the carbon dioxide lean stream to the gas dehydration unit is included.

Specific example 216. The method of any of the preceding specific examples, A method of delivering at least a portion of the carbon dioxide rich stream to a gas dehydration unit.

Specific example 217. The method of any of the preceding specific examples, A process comprising introducing at least a portion of the low oxygen content product stream to an expander and expanding the at least a portion of the low oxygen content product stream, driving at least one of the generator or another mechanical device, and generating a discharge stream.

Specific example 218. The method of any of the preceding specific examples, A process comprising introducing at least a portion of the carbon dioxide lean stream to an expander and expanding the at least a portion of the carbon dioxide stream, driving at least one of the generator or another mechanical device and generating a discharge stream.

Specific example 219. The method of any of the preceding specific examples, Included in the second at least one oxidation catalyst unit located within the recycle loop, and oxidizing at least a portion of a similar product comprising one of carbon monoxide, hydrogen, unburned hydrocarbons or incomplete combustion in the recycle low oxygen content gas stream At least one of them.

Specific example 220. The method of any of the preceding specific examples, The second at least one oxidation catalyst unit is located upstream of the second heat recovery unit.

Specific example 221. The method of any of the preceding specific examples, The second at least one oxidation catalyst unit is located in the second heat recovery unit Downstream.

Specific example 222. The method of any of the preceding specific examples, The second at least one oxidation catalyst unit is located within the second heat recovery unit and is located at a location that provides a suitable operating temperature and provides a suitable heat sink for the heat generated by the catalyst reaction.

Specific example 223. The method of any of the preceding specific examples, A flow rate comprising a compressed low oxygen content gas stream controlling the at least a second portion is included.

Specific example 224. The method of any of the preceding specific examples, The flow rate of the compressed low oxygen content gas stream of the at least second portion is adjusted to maintain the pressure at the location within the recirculation loop within a desired range.

Specific example 225. The method of any of the preceding specific examples, Adjusting at least a second portion of the compressed low oxygen content gas stream using at least one of an extraction valve, an extraction bleed valve, a product compressor operating rate, a product compressor inlet baffle position, or a product compressor recirculation valve Flow rate.

Specific example 226. The method of any of the preceding specific examples, The at least one turbine combustor each includes a plurality of combustors and at least two separately controlled loops that separately supply the fuel stream to two individual combustors, one individual combustor and one set of combustors, and two sets of combustors At least one of a device, and a combination thereof.

Specific example 227. The method of any of the preceding specific examples, Among the at least two separately controlled circuits, from the first fuel flow rate to the second fuel flow rate, the second fuel flow rate to the third fuel flow rate, and the third fuel flow rate to the fourth fuel flow rate The percentage reduction of the fuel flow rate of at least one of them is not equal.

Specific example 228. The method of any of the preceding specific examples, Included: reducing a fuel flow rate to a fifth flow rate that is less than the first fuel flow rate, and reducing the first portion of the compressed oxidant flow rate to a fifth compressed oxidant that is less than the first compressed oxidant flow rate a flow rate wherein the substantially stoichiometric ratio is maintained, a fifth mechanical power less than the first mechanical power is generated, and a low oxygen content product stream is produced comprising a fifth low oxygen content product effluent level within the target range and a first heat release from the second at least one oxidation catalyst unit, which results in a temperature of the recycled low oxygen content gas stream downstream of the second at least one oxidation catalyst unit being within a target range; reducing the fuel flow rate to less than a sixth fuel flow rate of the fifth fuel flow rate, and reducing the first portion of the compressed oxidant flow rate to a sixth compressed oxidant flow rate less than the fifth compressed oxidant flow rate, wherein the substantially chemical Metering ratio, producing a sixth mechanical power less than the fifth mechanical power and producing a low oxygen content product stream comprising a sixth low oxygen content product effluent within the target range And a second heat release from the second at least one oxidation catalyst unit, the temperature of the recycled low oxygen content gas stream downstream of the second at least one oxidation catalyst unit being within a target range; the fuel flow rate Reducing to a seventh fuel flow rate that is less than the sixth fuel flow rate, and reducing the first portion of the compressed oxidant flow rate to a seventh compressed oxidant flow rate that is less than the sixth compressed oxidant flow rate, wherein The substantially stoichiometric ratio, and achieving lean fuel combustion, producing a seventh mechanical power less than the sixth mechanical power and producing a high oxygen content product comprising a high oxygen content product effluent level and from the second at least one oxidation catalyst a third heat release of the unit which results in a further downstream of the second at least one oxidation catalyst unit The temperature of the circulating low oxygen content gas stream is within the target range.

Specific example 229. The method of any of the preceding specific examples, The method includes: reducing a fuel flow rate to an eighth flow rate that is less than the first fuel flow rate, and reducing the first portion of the compressed oxidant flow rate to an eighth compressed oxidant that is less than the first compressed oxidant flow rate a flow rate, wherein the substantially stoichiometric ratio is maintained, producing an eighth mechanical power less than the first mechanical power and producing a low oxygen content product stream comprising an eighth low oxygen content product effluent level within the target range and from a fourth heat release of the first at least one oxidation catalyst unit, which results in a temperature of the low oxygen content product stream downstream of the first at least one oxidation catalyst unit being within a target range; reducing the fuel flow rate to less than the eighth a ninth fuel flow rate of the fuel flow rate, and reducing the first portion of the compressed oxidant flow rate to a ninth compressed oxidant flow rate that is less than the eighth compressed oxidant flow rate, wherein the substantially stoichiometric ratio is maintained, Generating a ninth mechanical power less than the eighth mechanical power and producing a low oxygen content product stream comprising a ninth low oxygen content product effluent level within the target range and a fifth heat release of the first at least one oxidation catalyst unit, which results in a temperature of the low oxygen content product stream downstream of the first at least one oxidation catalyst unit being within a target range; reducing the fuel flow rate to less than the a tenth fuel flow rate of the ninth fuel flow rate, and reducing the first portion of the compressed oxidant flow rate to a tenth compressed oxidant flow rate that is less than the ninth compressed oxidant flow rate, wherein the substantially chemistry is not maintained Metering ratio, and achieving lean fuel combustion, producing a tenth mechanical power less than the ninth mechanical power and producing a high oxygen content product stream comprising a high oxygen content product effluent level and a first from at least one oxidation catalyst unit Six heat release Put, which results in a temperature of the high oxygen content product stream downstream of the first at least one oxidation catalyst unit being within the target range.

Specific example 230. The method of any of the preceding specific examples, A first at least one nitrogen oxide reduction catalyst unit is included as part of the first at least one oxidation catalyst unit.

Specific example 231. The method of any of the preceding specific examples, A second at least one nitrogen oxide reduction catalyst unit is included as part of the second at least one oxidation catalyst unit.

