Operational Flexibility of GE’s F-Class Gas Turbines With the DLN2.6+ Combustion System

2018 ◽  
Author(s):  
William D. York ◽  
Derrick W. Simons ◽  
Yongqiang Fu
Keyword(s):  
Gas Turbine ◽  
Gas Turbines ◽  
Combined Cycle ◽  
Nox Emissions ◽  
Combustion System ◽  
Operational Flexibility ◽  
Start Up ◽  
Wide Range ◽  
Combined Cycle Plant ◽  
Base Load

F-class gas turbines comprise a major part of the heavy-duty gas turbine power generation fleet worldwide, despite increasing penetration of H/J class turbines. F-class gas turbines see a wide range of applications, including simple cycle peaking operation, base load combined cycle, demand following in simple or combined cycle, and cogeneration. Because of the different applications, local power market dynamics, and varied emissions regulations by region or jurisdiction, there is a need for operational flexibility of the gas turbine and the combustion system. In 2015, GE introduced a DLN2.6+ combustion system for new and existing 7F gas turbines. Approximately 50 are now in operation on 7F.04 and 7F.05 turbines, combining for nearly 150,000 fired hours. The system has been demonstrated to deliver 5 ppm NOx emissions @ 15% O2, and it exhibits a wide window of operation without significant thermoacoustic instabilities, owing the capability to premixed pilot flames on the main swirl fuel-air premixers, low system residence time, and air path improvements. Based on the success on the 7F, this combustion system is being applied to the 6F.03 in 2018. This paper highlights the flexibility of the 7F and 6F.03 DLN2.6+ combustion system and the enabling technology features. The advanced OpFlex* AutoTune control system tightly controls NOx emissions, adjusts fuel splits to stay clear of instabilities, and gives operators the ability to prioritize emissions or peak load output. Because of the low-NOx capability of the system, it is often being pushed to higher combustor exit temperatures, 35°C or more above the original target. The gas turbine is still meeting 9 or 15 ppm NOx emissions while delivering nearly 12% additional output in some cases. Single-can rig test and engine field test results show a relatively gentle NOx increase over the large range of combustor exit temperature because of the careful control of the premixed pilot fuel split. The four fuel legs are staged in several modes during startup and shutdown to provide robust operation with fast loading capability and low starting emissions, which are shown with engine data. The performance of a turndown-only fueling mode is highlighted with engine measurements of CO at low load. In this mode, the center premixer is not fueled, trading the NOx headroom for a CO emissions benefit that improves turndown. The combustion system has also demonstrated wide-Wobbe capability in emissions compliance. 7F.04 engine NOx and dynamics data are presented with the target heated gas fuel and also with cold fuel, producing a 24% increase in Modified Wobbe Index. The ability to run unheated fuel at base load may reduce the start-up time for a combined cycle plant. Lastly, there is a discussion of a new OpFlex* Variable Load Path digital solution in development that will allow operators to customize the start-up of a combined cycle plant.

Premixed Pilot Flames for Improved Emissions and Flexibility in a Heavy Duty Gas Turbine Combustion System

2015 ◽  
Author(s):  
William D. York ◽  
Bryan W. Romig ◽  
Michael J. Hughes ◽  
Derrick W. Simons ◽  
Joseph V. Citeno
Keyword(s):  
Gas Turbine ◽  
Gas Turbines ◽  
Hydrogen Gas ◽  
Operating Conditions ◽  
Nox Emissions ◽  
Combustion System ◽  
Heavy Duty ◽  
Low Load ◽  
Gas Turbine Combustion ◽  
Base Load