Specific example 232. The method of any of the preceding specific examples, Downstream of the heat exchanger includes at least one of an inertial separator, a coalescing filter, and a watertight filter, and improves the efficiency of removing condensed water.

The written description uses examples to disclose the invention, including the best mode of the invention, and is to be understood by those skilled in the art, including the manufacture and use of any device or system and any combination. The patentable scope of the invention is defined by the scope of the claims, and may include other examples that may occur to those skilled in the art. If such other examples have structural elements that are no different from the literal language of the patent application, or if they include equivalent structural elements that are not substantially different from the literal language of the patent application, they are intended to be within the scope of the patent application.

100‧‧‧Control system

160‧‧‧ burner

164‧‧‧fuel nozzle

166‧‧‧ head section

168‧‧‧ burning part

Room 494‧‧

496‧‧‧First wall or liner

498‧‧‧Second wall or flow casing

500‧‧‧Flow channel

502‧‧‧ holes or perforations

506‧‧ ‧ holes or perforations

508‧‧‧Exhaust gas injection

510‧‧‧Diluent injector

512‧‧‧Diluent injection

516‧‧‧flame

518‧‧‧Fluid Supply System (FSS)

554‧‧‧Diffusion fuel nozzle

556‧‧‧Diffuse flame

722‧‧‧Fluid A channel

724‧‧‧ Fluid B channel

726‧‧‧Function C channel

728‧‧‧catheter or structure

730‧‧‧catheter or structure

732‧‧‧catheter or structure

734‧‧‧Fluid A

736‧‧‧ Fluid B

738‧‧‧ Fluid C

740‧‧‧ Hole

742‧‧‧ Hole

744‧‧‧ Hole

746‧‧‧ shared plane or downstream

760‧‧‧D fluid channel

762‧‧‧catheter or structure

764‧‧‧ Fluid D

766‧‧‧Export

770‧‧‧Diluent injection system

772‧‧‧Hot products of combustion

774‧‧‧Fluid E

776‧‧‧Fluid F

778‧‧‧ Fluid G

Claims (232)