Operators of heavy duty gas turbines desire more flexibility of operation in compliance with increasingly stringent emissions regulations. Delivering low NOx at base load operation, while at the same time meeting aggressive startup, shutdown, and part load requirements for NOx, CO, and unburned hydrocarbons is a challenge that requires novel solutions in the framework of lean premixed combustion systems. The DLN2.6+ combustion system, first offered by the General Electric Company (GE) in 2005 on the 9F series gas turbines for the 50 Hz market, has a proven track record of low emissions, flexibility, and reliability. In 2010, GE launched a program to incorporate the DLN2.6+ into the 7F gas turbine model. The primary driver for the introduction of this combustion system into the 60 Hz market was to enable customers to capitalize on opportunities to use shale gas, which may have a greater Wobbe range and higher reactivity than traditional natural gas. The 7F version of the DLN2.6+ features premixed pilot flames on the five outer swirl-stabilized premixing fuel nozzles (“swozzles”). The premixed pilots have their roots in the multitube mixer technology developed by GE in the US Department of Energy Hydrogen Gas Turbine Program. A fraction of air is extracted prior to entering the combustor and sent to small tubes around the tip of the fuel nozzle centerbody. A dedicated pilot fuel circuit delivers the gas fuel to the pilot tubes, where it is injected into the air stream and given sufficient length to mix. Since the pilot flames are premixed, they contribute lower NOx emissions than a diffusion pilot, but can still provide enhanced main circuit flame stability at low-load conditions. The pilot equivalence ratio can be optimized for the specific operating conditions of the gas turbine. This paper presents the development and validation testing of the premixed pilots, which were tested on E-class and F-class gas turbine combustion system rigs at GE Power & Water’s Gas Turbine Technology Lab. A 25% reduction in NOx emissions at nominal firing temperature was demonstrated over a diffusion flame pilot, translating into more than 80% reduction in CO emissions if increased flame temperature is employed to hold constant NOx. On the new 7F DLN2.6+, the premixed pilots have enabled modifications to the system to reduce base load NOx emissions while maintaining similar gas turbine low-load performance and bringing a significant reduction in the combustor exit temperature at which LBO occurs, highlighting the stability the pilot system brings to the combustor without the NOx penalty of a diffusion pilot. The new combustion system is scheduled to enter commercial operation on GE 7F series gas turbines in 2015.

Development of a Dry Low NOx Combustor for a 120-MW Gas Turbine

1984 ◽  
Vol 106 (4) ◽  
pp. 795-800 ◽  
Author(s):  
K. Aoyama ◽  
S. Mandai
Keyword(s):  
Gas Turbine ◽  
Mechanical Characteristics ◽  
Steam Injection ◽  
Combined Cycle ◽  
Operating Conditions ◽  
Combustion System ◽  
Wide Range ◽  
Combined Cycle Plant ◽  
Combustion Tests ◽  
Full Pressure

Two stage premixed combustor with variable geometry has been developed to meet stringent NOx goals in Japan without the use of water or steam injection. This combustion system is planned to be applied for 120-MW gas turbine in 1090-MW LNG combined cycle plant. The full-pressure, full-scale combustion tests were conducted over a wide range of operating conditions for this gas turbine. The combustion tests proved that NOx levels as well as mechanical characteristics were well within the goals.

scholarly journals The Economics of Firing Heavy Fuels in Utility Gas Turbines

1997 ◽  
Author(s):  
R. Singh ◽  
M. S. Baker
Keyword(s):  
Gas Turbine ◽  
Gas Turbines ◽  
Developing Economies ◽  
Cost Savings ◽  
Combined Cycle ◽  
Fuel Oil ◽  
Heavy Fuel Oil ◽  
Combined Cycle Plant ◽  
Heavy Fuels ◽  
Base Load

Heavy fuel oil is of interest for firing in utility gas turbine and combined cycle plant, particularly in the developing economies of Asia and Latin America. There are few detailed studies published, which justify in commercial terms the use of heavy fuels in utility gas turbine plant or indicate the scenarios when this should be considered. Whilst this technology/fuel combination is mature and can be considered proven, awareness of the option and the technical and commercial implications is not widespread. This paper outlines the technical and commercial implications of firing heavy fuels in open cycle peaking and base load combined cycle plant. An economic comparison is made with the alternative fuel and technology options. It is demonstrated that firing heavy fuels in base load combined cycle plant can yield significant cost savings compared to using alternative technologies and liquid fuels, provided the emissions limits are not restrictive.