A system comprising: a turbine combustor comprising a first diffusion fuel nozzle, wherein the first diffusion fuel nozzle is configured to generate a diffusion flame; the turbine is driven by a combustion product from a diffusion flame in the turbine combustor An exhaust gas compressor, wherein the exhaust gas compressor is configured to compress exhaust gas from the turbine and to be sent to the turbine combustor along an exhaust gas recirculation path; and a control system configured to be in a stoichiometric control mode and non-chemical a metered control mode to control a flow rate of the at least one oxidant and the at least one fuel to the turbine combustor, wherein the stoichiometric control mode is configured to vary the flow rates and provide the essence of the at least one fuel and the at least one oxidant The upper stoichiometric ratio, and the non-stoichiometric control mode, are configured to alter the flow rates and provide a non-stoichiometric ratio of the at least one fuel to the at least one oxidant. The system of claim 1, wherein the stoichiometric control mode is configured to provide an equivalent stoichiometric ratio of about 1.0. The system of claim 1, wherein the stoichiometric control mode is configured to provide the substantially stoichiometric ratio of an equivalence ratio between about 0.95 and about 1.05. The system of claim 1, wherein the non-stoichiometric control mode is configured to provide less than about 0.95 or greater than about 1.05. The equivalent ratio of the non-stoichiometric ratio. The system of claim 1, wherein the control system is configured to change the flow rate from the first set of flow rates to the second set of flow rates and to change the stoichiometric control mode and the non-stoichiometric control Conversion between modes. The system of claim 5, wherein the second set of flow rates is less than the first set of flow rates. The system of claim 5, wherein the second set of flow rates is greater than the first set of flow rates. The system of claim 1, wherein the control system in the stoichiometric control mode is configured to change the flow rate from the first set of flow rates to the second set of flow rates while maintaining the substantially stoichiometric ratio. The system of claim 8 wherein the second set of flow rates is less than the first set of flow rates. The system of claim 8 wherein the second set of flow rates is greater than the first set of flow rates. The system of claim 8, wherein the control system in the stoichiometric control mode is configured to respectively change the flow rate from the first set of flow rates to the second set of flow rates The power output changes from a first power output to a second power output. The system of claim 11, wherein the second set of flow rates is less than the first set of flow rates, and the second power output is less than the first power output. For example, the system of claim 11 of the patent scope, wherein the second group The flow rate is greater than the first set of flow rates, and the second power output is greater than the first power output. The system of claim 11, wherein the control system in the stoichiometric control mode is configured to change the flow rate from the first set of flow rates to the second set of flow rates Emissions are maintained within one or more target emissions ranges. The system of claim 14, wherein the emissions comprise carbon monoxide, oxygen, nitrogen oxides, sulfur oxides, unburned hydrocarbons, hydrogen, or any combination thereof. The system of claim 14, wherein the one or more target emission ranges comprise a range of oxygen of less than about 50 parts per million (ppmv) and/or a range of carbon monoxide of less than about 5000 ppmv. The system of claim 14, wherein the one or more target emission ranges comprise an oxygen range of less than about 10 parts per million (ppmv) and/or a range of carbon monoxide of less than about 1000 ppmv. The system of claim 1, wherein the control system in the stoichiometric control mode is configured to gradually change the flow rate in the plurality of sets of flow rates while maintaining the substantially stoichiometric ratio. The system of claim 18, wherein the plurality of sets of flow rates comprise at least three sets of flow rates. The system of claim 18, wherein the plurality of sets of flow rates comprise at least four sets of flow rates. The system of claim 18, wherein the control system in the stoichiometric control mode is configured to maintain the substantially chemical Metering ratio, and at the same time: gradually reducing the flow rate in the plurality of sets of flow rates; gradually reducing one of the plurality of power outputs of the turbine; and maintaining emissions in the exhaust gas in one or more target emission ranges Inside. The system of claim 21, wherein the emissions comprise carbon monoxide, oxygen, nitrogen oxides, sulfur oxides, unburned hydrocarbons, hydrogen, or any combination thereof. The system of claim 21, wherein the one or more target emission ranges comprise an oxygen range of less than about 50 parts per million (ppmv) and/or a range of carbon monoxide of less than about 5000 ppmv. The system of claim 21, wherein the one or more target emission ranges comprise a range of oxygen of less than about 10 parts per million (ppmv) and/or a range of carbon monoxide of less than about 1000 ppmv. The system of claim 21, wherein the control system is configured to switch from the stoichiometric control mode to the non-stoichiometric amount after gradually reducing the flow rate, gradually reducing the power output, and maintaining emissions. Control mode. The system of claim 25, wherein after switching from the stoichiometric control mode to the non-stoichiometric control mode, the control system is configured to operate in a fuel rich control mode that is not in a stoichiometric control mode. The system of claim 25, wherein after switching from the stoichiometric control mode to the non-stoichiometric control mode, The control system is configured to operate in a lean fuel control mode of a non-stoichiometric control mode. The system of claim 25, wherein the control system is configured to maintain emissions in the exhaust gas within a target discharge range of the first group when operating in a stoichiometric control mode, the control system being configured to The emissions in the exhaust gas are maintained within the target emission range of the second group when operating in the non-stoichiometric control mode, and the target emission ranges of the first and second groups are different from each other. A system of claim 28, wherein the non-stoichiometric control mode comprises a lean fuel control mode having a target emission range of oxygen emissions of at least about 1000 parts per million (ppmv). A system of claim 28, wherein the non-stoichiometric control mode comprises a lean fuel control mode having a target emission range of carbon monoxide emissions of less than about 100 parts per million (ppmv). A system of claim 28, wherein the non-stoichiometric control mode comprises a lean fuel control mode having a target emission range of carbon monoxide emissions of less than about 20 parts per million (ppmv). A system of claim 28, wherein the non-stoichiometric control mode comprises a lean fuel control mode having a target emission range of nitrogen oxide emissions of less than about 200 parts per million (ppmv). For example, the system of claim 28, wherein the non-stoichiometric control mode includes a target emission range with nitrogen oxide emissions of A lean fuel control mode of less than about 100 parts per million (ppmv). The system of claim 1, wherein the control system is configured to: gradually change a flow rate in the plurality of flow rates; gradually change a plurality of power outputs of the turbine due to a change in flow rate One of the power outputs; the emissions in the exhaust gas are maintained within one or more target emission ranges before and after the flow rate is changed; the temperature of the exhaust gases along the exhaust gas recirculation path before and after the flow rate is changed Maintained within the target temperature range; and before and after changing the flow rate, maintain the pressure of the exhaust gas along the exhaust gas recirculation path within the target temperature range. A system of claim 34, wherein the control system is configured to maintain the temperature within the target temperature range along the exhaust gas recirculation path downstream of the at least one catalyst unit. The system of claim 34, wherein the control system is configured to adjust an operating rate of an exhaust gas extraction valve, an exhaust gas discharge valve, an exhaust gas compressor or an oxidant compressor, a position of an exhaust gas compressor inlet baffle, At least one of the exhaust gas compressor recirculation valve, or any combination thereof, maintains the pressure. The system of claim 1, wherein the turbine combustor includes a first set of fuel nozzles coupled to the first fluid supply circuit and a second set of fuel nozzles coupled to the second fluid supply circuit, the first diffusion spray The nozzle is a portion of the first or second set of fuel nozzles, and the control system is configured to independently control fluid flow through the first and second fluid supply circuits. The system of claim 37, wherein the first set of fuel nozzles comprises a single fuel nozzle, and the second set of fuel nozzles comprises a plurality of fuel nozzles. The system of claim 37, wherein the