Performance Analysis of a Combined Cycle Power Plant Through Exergetic and Environmental Indices

2017 ◽  
Author(s):  
Edgar Vicente Torres González ◽  
Raúl Lugo Leyte ◽  
Martín Salazar Pereyra ◽  
Helen Denise Lugo Méndez ◽  
Miguel Toledo Velázquez ◽  
...  
Keyword(s):  
Power Plant ◽  
Gas Turbine ◽  
Gas Turbines ◽  
Combined Cycle ◽  
Environmental Indices ◽  
Combined Cycle Power Plant ◽  
Combustion Gases ◽  
Combined Cycle Plant ◽  
Exergetic Analysis ◽  
Gas Turbine Power Plant

In this paper is carried out a comparison between a gas turbine power plant and a combined cycle power plant through exergetic and environmental indices in order to determine performance and sustainability aspects of a gas turbine and combined cycle plant. First of all, an exergetic analysis of the gas turbine and the combined is carried out then the exergetic and environmental indices are calculated for the gas turbine (case A) and the combined cycle (case B). The exergetic indices are exergetic efficiency, waste exergy ratio, exergy destruction factor, recoverable exergy ratio, environmental effect factor and exergetic sustainability. Besides, the environmental indices are global warming, smog formation and acid rain indices. In the case A, the two gas turbines generate 278.4 MW; whereas 415.19 MW of electricity power is generated by the combined cycle (case B). The results show that exergetic sustainability index for cases A and B are 0.02888 and 0.1058 respectively. The steam turbine cycle improves the overall efficiency, as well as, the reviewed exergetic indexes. Besides, the environmental indices of the gas turbines (case A) are lower than the combined cycle environmental indices (case B), since the combustion gases are only generated in the combustion chamber.

Operation Experiences of Siemens IGCC Gas Turbines Using Gasification Products From Coal and Refinery Residues

2000 ◽  
Author(s):  
M. Huth ◽  
A. Heilos ◽  
G. Gaio ◽  
J. Karg
Keyword(s):  
Power Generation ◽  
Gas Turbine ◽  
Gas Turbines ◽  
Combined Cycle ◽  
Strong Impact ◽  
Coal Gas ◽  
Operation Conditions ◽  
Wide Range ◽  
Commercial Operation ◽  
Burner Design

The Integrated Gasification Combined Cycle concept is an emerging technology that enables an efficient and clean use of coal as well as residuals in power generation. After several years of development and demonstration operation, now the technology has reached the status for commercial operation. SIEMENS is engaged in 3 IGCC plants in Europe which are currently in operation. Each of these plants has specific characteristics leading to a wide range of experiences in development and operation of IGCC gas turbines fired with low to medium LHV syngases. The worlds first IGCC plant of commercial size at Buggenum/Netherlands (Demkolec) has already demonstrated that IGCC is a very efficient power generation technology for a great variety of coals and with a great potential for future commercial market penetration. The end of the demonstration period of the Buggenum IGCC plant and the start of its commercial operation has been dated on January 1, 1998. After optimisations during the demonstration period the gas turbine is running with good performance and high availability and has exceeded 18000 hours of operation on coal gas. The air-side fully integrated Buggenum plant, equipped with a Siemens V94.2 gas turbine, has been the first field test for the Siemens syngas combustion concept, which enables operation with very low NOx emission levels between 120–600 g/MWh NOx corresponding to 6–30 ppm(v) (15%O2) and less than 5 ppm(v) CO at baseload. During early commissioning the syngas nozzle has been recognised as the most important part with strong impact on combustion behaviour. Consequently the burner design has been adjusted to enable quick and easy changes of the important syngas nozzle. This design feature enables fast and efficient optimisations of the combustion performance and the possibility for easy adjustments to different syngases with a large variation in composition and LHV. During several test runs the gas turbine proved the required degree of flexibility and the capability to handle transient operation conditions during emergency cases. The fully air-side integrated IGCC plant at Puertollano/Spain (Elcogas), using the advanced Siemens V94.3 gas turbine (enhanced efficiency), is now running successfully on coal gas. The coal gas composition at this plant is similar to the Buggenum example. The emission performance is comparable to Buggenum with its very low emission levels. Currently the gas turbine is running for the requirements of final optimization runs of the gasifier unit. The third IGCC plant (ISAB) equipped with Siemens gas turbine technology is located at Priolo near Siracusa at Sicilly/Italy. Two Siemens V94.2K (modified compressor) gas turbines are part of this “air side non-integrated” IGCC plant. The feedstock of the gasification process is a refinery residue (asphalt). The LHV is almost twice compared to the Buggenum or Puertollano case. For operation with this gas, the coal gas burner design was adjusted and extensively tested. IGCC operation without air extraction has been made possible by modifying the compressor, giving enhanced surge margins. Commissioning on syngas for the first of the two gas turbines started in mid of August 1999 and was almost finished at the end of August 1999. The second machine followed at the end of October 1999. Since this both machines are released for operation on syngas up to baseload.