first set of fuel nozzles comprises a first plurality of fuel nozzles, and the second set of fuel nozzles comprises a second plurality of fuel nozzles. The system of claim 37, wherein the turbine combustor includes a third set of fuel nozzles coupled to a third fluid supply circuit, and the control system is configured to transmit the first, second, and third fluids The supply circuit independently controls the fluid flow. A system of claim 37, wherein the control system is configured to independently change the fluid at different rates through the first and second fluid supply circuits. A system of claim 37, wherein the control system is configured to independently change the fluid at the same rate through the first and second fluid supply circuits. The system of claim 37, wherein the first set of fuel nozzles comprises at least a first diffusion fuel nozzle, and the second set of fuel nozzles comprises a second diffusion fuel nozzle. The system of claim 37, wherein the first set of fuel nozzles comprises at least a first diffusion fuel nozzle, and the second set of fuel sprays The mouth contains a first premixed fuel nozzle. A system of claim 1, comprising a first catalyst unit disposed along the exhaust gas recirculation path. The system of claim 45, wherein the first catalyst unit is configured to control a concentration level of oxygen, carbon monoxide, carbon dioxide, nitrogen oxides, unburned hydrocarbons, or any combination thereof in the exhaust. The system of claim 45, wherein the first catalyst unit comprises an oxidation catalyst, a carbon monoxide reduction catalyst, a nitrogen oxide reduction catalyst, an alumina, a zirconia, a cerium oxide, a titanium oxide, a platinum oxide, and an oxidation. Palladium, cobalt oxide, or a mixed metal oxide, or a combination thereof. A system of claim 45, wherein the first catalyst unit is configured to drive an oxidation reaction with an exhaust gas and an oxidant fuel. A system of claim 48, wherein the control system is configured to adjust the flow of the oxidant fuel to control the oxidation reaction system. The system of claim 49, wherein the control system is configured to adjust the flow of the oxidant fuel in response to sensor feedback, and the sensor feedback includes an indicator of oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned Gas composition feedback for the hydrocarbons, or any combination thereof. A system of claim 1, comprising a first heat recovery unit, a second heat recovery unit, or a combination thereof disposed along the exhaust gas recirculation path. Such as the system of claim 51, which includes The first catalyst unit, the second catalyst unit, or a combination thereof of the exhaust gas recirculation path configuration. The system of claim 52, wherein the first or second catalyst unit is configured upstream, downstream, or integrated with the first or second heat recovery unit. A system of claim 53, comprising a first heat recovery unit having a first heat recovery steam generator. A system of claim 54 comprising a first steam turbine coupled to the first heat recovery steam generator. A system of claim 54, comprising a second heat recovery unit having a second heat recovery steam generator, a first steam turbine coupled to the first heat recovery steam generator, and a second heat coupled thereto A second steam turbine of the steam generator is recovered. A system of claim 1, comprising a dehumidification system and/or a degranulation system disposed along the exhaust gas recirculation path. The system of claim 57, wherein the dehumidification system comprises a heat exchanger, a condenser, a water gas separator, a first filter, or any combination thereof, wherein the degranulation system comprises an inertial separator, a gravity separator , a second filter, or any combination thereof. A system of claim 1, comprising a booster blower disposed along the exhaust gas recirculation path. A system according to claim 1, comprising a heat recovery unit, a booster blower, a dehumidifying unit, and a degranulation unit disposed along the exhaust gas recirculation path. The system of claim 1, wherein the first diffusion fuel nozzle comprises a first fuel passage and a first oxidant passage that are isolated from each other along the first diffusion fuel nozzle. The system of claim 61, wherein the first diffusion fuel nozzle comprises a first diluent passage. The system of claim 62, wherein the first diluent passage is configured to flow a portion of the exhaust gas through the first diffusion fuel nozzle. A system of claim 63, wherein the diluent channel is configured to flow a portion of the exhaust gas, steam, nitrogen, another inert gas, or a combination thereof through the first diffusion fuel nozzle. The system of claim 1, wherein the turbine combustor comprises a diluent injection system disposed downstream of the first diffusion fuel nozzle. The system of claim 65, wherein the diluent injection system is configured to inject a portion of exhaust gas, steam, nitrogen or another inert gas, or a combination thereof into a turbine combustor chamber downstream of the first diffusion fuel nozzle . The system of claim 66, wherein the diluent injection system comprises a plurality of cells in a liner of the turbine combustor, and the plurality of cells are configured to inject the portion of exhaust gas into the chamber of the turbine combustor . The system of claim 66, wherein the turbine combustor includes a first wall disposed about the chamber, a second wall disposed about the first wall, and disposed between the first and second walls Exhaust passage, wherein the diluent injection system includes a plurality of first and third through turbine burners A two-wall diluent injector. The system of claim 68, wherein the plurality of diluent injectors are configured to inject a portion of the exhaust, steam, nitrogen, or another inert gas into the chamber of the turbine combustor. A system as claimed in claim 1, comprising an exhaust gas extraction system configured to extract a portion of the exhaust gas. A system of claim 70, comprising an exhaust gas treatment system configured to treat the exhaust of the portion. A system of claim 71, wherein the exhaust gas treatment system comprises a gas separation system configured to separate a portion of the exhaust gas into a plurality of gas streams. The patentable scope of application of the system of 72, wherein the carbon dioxide-rich stream comprises a plurality of gas (CO ₂₎ and the first flow-lean carbon dioxide (CO ₂₎ of the second stream. A system of claim 73, wherein the exhaust treatment system comprises a gas compression system, a dehumidification system, a degranulation system, or a combination thereof configured to receive at least one of the first or second streams. The system of claim 72, wherein the exhaust gas treatment system comprises a gas purification system configured to purify at least one of the plurality of gas streams. A system of claim 72, comprising a target system configured to receive at least one of the plurality of streams, wherein the target system comprises a hydrocarbon generation system, an underground storage, a carbon storage system, a pipeline, a storage Slot, or any combination thereof. A system of claim 71, wherein the exhaust treatment system comprises a compression system configured to compress a portion of the exhaust. The system of claim 71, wherein the exhaust gas treatment system comprises a dehumidification system and/or a degranulation system. A system as claimed in claim 1 includes a control system that adjusts one or more operating parameters to control an equivalence ratio or emission level in the exhaust gas in response to sensor feedback. The system of claim 79, wherein the one or more operational parameters comprise an oxidant flow rate and/or a fuel flow rate to the turbine combustor. The system of claim 79, wherein the control system is configured to maintain the equivalence ratio between about 0.95 and 1.05. A system of claim 79, wherein the sensor feedback comprises gas composition feedback relating to oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons, or any combination thereof. The system of claim 79, wherein the control system is coupled to a plurality of sensors configured to obtain sensor feedback, and the plurality of sensors are combusted along the exhaust gas recirculation path, the turbine , turbine, exhaust compressor, or a combination thereof. A system of claim 1, comprising a bypass line from the exhaust gas compressor to the turbine, wherein the bypass line includes a heat exchanger configured to cool a bypass flow of exhaust gas from the exhaust gas compressor to the turbine. A system of claim 1, comprising a gas turbine engine having a turbine combustor, a turbine, and an exhaust gas compressor, wherein the combustion The gas turbine engine is a stoichiometric exhaust gas recirculation (SEGR) gas turbine engine. A system of claim 85, comprising an exhaust gas extraction system coupled to the gas turbine engine, an exhaust gas treatment system coupled to the exhaust gas extraction system, and a hydrocarbon production system coupled to the exhaust gas treatment system. A method comprising: injecting at least one oxidant and at least one fuel into a chamber of a turbine combustor, wherein the at least one oxidant and the at least one fuel are mixed and combusted to form a diffusion flame to produce a combustion product; the combustion product is used to drive the turbine and Exchanging exhaust gas; recirculating the exhaust gas along an exhaust gas recirculation path to an exhaust gas compressor; compressing and transmitting the exhaust gas to the turbine combustor; controlling the at least one oxidant and the at least one fuel to the turbine in a stoichiometric control mode Flow rate, wherein the stoichiometric control mode is configured to vary the flow rate and provide a substantially stoichiometric ratio of at least one fuel to at least one oxidant; and control the at least one oxidant in a non-stoichiometric control mode And a flow rate of the at least one fuel to the turbine combustor, wherein the non-stoichiometric control mode is configured to vary the flow rates and provide a non-stoichiometric ratio of the at least one fuel to the at least one oxidant. The method of claim 87, wherein the controlling of the stoichiometric control mode comprises providing the substantially stoichiometric ratio of an equivalent ratio of about 1.0. The method of claim 87, wherein the controlling of the stoichiometric control mode comprises providing the substantially stoichiometric ratio of an equivalence ratio between about 0.95 and about 1.05. The method of claim 87, wherein the controlling of the non-stoichiometric control mode comprises providing the non-stoichiometric ratio of an equivalence ratio of less than about 0.95 or greater than about 1.05. A method of claim 87, comprising changing the flow rate from the first set of flow rates to the second set of flow rates and converting between the stoichiometric control mode and the non-stoichiometric control mode. The method of claim 91, wherein the second set of flow rates is less than the first set of flow rates. The method of claim 91, wherein the second set of flow rates is greater than the first set of flow rates. The method of claim 87, wherein the controlling of the stoichiometric control mode comprises changing the flow rates from the first set of flow rates to the second set of flow rates while maintaining the substantially stoichiometric ratio. The system of claim 94, wherein the second set of flow rates is less than the first set of flow rates. The system of claim 94, wherein the second set of flow rates is greater than the first set of flow rates. The method of claim 94, wherein the controlling the stoichiometric control mode comprises respectively outputting the power of the turbine from the first set of flow rates to the second set of flow rates A power output is changed to a second power output. The method of claim 97, wherein the second set of flow rates is less than the first set of flow rates, and the second power output is less than the first power output. The method of claim 97, wherein the second set of flow rates is greater than the first set of flow rates, and the second power output is greater than the first power output. The method of claim 97, wherein the controlling the stoichiometric control mode comprises maintaining the discharge in the exhaust gas while maintaining the flow rate from the first flow rate to the second flow rate Multiple target emissions. The method of claim 100, wherein the emission comprises carbon monoxide, oxygen, nitrogen oxides, sulfur oxides, unburned hydrocarbons, hydrogen, or any combination thereof. The method of claim 100, wherein the one or more target emission ranges comprise a range of oxygen of less than about 50 parts per million (ppmv) and/or a range of carbon monoxide of less than about 5000 ppmv. The method of claim 100, wherein the one or more target emission ranges comprise an oxygen range of less than about 10 parts per million (ppmv) and/or a range of carbon monoxide of less than about 1000 ppmv. The method of claim 87, wherein the controlling of the stoichiometric control mode comprises gradually changing the flow rate in the plurality of sets of flow rates while maintaining the substantially stoichiometric ratio. The method of claim 104, wherein the plurality of sets of flow rates comprise at least three sets of flow rates. The method of claim 104, wherein the plurality of sets of flow rates comprise at least four sets of flow rates. The method of claim 104, wherein controlling the stoichiometric control mode comprises maintaining a substantial stoichiometric ratio, and at the same time: gradually reducing the flow rate in the plurality of sets of flow rates; gradually reducing the number of turbines One of the power outputs is output; and the exhaust is maintained in one or more of the target emissions. The method of claim 107, wherein the emission comprises carbon monoxide, oxygen, nitrogen oxides, sulfur oxides, unburned hydrocarbons, hydrogen, or any combination thereof. The method of claim 107, wherein the one or more target emission ranges comprise an oxygen range of less than about 50 parts per million (ppmv) and/or a range of carbon monoxide of less than about 5000 ppmv. The method of claim 107, wherein the one or more target emission ranges comprise an oxygen range of less than about 10 parts per million (ppmv) and/or a range of carbon monoxide of less than about 1000 ppmv. The method of claim 107, which comprises gradually reducing the flow rate, gradually reducing the power output, and maintaining the discharge. Thereafter, the stoichiometric control mode is switched to the non-stoichiometric control mode. The method of claim 111, wherein the controlling of the non-stoichiometric control mode comprises operating in a fuel rich control mode after switching from the stoichiometric control mode to the non-stoichiometric control mode. The method of claim 111, wherein the controlling of the non-stoichiometric control mode comprises operating in a lean fuel control mode after switching from the stoichiometric control mode to the non-stoichiometric control mode. The method of claim 111, wherein the controlling of the stoichiometric control mode comprises maintaining emissions in the exhaust gas within a target emission range of the first group, wherein the control of the non-stoichiometric control mode comprises exhausting The emissions are maintained within the target emissions range of the second group, wherein the target emission ranges of the first and second groups are different from each other. The method of claim 114, wherein the controlling of the non-stoichiometric control mode comprises operating in a lean fuel control mode having a target emission range of oxygen emissions of at least about 1000 parts per million (ppmv). The method of claim 114, wherein the controlling of the non-stoichiometric control mode comprises operating in a lean fuel control mode having a target emission range of carbon monoxide emissions of less than about 100 parts per million (ppmv). For example, the method of claim 114, in which Control of the stoichiometric control mode includes operating in a lean fuel control mode having a target emission range of carbon monoxide emissions of less than about 20 parts per million (ppmv). The method of claim 114, wherein the controlling of the non-stoichiometric control mode comprises operating in a lean fuel control mode having a target emission range of nitrogen oxide emissions of less than about 200 parts per million (ppmv) . The method of claim 114, wherein the controlling of the non-stoichiometric control mode comprises operating in a lean fuel control mode having a target emission having a nitrogen oxide emission range of less than about 100 parts per million (ppmv) . The method of claim 87, comprising controlling one or more operating parameters for: gradually changing a flow rate in the plurality of sets of flow rates; and gradually changing the plurality of turbines in response to changing the flow rate One of the power outputs; the emissions in the exhaust gas are maintained within one or more target emissions ranges before and after changing the flow rate; along the exhaust gas recirculation path before and after changing the flow rate The temperature of the exhaust gas is maintained within a target temperature range; and the pressure of the exhaust gas along the exhaust gas recirculation path is maintained within a target temperature range before and after the flow rate is changed. The method of claim 120, wherein controlling comprises flowing the temperature along the exhaust gas recirculation path downstream of the at least one catalyst unit The diameter remains within the target temperature range. The method of claim 120, wherein the controlling comprises adjusting the operating rate of the exhaust gas extraction valve, the exhaust gas discharge valve, the exhaust gas compressor or the oxidant compressor, the position of the exhaust gas compressor inlet baffle, the exhaust gas compressor recirculation The pressure is maintained by at least one of a valve, or any combination thereof. The method of claim 87, comprising independently controlling fluid flow through the first and second fluid supply circuits, wherein the turbine combustor includes a first set of fuel nozzles coupled to the first fluid supply circuit and is coupled to A second set of fuel nozzles of the second fluid supply circuit, wherein at least one of the first or second set of fuel nozzles comprises a first diffusion fuel nozzle configured to generate a diffusion flame. The method of claim 123, wherein the first set of fuel nozzles comprises a single fuel nozzle, and the second set of fuel nozzles comprises a plurality of fuel nozzles. The method of claim 123, wherein the first set of fuel nozzles comprises a first plurality of fuel nozzles, and the second set of fuel nozzles comprises a second plurality of fuel nozzles. The method of claim 123, comprising independently controlling fluid flow through the first