Advanced Gas Turbine and High Performance Gas-Steam Combined Cycle Plant With Blade Cooling Air Controlling

2006 ◽  
Author(s):  
Tadashi Tsuji
Keyword(s):  
Power Generation ◽  
Heat Exchanger ◽  
Gas Turbine ◽  
Thermal Efficiency ◽  
Gas Turbines ◽  
Combined Cycle ◽  
Hot Water ◽  
Blade Cooling ◽  
Combined Cycle Plant ◽  
Cooling Air

Air cooling blades are usually applied to gas turbines as a basic specification. This blade cooling air is almost 20% of compressor suction air and it means that a great deal of compression load is not converted effectively to turbine power generation. This paper proposes the CCM (Cascade Cooling Module) system of turbine blade air line and the consequent improvement of power generation, which is achieved by the reduction of cooling air consumption with effective use of recovered heat. With this technology, current gas turbines (TIT: turbine inlet temperature: 1350°C) can be up-rated to have a relative high efficiency increase. The increase ratio has a potential to be equivalent to that of 1500°C Class GT/CC against 1350°C Class. The CCM system is designed to enable the reduction of blade cooling air consumption by the low air temperature of 15°C instead of the usual 200–400°C. It causes the turbine operating air to increase at the constant suction air condition, which results in the enhancement of power and thermal efficiency. The CCM is installed in the cooling air line and is composed of three stage coolers: steam generator/fuel preheater stage, heat exchanger stage for hot water supplying and cooler stage with chilled water. The coolant (chilled water) for downstream cooler is produced by an absorption refrigerator operated by the hot water of the upstream heat exchanger. The proposed CCM system requires the modification of cooling air flow network in the gas turbine but produces the direct effect on performance enhancement. When the CCM system is applied to a 700MW Class CC (Combined Cycle) plant (GT TIT: 135°C Class), it is expected that there will be a 40–80MW increase in power and +2–5% relative increase in thermal efficiency.

NOx Emissions Reduction in an Innovative Industrial Gas Turbine Combustor (GE10 Machine): A Numerical Study of the Benefits of a New Pilot-System on Flame Structure and Emissions

2005 ◽  
Author(s):  
Antonio Andreini ◽  
Bruno Facchini ◽  
Luca Mangani ◽  
Antonio Asti ◽  
Gianni Ceccherini ◽  
...  
Keyword(s):  
Gas Turbine ◽  
Gas Turbines ◽  
Numerical Study ◽  
Flame Structure ◽  
Combustion Model ◽  
Emissions Reduction ◽  
Minimal Amount ◽  
Nox Emissions ◽  
Ambient Temperatures ◽  
Wide Range