fluid supply circuit, the second fluid supply circuit, and the third fluid supply circuit, wherein the turbine combustor comprises a connection to the third fluid supply The third group of fuel nozzles in the circuit. The method of claim 123, comprising independently changing the fluids at different rates through the first and second fluid supply circuits flow. The method of claim 123, comprising independently varying the fluid streams at the same rate through the first and second fluid supply circuits. The method of claim 123, wherein the first set of fuel nozzles comprises at least a first diffusion fuel nozzle, and the second set of fuel nozzles comprises a second diffusion fuel nozzle. The method of claim 123, wherein the first set of fuel nozzles comprises at least a first diffusion fuel nozzle, and the second set of fuel nozzles comprises a first premixed fuel nozzle. The method of claim 87, wherein the injecting comprises separately injecting the at least one oxidant and the at least one fuel from individual first and second passages that are isolated from each other along the first diffusion fuel nozzle. The method of claim 131, wherein the first and second channels are arranged in a concentric arrangement. The method of claim 131, wherein the first passage extends around the second passage. The method of claim 131, wherein the second channel extends around the first channel. A method of claim 87, comprising injecting at least one diluent into the chamber. The method of claim 135, wherein the at least one diluent comprises a portion of the offgas, steam, nitrogen, another inert gas, or a combination thereof. The method of claim 135, comprising separately injecting the at least one oxidant and the at least one fuel from the respective first and second channels isolated from each other along the first diffusion fuel nozzle, and transmitting through the first diffusion fuel nozzle Diluent flow. A method of claim 135, comprising the step of feeding a stream of diluent into a chamber downstream of the first diffusion fuel nozzle. A method of claim 138, comprising injecting a diluent stream through a plurality of channels in a liner of a turbine combustor, and wherein the diluent stream comprises a portion of the exhaust gas. The method of claim 138, comprising injecting a diluent stream through a plurality of diluent injectors through at least one wall of the turbine combustor, and the diluent stream comprising a portion of exhaust gas, steam, nitrogen, or another Inert gas. A method of claim 87, comprising treating the exhaust gas with the first catalyst unit along the exhaust gas recirculation path. The method of claim 141, wherein the treating comprises controlling the concentration levels of carbon monoxide, carbon dioxide, and unburned hydrocarbons in the exhaust. The method of claim 141, wherein the treating comprises driving the oxidation reaction with the exhaust gas and the oxidant fuel. A method of claim 143, which comprises controlling the flow of oxidant fuel to the first catalyst unit to control the oxidation reaction. The method of claim 144, comprising controlling the flow of the oxidant fuel in response to the sensor feedback, and the second sensor is opposite The feed contains gas composition feedback indicative of oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons, or any combination thereof. The method of claim 87, comprising recovering heat from the exhaust gas along the exhaust gas recirculation path using the first heat recovery unit, the second heat recovery unit, or a combination thereof. A method of claim 146, comprising the first catalyst unit for driving the first catalyst reaction within, upstream or downstream of the first or second heat recovery unit. The method of claim 147, wherein the second catalyst unit is used to drive the second catalyst reaction within, upstream or downstream of the first or second heat recovery unit. The method of claim 146, comprising: generating a first steam by a first heat recovery steam generator of the first heat recovery unit, generating a second steam by using a second heat recovery steam generator of the second heat recovery unit, Or a combination thereof. The method of claim 149, comprising driving the first steam turbine with the first steam or driving the second steam turbine with the second steam. A method of claim 87, comprising removing moisture from the exhaust gas with a dehumidification system disposed along the exhaust gas recirculation path. The method of claim 151, wherein the dehumidification system comprises a heat exchanger, a condenser, a water gas separator, a filter, or any combination thereof. For example, the method of claim 87 of the patent scope includes The degranulation system of the exhaust gas recirculation path configuration removes particles from the exhaust gas. The method of claim 153, wherein the degranulation system comprises an inertial separator, a gravity separator, a filter, or any combination thereof. A method of claim 87, comprising boosting the flow of exhaust gas with a booster blower disposed along the exhaust gas recirculation path. A method of claim 87, comprising a heat recovery unit, a booster blower, a dehumidifying unit, and a degranulation unit disposed along the exhaust gas recirculation path. A method of claim 87, which comprises extracting a portion of the exhaust gas with an exhaust gas extraction system. The method of claim 157, which comprises treating the portion of the exhaust with an exhaust gas treatment system. The method of claim 158, wherein treating the portion of the off-gas comprises separating the portion of the off-gas into a plurality of gas streams. The method of application of the 159 patents range, wherein the carbon dioxide-rich stream comprises a plurality of gas (CO ₂₎ and the first flow-lean carbon dioxide (CO ₂₎ of the second stream. The method of claim 160, wherein treating the portion of the exhaust gas comprises compressing the portion of the exhaust gas, the first stream, or the second vapor with a gas compression system. The method of claim 160, wherein treating the portion of the off-gas comprises removing moisture from the portion of the off-gas, the first stream, or the second vapor with a dehumidification system. The method of claim 160, wherein treating the portion of the off-gas comprises removing particles from the portion of the off-gas, the first stream, or the second vapor with a degranulation system. The method of claim 160, comprising the part of the exhaust gas, the first stream, or the second steam sending target system, wherein the target system comprises a hydrocarbon generating system, an underground storage, a carbon storage system, and a pipeline , storage tank, or any combination thereof. A method of claim 160, comprising adjusting one or more operating parameters to control an equivalence ratio or an emission level in the exhaust gas in response to sensor feedback. A method of claim 165, which comprises obtaining sensor feedback by monitoring a gas composition of an exhaust gas relating to oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons, or any combination thereof. The method of claim 166, wherein obtaining sensor feedback comprises monitoring a plurality of sensors along the exhaust gas recirculation path, a turbine combustor, a turbine, an exhaust gas compressor, or a combination thereof. A method of claim 87, comprising the bypass flow of the exhaust gas being sent from the exhaust compressor to the turbine along a bypass line. A method of claim 168, comprising a bypass stream that cools the exhaust gas along the bypass line, and a bypass flow using the exhaust gas to cool the turbine. A method of claim 87, comprising operating a gas turbine engine having a turbine combustor, a turbine, and the exhaust gas compressor to achieve substantial feedback based on sensor feedback during the stoichiometric control mode Stoichiometric combustion. A method of claim 170, comprising extracting a portion of the exhaust gas from an exhaust gas extraction system coupled to the gas turbine engine, and sending the portion of the exhaust gas to a hydrocarbon generation system, a carbon storage system, a pipeline, a storage tank , or any combination thereof. A method comprising: directing an oxidant to at least one oxidant compressor to produce a compressed oxidant stream; directing a recirculated low oxygen content gas stream to a compressor section of a gas turbine engine to produce a compressed low oxygen content gas stream; a first portion of the compressed oxidant flow rate and a first fuel flow rate fuel stream are directed to the at least one turbine combustor at a substantially stoichiometric ratio, and the compressed oxidant stream and the fuel stream are mixed at a point of combustion, and Combusing a mixture of the compressed oxidant stream and the fuel stream; directing a first portion of the compressed low oxygen content gas stream of the low oxygen content gas flow rate to the at least one turbine combustor and combining it with the compressed oxidant after the combustion point Mixing the combustion stream of the fuel and generating a high temperature, high pressure, low oxygen content stream; directing the high temperature, high pressure, low oxygen content stream to the expander section of the gas turbine engine, and expanding the high temperature, high pressure, low oxygen content stream to produce the first machine Power and a recycled low oxygen content gas stream having a first recycled low oxygen content gas flow rate, wherein the recycled low oxygen content gas stream A first gas effluent recirculated low oxygen content level; a first portion of a first mechanical power is used to drive the gas turbine engine Compressor section; using a second portion of the first mechanical power to drive at least one of: a generator, the at least one oxidant compressor, or at least one other mechanical device; the recycle loop will recirculate the low oxygen content gas Flow is recirculated from an outlet of the expander section to an inlet of a compressor section of the gas turbine engine; at least a second portion of the compressed low oxygen content gas stream is withdrawn from the gas turbine engine, and the compression of the at least second portion is low Delivering an oxygen content gas stream to the first at least one oxidation catalyst unit and generating a low oxygen content product stream comprising a first low oxygen content product effluent level within a target range; reducing the fuel flow rate to less than the first a second fuel flow rate of the fuel flow rate, and reducing the first portion of the compressed oxidant flow rate to a second compressed oxidant flow rate that is less than the first compressed oxidant flow rate, wherein the substantially stoichiometric ratio is maintained, Generating a second mechanical power that is less than the first mechanical power and producing a low oxygen content product stream having a second low oxygen content product effluent level within a target range Reducing the fuel flow rate to a third fuel flow rate that is less than the second fuel flow rate, and reducing the first portion of the compressed oxidant flow rate to a third compressed oxidant stream that is less than the second compressed oxidant flow rate a rate wherein the substantially stoichiometric ratio is maintained, a third mechanical power less than the second mechanical power is generated, and a low oxygen content product stream comprising a third low oxygen content product effluent level within a target range is produced; and the fuel is The flow rate is reduced to a fourth fuel flow rate that is less than the third fuel flow rate, and the first portion of the compressed oxidant flow rate is reduced to a fourth compressed oxidant flow rate that is less than the third compressed oxidant flow rate, wherein the substantially stoichiometric ratio is not maintained, and lean fuel combustion is achieved, a fourth mechanical power less than the third mechanical power is generated, and high oxygen is generated A high oxygen content product stream at the level of product effluent. The method of claim 172, wherein the first recycled low oxygen content gas discharge comprises at least one of oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons or similar products of incomplete combustion. . The method of claim 172, wherein the first, second, and third low oxygen content products emit oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons, or similar products incomplete combustion. At least one of them. The method of claim 172, wherein the high oxygen content product discharge comprises at least one of oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons or similar products of incomplete combustion. The method of claim 172, wherein the low oxygen content product emission level limit is at least one of 50 ppmv oxygen and 5000 ppmv carbon monoxide. The method of claim 172, wherein the low oxygen content product emission level limit is at least one of 10 ppmv oxygen and 1000 ppmv carbon monoxide. The method of claim 172, wherein the high oxygen content product effluent level comprises at least 1000 ppmv oxygen. Such as the method of claim 172, wherein the high oxygen The level product effluent level comprises less than 100 ppmv carbon monoxide. The method of claim 172, wherein the high oxygen content product effluent level comprises less than 20 ppmv carbon monoxide. The method of claim 172, wherein the high oxygen content product effluent level comprises less than 200 ppmv oxynitride. The method of claim 172, wherein the high oxygen content product effluent level comprises less than 100 ppmv oxynitride. The method of claim 172, comprising introducing a second portion of the compressed oxidant stream to the first at least one oxidation catalyst unit to oxidize at least a portion of the carbon monoxide contained in the second portion of the compressed low oxygen content stream At least one of hydrogen, unburned hydrocarbons or similar products that are not completely combusted. The method of claim 172, comprising introducing an oxidizing fuel to the first at least one oxidation catalyst unit, and reducing at least a portion of the residual oxygen contained in the compressed low oxygen content stream of the second portion. The method of claim 172, wherein the oxidant consists essentially of ambient air and a recycled low oxygen content gas stream comprising nitrogen. For example, the method of claim 172, wherein the equivalent ratio (phi, ) Is equal to (mol% of the fuel / oxidant mol%) _Actual / (fuel mol% / oxidant mol%) _{stoichiometry.} The method of claim 186, comprising controlling the flow of the first portion of the compressed oxidant stream and at least one of the fuel streams The rate is such that a combustion equivalent ratio of about 1 is achieved, and a substantially stoichiometric ratio of the first portion of the compressed oxidant stream to the fuel stream is produced. A method of claim 187, comprising a sensor mounted in the recirculation loop and measuring a component of the recycled low oxygen content stream. The method of claim 188, wherein the measured component is at least one of the group consisting of oxygen, carbon monoxide, hydrogen, nitrogen oxides, and unburned hydrocarbons. The method of claim 189, which comprises determining an equivalence ratio by analyzing component measurements. The method of claim 172, comprising at least one second selected and installed upstream of the first at least one oxidation catalyst unit, downstream of the first at least one oxidation catalyst unit, or both A sensor of a component of a partially compressed low oxygen content gas stream. The method of claim 191, wherein the measured component is at least one of the group consisting of oxygen, carbon monoxide, hydrogen, nitrogen oxides, and unburned hydrocarbons. The method of claim 192, comprising at least one of adjusting a combustion equivalent ratio, a flow rate of the second portion of the compressed oxidant stream, or a flow rate of the oxidizing fuel and achieving at least one oxidation in the first A controller of a desired level of at least one of the measured components downstream of the catalyst unit. The method of claim 172, wherein the first heat recovery unit is included downstream of the first at least one oxidation catalyst unit. The method of claim 194, wherein the first heat recovery unit comprises a steam generator. A method of claim 195, comprising generating, by a steam generator, steam delivered to at least one steam turbine, and driving at least one of a generator or another mechanical device that produces electrical power. A method of claim 172, comprising a second heat recovery unit in the recirculation loop between the outlet of the expander section and the inlet to the compressor section of the gas turbine engine, and recycling low oxygen content The gas stream removes heat. The method of claim 197, wherein the second heat recovery unit comprises a steam generator. A method of claim 198, comprising generating, by a steam generator, steam delivered to at least one steam turbine, and driving at least one of a generator or another mechanical device that produces electrical power. A method of claim 172, comprising delivering a third portion of the compressed low oxygen content gas stream from a compressor section of the gas turbine engine to a turbine as a secondary flow secondary flow path, and cooling and sealing The turbine then delivers a third portion of the compressed low oxygen content gas stream to the recirculation loop. The method of claim 197, wherein the recirculation loop includes a booster blower that increases the pressure of the recycled low oxygen content gas stream downstream of the second heat recovery unit. A method of claim 197, comprising a heat exchanger in a recirculation loop upstream of a compressor section of the gas turbine engine, The heat exchanger cools the recirculated low oxygen content gas stream prior to entering the inlet of the compressor section of the gas turbine engine. A method of claim 202, comprising condensing and removing water from the recycled low oxygen content gas stream using the heat exchanger. A method of claim 172, comprising delivering at least a portion of the low oxygen content product stream to an underground reservoir for enhanced hydrocarbon recovery. The method of claim 204, comprising compressing the at least one portion with at least one inert gas product compressor prior to delivering the at least a portion of the low oxygen content product stream to an underground reservoir for enhanced hydrocarbon recovery The low oxygen content product stream. A method of claim 204, comprising cooling the low oxygen content product stream by a first heat recovery unit. A method of claim 204, comprising delivering the at least a portion of the low oxygen content product stream to a gas dehydration unit. A method of claim 172, comprising delivering at least a portion of the low oxygen content product stream to a carbon dioxide separation unit to produce a carbon dioxide lean stream and a carbon dioxide rich stream. A method of claim 208, comprising delivering at