One of the driving requirements in gas turbine design is emissions reduction. In the mature markets (especially the North America), permits to install new gas turbines are granted provided emissions meet more and more restrictive requirements, in a wide range of ambient temperatures and loads. To meet such requirements, design techniques have to take advantage also of the most recent CFD tools. As a successful example of this, this paper reports the results of a reactive 3D numerical study of a single-can combustor for the GE10 machine, recently updated by GE-Energy. This work aims to evaluate the benefits on the flame shape and on NOx emissions of a new pilot-system located on the upper part of the liner. The former GE10 combustor is equipped with fuel-injecting-holes realizing purely diffusive pilot-flames. To reduce NOx emissions from the current 25 ppmvd@15%O2 to less than 15 ppmvd@15%O2 (in the ambient temperature range from −28.9°C to +37.8°C and in the load range from 50% and 100%), the new version of the combustor is equipped with 4 swirler-burners realizing lean-premixed pilot flames; these flames in turn are stabilized by a minimal amount of lean-diffusive sub-pilot-fuel. The overall goal of this new configuration is the reduction of the fraction of fuel burnt in diffusive flames, lowering peak temperatures and therefore NOx emissions. To analyse the new flame structure and to check the emissions reduction, a reactive RANS study was performed using STAR-CD™ package. A user-defined combustion model was used, while to estimate NOx emissions a specific scheme was also developed. Three different ambient temperatures (ISO, −28.9°C and 37.8°C) were simulated. Results were then compared with experimental measurements (taken both from the engine and from the rig), resulting in reasonable agreement. Finally, an additional simulation with an advanced combustion model, based on the laminar flamelet approach, was performed. The model is based on the G-Equation scheme but was modified to study partially premixed flames. A geometric procedure to solve G-Equation was implemented as add-on in STAR-CD™.

Risk-Based Assessment of Unplanned Outage Events and Costs for Combined-Cycle-Plants

2012 ◽  
Author(s):  
Dale Grace ◽  
Thomas Christiansen
Keyword(s):  
Power Systems ◽  
Gas Turbine ◽  
Cash Flow ◽  
Gas Turbines ◽  
Operational Reliability ◽  
Combined Cycle ◽  
Maintenance Costs ◽  
Wide Range ◽  
Turbine Equipment ◽  
The Impact

Unexpected outages and maintenance costs reduce plant availability and can consume significant resources to restore the unit to service. Although companies may have the means to estimate cash flow requirements for scheduled maintenance and on-going operations, estimates for unplanned maintenance and its impact on revenue are more difficult to quantify, and a large fleet is needed for accurate assessment of its variability. This paper describes a study that surveyed 388 combined-cycle plants based on 164 D/E-class and 224 F-class gas turbines, for the time period of 1995 to 2009. Strategic Power Systems, Inc. (SPS®), manager of the Operational Reliability Analysis Program (ORAP®), identified the causes and durations of forced outages and unscheduled maintenance and established overall reliability and availability profiles for each class of plant in 3 five-year time periods. This study of over 3,000 unit-years of data from 50 Hz and 60 Hz combined-cycle plants provides insight into the types of events having the largest impact on unplanned outage time and cost, as well as the risks of lost revenue and unplanned maintenance costs which affect plant profitability. Outage events were assigned to one of three subsystems: the gas turbine equipment, heat recovery steam generator (HRSG) equipment, or steam turbine equipment, according to the Electric Power Research Institute’s Equipment Breakdown Structure (EBS). Costs to restore the unit to service for each main outage cause were estimated, as were net revenues lost due to unplanned outages. A statistical approach to estimated costs and lost revenues provides a risk-based means to quantify the impact of unplanned events on plant cash flow as a function of class of gas turbine, plant subsystem, and historical timeframe. This statistical estimate of the costs of unplanned outage events provides the risk-based assessment needed to define the range of probable costs of unplanned events. Results presented in this paper demonstrate that non-fuel operation and maintenance costs are increased by roughly 8% in a typical combined-cycle power plant due to unplanned maintenance events, but that a wide range of costs can occur in any single year.

System Evaluation and LBTU Fuel Combustion Studies for IGCC Power Generation

1995 ◽  
Vol 117 (4) ◽  
pp. 673-677 ◽  
Author(s):  
C. S. Cook ◽  
J. C. Corman ◽  
D. M. Todd
Keyword(s):  
Gas Turbine ◽  
Gas Turbines ◽  
Coal Gasification ◽  
Flame Temperature ◽  
Combined Cycle ◽  
Gas Turbine Combustor ◽  
Gas Cleaning ◽  
Wide Range ◽  
Cycle Systems ◽  
Combined Cycles

The integration of gas turbines and combined cycle systems with advances in coal gasification and gas stream cleanup systems will result in economically viable IGCC systems. Optimization of IGCC systems for both emission levels and cost of electricity is critical to achieving this goal. A technical issue is the ability to use a wide range of coal and petroleum-based fuel gases in conventional gas turbine combustor hardware. In order to characterize the acceptability of these syngases for gas turbines, combustion studies were conducted with simulated coal gases using full-scale advanced gas turbine (7F) combustor components. It was found that NOx emissions could be correlated as a simple function of stoichiometric flame temperature for a wide range of heating values while CO emissions were shown to depend primarily on the H2 content of the fuel below heating values of 130 Btu/scf (5125 kJ/NM3) and for H2/CO ratios less than unity. The test program further demonstrated the capability of advanced can-annular combustion systems to burn fuels from air-blown gasifiers with fuel lower heating values as low as 90 Btu/scf (3548 kJ/NM3) at 2300°F (1260°C) firing temperature. In support of ongoing economic studies, numerous IGCC system evaluations have been conducted incorporating a majority of the commercial or near-commercial coal gasification systems coupled with “F” series gas turbine combined cycles. Both oxygen and air-blown configurations have been studied, in some cases with high and low-temperature gas cleaning systems. It has been shown that system studies must start with the characteristics and limitations of the gas turbine if output and operating economics are to be optimized throughout the range of ambient operating temperature and load variation.

Study of a Rich/Lean Staged Combustion Concept for Hydrogen at Gas Turbine Relevant Conditions

2013 ◽  
Author(s):  
Felipe Bolaños ◽  
Dieter Winkler ◽  
Felipe Piringer ◽  
Timothy Griffin ◽  
Rolf Bombach ◽  
...  
Keyword(s):  
Heat Transfer ◽  
Gas Turbine ◽  
Gas Turbines ◽  
Carbon Capture ◽  
Flame Temperature ◽  
Nox Emissions ◽  
Hydrogen Fuel ◽  
Auto Ignition ◽  
Wide Range ◽  
The Rich

The combustion of hydrogen-rich fuels (> 80 % vol. H2), relevant for gas turbine cycles with “pre-combustion” carbon capture, creates great challenges in the application of standard lean premix combustion technology. The significant higher flame speed and drastically reduced auto-ignition delay time of hydrogen compared to those of natural gas, which is normally burned in gas turbines, increase the risk of higher NOX emissions and material damage due to flashback. Combustion concepts for gas turbines operating on hydrogen fuel need to be adapted to assure safe and low-emission combustion. A rich/lean (R/L) combustion concept with integrated heat transfer that addresses the challenges of hydrogen combustion has been investigated. A sub-scale, staged burner with full optical access has been designed and tested at gas turbine relevant conditions (flame temperature of 1750 K, preheat temperature of 400 °C and a pressure of 8 bar). Results of the burner tests have confirmed the capability of the rich/lean staged concept to reduce the NOx emissions for undiluted hydrogen fuel. The NOx emissions were reduced from 165 ppm measured without staging (fuel pre-conversion) to 23 ppm for an R/L design having a fuel-rich hydrogen pre-conversion of 50 % at a constant power of 8.7 kW. In the realized R/L concept the products of the first rich stage, which is ignited by a Pt/Pd catalyst (under a laminar flow, Re ≈ 1900) are combusted in a diffusion-flame-like lean stage (turbulent flow Re ≈ 18500) without any flashback risk. The optical accessibility of the reactor has allowed insight into the combustion processes of both stages. Applying OH-LIF and OH*-chemiluminescence optical techniques, it was shown that mainly homogeneous reactions at rich conditions take place in the first stage, questioning the importance of a catalyst in the system, and opening a wide range of optimization possibilities. The promising results obtained in this study suggest that such a rich/lean staged burner with integrated heat transfer could help to develop a new generation of gas turbine burners for safe and clean combustion of H2-rich fuels.

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