least a portion of the carbon dioxide lean stream to an underground reservoir for enhanced hydrocarbon recovery. A method of claim 208, comprising delivering at least a portion of the carbon dioxide rich stream to an underground reservoir for enhanced hydrocarbon recovery. A method of claim 208, comprising delivering at least a portion of the carbon dioxide rich stream to a carbon sequestration unit. The method of claim 209, comprising compressing the at least a portion of the carbon dioxide lean stream to at least one lean product compression prior to delivering the at least a portion of the carbon dioxide lean stream to the subterranean reservoir for enhanced hydrocarbon recovery machine. The method of claim 210, comprising compressing the at least a portion of the carbon dioxide rich stream to at least one rich product prior to delivering the at least a portion of the carbon dioxide rich stream to an underground reservoir for enhanced hydrocarbon recovery. compressor. A method of claim 211, comprising compressing the at least a portion of the carbon dioxide rich stream to at least one rich product compressor prior to delivering the at least a portion of the carbon dioxide rich stream to the carbon sequestration unit. A method of claim 208, comprising delivering at least a portion of the carbon dioxide lean stream to a gas dehydration unit. A method of claim 208, comprising delivering at least a portion of the carbon dioxide rich stream to a gas dehydration unit. The method of claim 172, comprising introducing at least a portion of the low oxygen content product stream to an expander and expanding the at least a portion of the low oxygen content product stream, driving at least a generator or another mechanical device One and generate a discharge stream. The method of claim 208, comprising introducing at least a portion of the carbon dioxide lean stream to an expander and expanding the at least one portion The lean carbon dioxide stream divides at least one of the generator or another mechanical device and produces a discharge stream. The method of claim 172, comprising a second at least one oxidation catalyst unit located in the recycle loop, and oxidizing at least a portion of the carbon monoxide, hydrogen, or not contained in the recycled low oxygen content gas stream At least one of a burning hydrocarbon or a similar product that is not completely combusted. The method of claim 219, wherein the second at least one oxidation catalyst unit is located upstream of the second heat recovery unit. The method of claim 219, wherein the second at least one oxidation catalyst unit is located downstream of the second heat recovery unit. The method of claim 219, wherein the second at least one oxidation catalyst unit is located in the second heat recovery unit and is located at a suitable heat supply for providing an appropriate operating temperature and providing heat for reaction by the catalyst. The location of the device. A method of claim 172, which comprises controlling the flow rate of the compressed low oxygen content gas stream of the at least second portion. The method of claim 223, wherein the flow rate of the compressed low oxygen content gas stream of the at least second portion is adjusted to maintain the pressure at a location within the recirculation loop within a desired range. The method of claim 223, wherein the at least one of the extraction valve, the extraction discharge valve, the product compressor operating rate, the product compressor inlet baffle position, or the product compressor recirculation valve is adjusted The flow rate of the two-part compressed low oxygen content gas stream. The method of claim 172, wherein the at least one turbine combustor each comprises a plurality of combustors and at least two separately controlled loops, the loop supplying the fuel stream separately to the two individual combustors, one for individual combustion And at least one of a set of burners, two sets of burners, and combinations thereof. The method of claim 226, wherein the at least two separately controlled circuits, from the first fuel flow rate to the second fuel flow rate, the second fuel flow rate to the third fuel flow rate, and the third fuel The percentage reduction of the fuel flow rate of at least one of the flow rate to the fourth fuel flow rate is not equal. The method of claim 172, comprising: reducing a fuel flow rate to a fifth flow rate that is less than the first fuel flow rate, and reducing the first portion of the compressed oxidant flow rate to less than the a fifth compressed oxidant flow rate of the first compressed oxidant flow rate, wherein the substantially stoichiometric ratio is maintained, a fifth mechanical power less than the first mechanical power is generated, and a low oxygen content product stream is produced, which is included in the target range a fifth low oxygen content product effluent level and a first heat release from the second at least one oxidation catalyst unit, which results in a temperature of the recycled low oxygen content gas stream downstream of the second at least one oxidation catalyst unit at the target Within the range; reducing the fuel flow rate to a sixth fuel flow rate that is less than the fifth fuel flow rate, and reducing the first portion of the compressed oxidant flow rate to a sixth less than the fifth compressed oxidant flow rate Compressing the oxidant flow rate, wherein maintaining the substantially stoichiometric ratio produces a sixth mechanical power that is less than the fifth mechanical power and produces a low oxygen content product stream, which is included in the sixth The oxygen content a product effluent level and a second heat release from the second at least one oxidation catalyst unit, the temperature of the recycled low oxygen content gas stream downstream of the second at least one oxidation catalyst unit being within a target range; The flow rate is reduced to a seventh fuel flow rate that is less than the sixth fuel flow rate, and the first portion of the compressed oxidant flow rate is reduced to a seventh compressed oxidant flow rate that is less than the sixth compressed oxidant flow rate, Not maintaining the substantial stoichiometric ratio, and achieving lean fuel combustion, producing a seventh mechanical power less than the sixth mechanical power and producing a high oxygen content product comprising a high oxygen content product emission level and at least one from the second A third heat release of the oxidation catalyst unit results in a temperature of the recycled low oxygen content gas stream downstream of the second at least one oxidation catalyst unit being within a target range. The method of claim 172, comprising: reducing a fuel flow rate to an eighth flow rate that is less than the first fuel flow rate, and reducing the first portion of the compressed oxidant flow rate to less than the An eighth compressed oxidant flow rate of the first compressed oxidant flow rate, wherein the substantially stoichiometric ratio is maintained, producing an eighth mechanical power less than the first mechanical power and producing a low oxygen content product stream, which is included in the target range An eighth low oxygen content product effluent level and a fourth heat release from the first at least one oxidation catalyst unit, which results in a temperature of the low oxygen content product stream downstream of the first at least one oxidation catalyst unit being within a target range; Reducing the fuel flow rate to a ninth fuel flow rate that is less than the eighth fuel flow rate, and reducing the first portion of the compressed oxidant flow rate to a ninth compressed oxidant stream that is less than the eighth compressed oxidant flow rate Rate, wherein the substantial stoichiometric ratio is maintained, producing a ninth less than the eighth mechanical power Mechanically motivating and producing a low oxygen content product stream comprising a ninth low oxygen content product effluent level within the target range and a fifth heat release from the first at least one oxidation catalyst unit, which results in the first at least one oxidation a temperature of the low oxygen content product stream downstream of the catalyst unit is within a target range; a fuel flow rate is reduced to a tenth fuel stream flow rate less than the ninth fuel stream flow rate, and the first portion of the compressed oxidant is The flow rate is reduced to a tenth compressed oxidant flow rate that is less than the ninth compressed oxidant flow rate, wherein the substantially stoichiometric ratio is not maintained, and lean fuel combustion is achieved, producing a tenth mechanical power that is less than the ninth mechanical power and Generating a high oxygen content product stream comprising a high oxygen content product effluent level and a sixth heat release from the first at least one oxidation catalyst unit, which results in a high oxygen content product stream downstream of the first at least one oxidation catalyst unit The temperature is within the target range. The method of claim 172, comprising the first at least one nitrogen oxide reduction catalyst unit as part of the first at least one oxidation catalyst unit. The method of claim 219, comprising the second at least one nitrogen oxide reduction catalyst unit as part of the second at least one oxidation catalyst unit. The method of claim 203, comprising at least one of an inertial separator, a coalescing filter, and a watertight filter downstream of the heat exchanger, and improving the efficiency of removing the condensed water.